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, 20202022
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 1-2256
Exxon Mobil Corporation
(Exact name of registrant as specified in its charter)
| | | | | | | | |
| New Jersey | | 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 R ☑ 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, 2020,2022, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $44.72$85.64 on the New York Stock Exchange composite tape, was in excess of $189$356 billion.
| | | | | | | | |
| Class | | Outstanding as of January 31, 20212023 |
| Common stock, without par value | | 4,233,483,1604,070,984,988 |
Documents Incorporated by Reference: Proxy Statement for the 20212023 Annual Meeting of Shareholders (Part III)
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| EXXON MOBIL CORPORATION | |
| FORM 10-K | |
| FOR THE FISCAL YEAR ENDED DECEMBER 31, 20202022 | |
| | | |
| TABLE OF CONTENTS | |
| | | |
| PART I | |
| | | |
| Item 1. | Business | |
| Item 1A. | Risk Factors | |
| Item 1B. | Unresolved Staff Comments | |
| Item 2. | Properties | |
| Item 3. | Legal Proceedings | |
| Item 4. | Mine Safety Disclosures | |
| Information about our Executive Officers | |
| | |
| PART II | |
| | |
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | |
| | |
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | |
| Item 8. | Financial Statements and Supplementary Data | |
| Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | |
| Item 9A. | Controls and Procedures | |
| Item 9B. | Other Information | |
| Item 9C. | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | |
| | | |
| PART III | |
| | |
| Item 10. | Directors, Executive Officers and Corporate Governance | |
| Item 11. | Executive Compensation | |
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | |
| Item 13. | Certain Relationships and Related Transactions, and Director Independence | |
| Item 14. | Principal Accounting Fees and Services | |
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| PART IV | |
| | |
| Item 15. | Exhibits,Exhibit and Financial Statement Schedules | |
| Item 16. | Form 10-K Summary | |
| | |
| Financial Section | |
| Index to Exhibits | |
| Signatures | |
| Exhibits 31 and 32 — Certifications | |
PART I
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. TheirOur principal business involves exploration for, and production of, crude oil and natural gas andgas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals, and a wide variety of specialty products.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” and “Operating 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 nearly 9over 8 thousand active patents worldwide at the end of 2020.2022. For technology licensed to third parties, revenues totaled approximately $130$129 million in 2020.2022. 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.
SixtyOver 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 3135 percent of our U.S. hires for management, professional and technical positions were minorities. With over 160 nationalities represented in the Company,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 7262 thousand, 7563 thousand, and 7172 thousand at years ended 2020, 2019,2022, 2021, and 2018,2020, 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 nitrogen oxide, sulfur oxideair, water, and greenhouse gaswaste emissions, and expenditures for asset retirement obligations. Using definitions and guidelines established by the American Petroleum Institute, ExxonMobil’s 20202022 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $4.5$5.7 billion, of which $3.4$3.8 billion were included in expenses with the remainder in capital expenditures. The total cost for such activities isAs the Corporation progresses its emission-reduction plans, worldwide environmental expenditures are expected to increase to approximately $4.9$7.3 billion in 2021 and 2022. Capital2023, with capital expenditures are expected to account for approximately 2546 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’scompany’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.
ExxonMobil’s financial and operating results are subject to a variety of risks inherent in the global oil, gas, and petrochemical businesses.businesses, and the pursuit of lower-emission business opportunities. Many of these risk factors are not within the Company’scompany’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.commodity or product. Any material decline in oil or natural gas prices could have a material adverse effect on certain of the Company’scompany’s operations, financial condition, and proved reserves, especially in the Upstream segment, financial condition, and proved reserves.segment. On the other hand, a material increase in oil or natural gas prices could have a material adverse effect on certain of the Company’scompany’s operations, especially in the DownstreamEnergy Products, Chemical Products, and ChemicalSpecialty 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 creditrating, 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. Demand reduction due to the COVID-19 pandemic as well as accompanying conditions of oversupply have led to a significant decrease in commodity prices and margins. FutureOur future business results, including cash flows and financing needs, will also be affected by the extentrate of recovery from the COVID-19 pandemic, as well as the occurrence and durationseverity of these conditions andfuture outbreaks, the effectiveness of responsive actions that the Corporation and others take, including actions to reduce capital and operating expenses, and actions taken by governments and others, to address the COVID-19 pandemic including the ongoing development and distribution of COVID-19 vaccines, and the impact of the pandemicresulting effects on nationalregional and global economiesmarkets and markets.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 tendtends 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 OPEC production quotas established by OPEC or "OPEC+" and other agreements among sovereigns,sovereigns; government policies, including actions intended to reduce greenhouse gas emissions, that restrict oil and gas production or increase associated costs,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 offor 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 production or use of new or recycled plastics);
•actions by policy-makers, regulators, or other political actors to delay or deny necessary licenses and permits, restrict the availability of oil and gas leases or restrict the transportation of our products;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-denominateredenominate 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.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 changeChange and greenhouse gas restrictions.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 orincluding emissions from the production and use of oil and gas.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 for renewable energy.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 of or increase the cost for,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, theysuch policies could have the potential to 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 sources such as natural gas.alternatives. Current and pending greenhouse gas regulations or policies may also increase our compliance costs, such as for monitoring or sequestering emissions.
Alternative energy.Technology and lower-emission solutions. Many governments are providing tax advantagesAchieving societal ambitions to reduce greenhouse gas emissions and other subsidies to support transitioning to alternative energy sources or are mandating the use of specific fuels or technologies. Governments and others are also promoting research intoultimately achieve net zero will require new technologies to reduce the cost and increase the scalability of alternative energy sources. We are conducting our own research both in-house and by working with more than 80 leading universities around the world, including the Massachusetts Institute of Technology, Princeton University, The University of Texas, and Stanford University in the U.S., and in Singapore with Nanyang Technological Institute and the National University. Our research projects focus on developing advanced biofuels and hydrogen,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 technologiestechnologies. 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 collaboration with our partners including Synthetic Genomics, FuelCell Energy and Global Thermostat.advanced lower-emission energy technologies. Our future results mayand 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 ourthese 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” below.in this Item 1A.
Operational and Other FactorsUNITED STATES
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.SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Exploration and development program.FORM 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.10-K
Project and portfolio management.☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2022
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from The long-term successto
Commission File Number 1-2256
Exxon Mobil Corporation
(Exact name of ExxonMobil’s Upstream, Downstream, and Chemical businesses depends on complex, long-term, capital intensive projects. These projectsregistrant as specified in turn require a high degreeits charter)
| | | | | | | | |
| New Jersey | | 13-5409005 |
(State or other jurisdiction of
incorporation or organization) | | (I.R.S. Employer
Identification Number) |
5959 Las Colinas Boulevard,Irving,Texas75039-2298
(Address 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,principal executive offices) (Zip Code)
(972)940-6000
(Registrant’s telephone number, 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 startup 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 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.area code)
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 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 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 our management systems and controls do not function as intended.
Securities registered pursuant to Section 12(b) of the Act:Cybersecurity. ExxonMobil | | | | | | | | | | | | | | |
| 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 regularlya 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 attempted cybersecurity disruptions from a variety of threat actors including state-sponsored actors. ExxonMobil’s defensive preparedness includes multi-layered technological capabilitiessuch filing requirements 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 provepast 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be insufficientsubmitted 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 our proprietary data is otherwisethe registrant has elected not protected, ExxonMobil as well as our customers, employees,to use the extended transition period for complying with any new or third parties could be adversely affected. Cybersecurity disruptions could cause physical harmrevised financial accounting standards provided pursuant to people orSection 13(a) of 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 costsExchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to remedy the effectsits management's assessment 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 abilityits internal control over financial reporting under Section 404(b) of the Corporation to insure against manySarbanes-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 risks it faces as described in this Item 1A is limited by the capacityAct). Yes ☐ No ☑
The aggregate market value of the applicable insurance markets, which may not be sufficient.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 |
Competition.Documents Incorporated by Reference: As noted in Item 1 above,Proxy Statement for 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 outside2023 Annual Meeting 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.
Reputation.Shareholders (Part III) Our reputation is an important corporate asset. An operating incident, significant cybersecurity disruption, change in consumer views concerning our products, or other adverse event such as those described in this Item 1A may have a negative impact on our reputation, which in turn could make it more difficult for us to compete successfully for new opportunities, obtain necessary regulatory approvals, obtain financing, 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.
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 2020
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. Primarily as a result of very low prices during 2020 and the effects of reductions in capital expenditures, under the SEC definition of proved reserves, certain quantities of crude oil, bitumen, and natural gas that qualified as proved reserves in prior years did not qualify as proved reserves at year-end 2020. Otherwise, no major discovery or other favorable or adverse event has occurred since December 31, 2020, 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 | 1,029 | | | 444 | | | — | | | — | | | 10,375 | | | 3,202 | |
Canada/Other Americas (1) | 288 | | | 5 | | | 76 | | | 311 | | | 472 | | | 759 | |
| Europe | 11 | | | 2 | | | — | | | — | | | 399 | | | 79 | |
| Africa | 314 | | | 31 | | | — | | | — | | | 318 | | | 398 | |
| Asia | 2,215 | | | 84 | | | — | | | — | | | 3,323 | | | 2,853 | |
| Australia/Oceania | 44 | | | 23 | | | — | | | — | | | 3,344 | | | 624 | |
| Total Consolidated | 3,901 | | | 589 | | | 76 | | | 311 | | | 18,231 | | | 7,915 | |
| | | | | | | | | | | |
| Equity Companies | | | | | | | | | | | |
| United States | 107 | | | 4 | | | — | | | — | | | 83 | | | 125 | |
| Europe | 8 | | | — | | | — | | | — | | | 293 | | | 57 | |
| Africa | — | | | — | | | — | | | — | | | — | | | — | |
| Asia | 432 | | | 214 | | | — | | | — | | | 8,992 | | | 2,144 | |
| Total Equity Company | 547 | | | 218 | | | — | | | — | | | 9,368 | | | 2,326 | |
| Total Developed | 4,448 | | | 807 | | | 76 | | | 311 | | | 27,599 | | | 10,241 | |
| | | | | | | | | | | |
| Undeveloped | | | | | | | | | | | |
| Consolidated Subsidiaries | | | | | | | | | | | |
| United States | 930 | | | 412 | | | — | | | — | | | 3,064 | | | 1,853 | |
Canada/Other Americas (1) | 209 | | | — | | | 5 | | | 133 | | | 89 | | | 362 | |
| Europe | 11 | | | 5 | | | — | | | — | | | 42 | | | 23 | |
| Africa | 42 | | | — | | | — | | | — | | | 2 | | | 42 | |
| Asia | 935 | | | 40 | | | — | | | — | | | 986 | | | 1,139 | |
| Australia/Oceania | 30 | | | 8 | | | — | | | — | | | 2,790 | | | 503 | |
| Total Consolidated | 2,157 | | | 465 | | | 5 | | | 133 | | | 6,973 | | | 3,922 | |
| | | | | | | | | | | |
| Equity Companies | | | | | | | | | | | |
| United States | 24 | | | — | | | — | | | — | | | 19 | | | 27 | |
| Europe | 1 | | | — | | | — | | | — | | | 67 | | | 12 | |
| Africa | 6 | | | — | | | — | | | — | | | 917 | | | 159 | |
| Asia | 393 | | | 59 | | | — | | | — | | | 2,385 | | | 850 | |
| Total Equity Company | 424 | | | 59 | | | — | | | — | | | 3,388 | | | 1,048 | |
| Total Undeveloped | 2,581 | | | 524 | | | 5 | | | 133 | | | 10,361 | | | 4,970 | |
| Total Proved Reserves | 7,029 | | | 1,331 | | | 81 | | | 444 | | | 37,960 | | | 15,211 | |
(1)Other Americas includes proved developed reserves of 119 million barrels of crude oil and 138 billion cubic feet of natural gas, as well as proved undeveloped reserves of 179 million barrels of crude oil and 77 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.
During the first and second quarters of 2020, the balance of supply and demand for petroleum and petrochemical products experienced two significant disruptive effects. On the demand side, the COVID-19 pandemic spread rapidly through most areas of the world resulting in substantial reductions in consumer and business activity and significantly reduced demand for crude oil, natural gas, and petroleum products. This reduction in demand coincided with announcements of increased production in certain key oil-producing countries which led to increases in inventory levels and sharp declines in prices for crude oil, natural gas, and petroleum products. Market conditions continued to reflect considerable uncertainty throughout 2020.
As noted above, certain quantities of crude oil, bitumen, and natural gas that qualified as proved reserves in prior years did not qualify as proved reserves at year-end 2020. Amounts no longer qualifying as proved reserves include 3.1 billion barrels of bitumen at Kearl, 0.6 billion barrels of bitumen at Cold Lake, and 0.5 billion oil-equivalent barrels in the United States. The Corporation's near-term reduction in capital expenditures resulted in a net reduction to estimates of proved reserves of approximately 1.5 billion oil-equivalent barrels, mainly related to unconventional drilling in the United States. Among the factors that could result in portions of these amounts being recognized again as proved reserves at some point in the future are a recovery in the SEC price basis, cost reductions, operating efficiencies, and increases in planned capital spending.
B. Technologies Used in Establishing Proved Reserves Additions in 2020
Additions to ExxonMobil’s proved reserves in 2020 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 proprietary seismic processing software, proprietary reservoir modeling and simulation software, and commercially available 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. | | | | | | | | |
| EXXON MOBIL CORPORATION | |
| FORM 10-K | |
| FOR THE FISCAL YEAR ENDED DECEMBER 31, 2022 | |
| | |
| TABLE OF CONTENTS | |
| | |
| PART I |
| | |
| Item 1. | Business | |
| Item 1A. | Risk Factors | |
| Item 1B. | Unresolved Staff Comments | |
| Item 2. | Properties | |
| Item 3. | Legal Proceedings | |
| Item 4. | Mine Safety Disclosures | |
| Information about our Executive Officers | |
| | |
| PART II |
| | |
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | |
| | |
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | |
| Item 8. | Financial Statements and Supplementary Data | |
| Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | |
| Item 9A. | Controls and Procedures | |
| Item 9B. | Other Information | |
| Item 9C. | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | |
| | |
| PART III |
| | |
| Item 10. | Directors, Executive Officers and Corporate Governance | |
| Item 11. | Executive Compensation | |
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | |
| Item 13. | Certain Relationships and Related Transactions, and Director Independence | |
| Item 14. | Principal Accounting Fees and Services | |
| | |
| PART IV |
| | |
| Item 15. | Exhibit and Financial Statement Schedules | |
| Item 16. | Form 10-K Summary | |
| | |
| Financial Section | |
| Index to Exhibits | |
| Signatures | |
| Exhibits 31 and 32 — Certifications | |
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 currently serves 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 2020, approximately 5.0 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped. This represents 33 percent of the 15.2 GOEB reported in proved reserves. This compares to the 7.7 GOEB of proved undeveloped reserves reported at the end of 2019. During the year, ExxonMobil conducted development activities that resulted in the transfer of approximately 0.9 GOEB from proved undeveloped to proved developed reserves by year end. The largest transfers were related to development activities in the United States, Qatar, the United Arab Emirates, and Guyana. During 2020, extensions, primarily in the United States and Canada, resulted in an addition of approximately 0.5 GOEB of proved undeveloped reserves. Also, as a result of very low prices during 2020 and the effects of reductions in capital expenditures, the Corporation reclassified approximately 2.3 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 $10.7 billion were made by the Corporation during 2020 to progress the development of reported proved undeveloped reserves, including $10.4 billion for oil and gas producing activities, along with additional investments for other non-oil and gas producing activities such as the construction of support infrastructure and other related facilities. These investments represented 74 percent of the $14.4 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| | (thousands of barrels daily) |
| Crude oil and natural gas liquids production | Crude Oil | | NGL | | Crude Oil | | NGL | | Crude Oil | | NGL |
| Consolidated Subsidiaries | | | | | | | | | | | |
| United States | 481 | | | 154 | | | 461 | | | 131 | | | 395 | | | 101 | |
Canada/Other Americas (1) | 121 | | | 5 | | | 87 | | | 4 | | | 62 | | | 6 | |
| Europe | 22 | | | 5 | | | 84 | | | 21 | | | 101 | | | 27 | |
| Africa | 301 | | | 11 | | | 360 | | | 12 | | | 377 | | | 10 | |
| Asia | 449 | | | 23 | | | 432 | | | 22 | | | 398 | | | 25 | |
| Australia/Oceania | 29 | | | 15 | | | 30 | | | 15 | | | 31 | | | 16 | |
| Total Consolidated Subsidiaries | 1,403 | | | 213 | | | 1,454 | | | 205 | | | 1,364 | | | 185 | |
| | | | | | | | | | | |
| Equity Companies | | | | | | | | | | | |
| United States | 49 | | | 1 | | | 52 | | | 2 | | | 54 | | | 1 | |
| Europe | 3 | | | — | | | 3 | | | — | | | 4 | | | — | |
| Asia | 208 | | | 62 | | | 232 | | | 62 | | | 226 | | | 62 | |
| Total Equity Companies | 260 | | | 63 | | | 287 | | | 64 | | | 284 | | | 63 | |
| | | | | | | | | | | |
| Total crude oil and natural gas liquids production | 1,663 | | | 276 | | | 1,741 | | | 269 | | | 1,648 | | | 248 | |
| | | | | | | | | | | |
| Bitumen production | | | | | | | | | | | |
| Consolidated Subsidiaries | | | | | | | | | | | |
| Canada/Other Americas | 342 | | | | | 311 | | | | | 310 | | | |
| | | | | | | | | | | |
| Synthetic oil production | | | | | | | | | | | |
| Consolidated Subsidiaries | | | | | | | | | | | |
| Canada/Other Americas | 68 | | | | | 65 | | | | | 60 | | | |
| | | | | | | | | | | |
| Total liquids production | 2,349 | | | | | 2,386 | | | | | 2,266 | | | |
| | | | | | | | | | | |
| | (millions of cubic feet daily) | | |
| Natural gas production available for sale | | | | | | | | | | | |
| Consolidated Subsidiaries | | | | | | | | | | | |
| United States | 2,668 | | | | | 2,756 | | | | | 2,550 | | | |
Canada/Other Americas (1) | 277 | | | | | 258 | | | | | 227 | | | |
| Europe | 447 | | | | | 808 | | | | | 925 | | | |
| Africa | 9 | | | | | 7 | | | | | 13 | | | |
| Asia | 872 | | | | | 851 | | | | | 838 | | | |
| Australia/Oceania | 1,219 | | | | | 1,319 | | | | | 1,325 | | | |
| Total Consolidated Subsidiaries | 5,492 | | | | | 5,999 | | | | | 5,878 | | | |
| | | | | | | | | | | |
| Equity Companies | | | | | | | | | | | |
| United States | 23 | | | | | 22 | | | | | 24 | | | |
| Europe | 342 | | | | | 649 | | | | | 728 | | | |
| Asia | 2,614 | | | | | 2,724 | | | | | 2,775 | | | |
| Total Equity Companies | 2,979 | | | | | 3,395 | | | | | 3,527 | | | |
| Total natural gas production available for sale | 8,471 | | | | | 9,394 | | | | | 9,405 | | | |
| | | | | | | | | | | |
| | (thousands of oil-equivalent barrels daily) | | |
| Oil-equivalent production | 3,761 | | | | | 3,952 | | | | | 3,833 | | | |
(1)Other Americas includes crude oil production for 2020, 2019 and 2018 of 29 thousand, 2 thousand, and 2 thousand barrels daily, respectively; and natural gas production available for sale for 2020, 2019 and 2018 of 45 million, 36 million, and 28 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 2020 | (dollars per unit) |
| 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 | 27.39 | | | — | | | 30.74 | | | — | | | 1.63 | | | — | | | 5.49 | |
| | | | | | | | | | | | | |
| 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 | 10.66 | | | 18.40 | | | 24.76 | | | 16.73 | | | 3.91 | | | 5.35 | | | 10.24 | |
| Average production costs, per barrel - bitumen | — | | | 19.22 | | | — | | | — | | | — | | | — | | | 19.22 | |
| Average production costs, per barrel - synthetic oil | — | | | 33.61 | | | — | | | — | | | — | | | — | | | 33.61 | |
| | | | | | | | | | | | | |
| During 2019 | |
| 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 | 28.17 | | | — | | | 14.04 | | | — | | | 2.03 | | | — | | | 5.16 | |
| | | | | | | | | | | | | |
| 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 | 13.08 | | | 23.41 | | | 13.80 | | | 17.56 | | | 4.39 | | | 6.60 | | | 11.51 | |
| Average production costs, per barrel - bitumen | — | | | 24.18 | | | — | | | — | | | — | | | — | | | 24.18 | |
| Average production costs, per barrel - synthetic oil | — | | | 40.38 | | | — | | | — | | | — | | | — | | | 40.38 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total |
| During 2018 | (dollars per unit) |
| Consolidated Subsidiaries | | | | | | | | | | | | | |
| Average production prices | | | | | | | | | | | | | |
| Crude oil, per barrel | 59.84 | | | 64.53 | | | 69.80 | | | 70.84 | | | 69.86 | | | 66.89 | | | 66.91 | |
| NGL, per barrel | 30.78 | | | 37.27 | | | 38.53 | | | 47.10 | | | 26.30 | | | 36.34 | | | 32.88 | |
| Natural gas, per thousand cubic feet | 2.14 | | | 1.68 | | | 6.97 | | | 1.96 | | | 2.33 | | | 6.39 | | | 3.87 | |
| Bitumen, per barrel | — | | | 28.66 | | | — | | | — | | | — | | | — | | | 28.66 | |
| Synthetic oil, per barrel | — | | | 54.85 | | | — | | | — | | | — | | | — | | | 54.85 | |
| Average production costs, per oil-equivalent barrel - total | 11.64 | | | 24.32 | | | 13.07 | | | 17.28 | | | 7.31 | | | 6.94 | | | 13.34 | |
| Average production costs, per barrel - bitumen | — | | | 22.93 | | | — | | | — | | | — | | | — | | | 22.93 | |
| Average production costs, per barrel - synthetic oil | — | | | 45.33 | | | — | | | — | | | — | | | — | | | 45.33 | |
| | | | | | | | | | | | | |
| Equity Companies | | | | | | | | | | | | | |
| Average production prices | | | | | | | | | | | | | |
| Crude oil, per barrel | 66.30 | | | — | | | 63.92 | | | — | | | 67.31 | | | — | | | 67.07 | |
| NGL, per barrel | 27.16 | | | — | | | — | | | — | | | 45.10 | | | — | | | 44.64 | |
| Natural gas, per thousand cubic feet | 2.19 | | | — | | | 5.03 | | | — | | | 6.31 | | | — | | | 6.01 | |
| Average production costs, per oil-equivalent barrel - total | 24.71 | | | — | | | 16.30 | | | — | | | 1.49 | | | — | | | 4.96 | |
| | | | | | | | | | | | | |
| Total | | | | | | | | | | | | | |
| Average production prices | | | | | | | | | | | | | |
| Crude oil, per barrel | 60.61 | | | 64.53 | | | 69.57 | | | 70.84 | | | 68.92 | | | 66.89 | | | 66.93 | |
| NGL, per barrel | 30.72 | | | 37.27 | | | 38.53 | | | 47.10 | | | 39.69 | | | 36.34 | | | 35.85 | |
| Natural gas, per thousand cubic feet | 2.14 | | | 1.68 | | | 6.11 | | | 1.96 | | | 5.38 | | | 6.39 | | | 4.67 | |
| Bitumen, per barrel | — | | | 28.66 | | | — | | | — | | | — | | | — | | | 28.66 | |
| Synthetic oil, per barrel | — | | | 54.85 | | | — | | | — | | | — | | | — | | | 54.85 | |
| Average production costs, per oil-equivalent barrel - total | 12.43 | | | 24.32 | | | 14.06 | | | 17.31 | | | 3.98 | | | 6.94 | | | 11.29 | |
| Average production costs, per barrel - bitumen | — | | | 22.93 | | | — | | | — | | | — | | | — | | | 22.93 | |
| Average production costs, per barrel - synthetic oil | — | | | 45.33 | | | — | | | — | | | — | | | — | | | 45.33 | |
Average
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 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; manufacture, trade, transport and sale of crude oil, natural gas, liquids (NGL) productionpetroleum 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 for this computationas abbreviated references to specific affiliates or groups of affiliates. The precise meaning depends on the context in question.
The energy and petrochemical industries are shownhighly 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 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 tableis 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 duereport.
ExxonMobil has a long-standing commitment to volumes consumedthe 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 flared. Natural gasconcession.
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 convertedmarket 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 an oil-equivalent basisidentify 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 six million cubic feet per one thousand barrels.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.
4. Drilling and Other Exploratory and Development Activities
A. Number of Net Productive and Dry Wells Drilled
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| Net Productive Exploratory Wells Drilled | | | | | |
| Consolidated Subsidiaries | | | | | |
| United States | 4 | | | 3 | | | 1 | |
| Canada/Other Americas | 2 | | | 6 | | | 4 | |
| Europe | — | | | 1 | | | — | |
| Africa | 1 | | | — | | | 1 | |
| Asia | — | | | — | | | — | |
| Australia/Oceania | — | | | 1 | | | 1 | |
| Total Consolidated Subsidiaries | 7 | | | 11 | | | 7 | |
| | | | | |
| Equity Companies | | | | | |
| United States | — | | | — | | | — | |
| Europe | — | | | — | | | — | |
| Africa | — | | | — | | | — | |
| Asia | — | | | — | | | — | |
| Total Equity Companies | — | | | — | | | — | |
| Total productive exploratory wells drilled | 7 | | | 11 | | | 7 | |
| | | | | |
| Net Dry Exploratory Wells Drilled | | | | | |
| Consolidated Subsidiaries | | | | | |
| United States | — | | | — | | | 3 | |
| Canada/Other Americas | 1 | | | 1 | | | — | |
| Europe | — | | | 1 | | | 1 | |
| Africa | — | | | — | | | — | |
| Asia | 1 | | | — | | | — | |
| Australia/Oceania | — | | | 1 | | | 2 | |
| Total Consolidated Subsidiaries | 2 | | | 3 | | | 6 | |
| | | | | |
| Equity Companies | | | | | |
| United States | — | | | — | | | — | |
| Europe | — | | | — | | | — | |
| Africa | — | | | — | | | — | |
| Asia | — | | | — | | | — | |
| Total Equity Companies | — | | | — | | | — | |
| Total dry exploratory wells drilled | 2 | | | 3 | | | 6 | |
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| Net Productive Development Wells Drilled | | | | | |
| Consolidated Subsidiaries | | | | | |
| United States | 412 | | | 618 | | | 389 | |
| Canada/Other Americas | 36 | | | 49 | | | 32 | |
| Europe | 2 | | | 3 | | | 3 | |
| Africa | 2 | | | 4 | | | 1 | |
| Asia | 15 | | | 12 | | | 14 | |
| Australia/Oceania | 4 | | | — | | | — | |
| Total Consolidated Subsidiaries | 471 | | | 686 | | | 439 | |
| | | | | |
| Equity Companies | | | | | |
| United States | 60 | | | 199 | | | 168 | |
| Europe | 1 | | | — | | | 3 | |
| Africa | — | | | — | | | — | |
| Asia | 5 | | | 9 | | | 6 | |
| Total Equity Companies | 66 | | | 208 | | | 177 | |
| Total productive development wells drilled | 537 | | | 894 | | | 616 | |
| | | | | |
| Net Dry Development Wells Drilled | | | | | |
| Consolidated Subsidiaries | | | | | |
| United States | 6 | | | 8 | | | 4 | |
| Canada/Other Americas | — | | | — | | | 1 | |
| Europe | — | | | — | | | — | |
| Africa | — | | | 1 | | | 1 | |
| Asia | — | | | — | | | — | |
| Australia/Oceania | 1 | | | — | | | — | |
| Total Consolidated Subsidiaries | 7 | | | 9 | | | 6 | |
| | | | | |
| Equity Companies | | | | | |
| United States | — | | | — | | | — | |
| Europe | — | | | — | | | — | |
| Africa | — | | | — | | | — | |
| Asia | — | | | — | | | — | |
| Total Equity Companies | — | | | — | | | — | |
| Total dry development wells drilled | 7 | | | 9 | | | 6 | |
| | | | | |
| Total number of net wells drilled | 553 | | | 917 | | | 635 | |
B. ExploratoryInformation concerning the source and Development Activities Regarding Oil and Gas Resources Extracted by Mining Technologies
Syncrude Operations. Syncrude is a joint venture established to recover shallow depositsavailability 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 interestraw materials used in the joint venture. Exxon Mobil Corporation hasCorporation’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 69.6 percent interest in Imperial Oil Limited. In 2020,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 shareCorporate Governance Guidelines, Code of net productionEthics and Business Conduct, and additional policies as well as the charters of synthetic crude oil was about 68 thousand barrels per daythe audit, compensation, and shareother committees of net acreage was about 55 thousand acresthe 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.
ExxonMobil’s financial and operating results are subject to a variety of risks inherent in the Athabascaglobal oil, sands deposit.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:
Kearl Operations. Kearl isSupply 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 joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extractmaterial adverse effect on the crude bitumen. Imperial Oil Limited holds a 70.96 percent interestcompany’s operations, financial condition, and proved reserves, especially in the joint venture and ExxonMobil Canada Properties holdsUpstream segment. On the other 29.04 percent. Exxon Mobil Corporation hashand, a 69.6 percent interestmaterial increase in Imperial Oil Limited andoil or natural gas prices could have a 100 percent interest in ExxonMobil Canada Properties. Kearl is comprised of six oil sands leases covering about 49 thousand acresmaterial adverse effect on the company’s operations, especially in the Athabasca oil sands deposit.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.
KearlEconomic conditions. The demand for energy and petrochemicals is located approximately 40 miles northgenerally linked closely with broad-based economic activities and levels of Fort McMurray, Alberta, Canada. Bitumen is extracted from oil sandsprosperity. 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 processed through bitumen extractionresponses, or currency exchange rate fluctuations, can also impact the demand for energy and froth treatment trains. The product, a blendpetrochemicals. Sovereign debt downgrades, defaults, inability to access debt markets due to rating, banking, or legal constraints, liquidity crises, the breakup or restructuring of bitumenfiscal, monetary, or political systems such as the European Union, and diluent, is shippedother events or conditions that impair the functioning of financial markets and institutions also pose risks to ExxonMobil, including risks to the safety of our refineriesfinancial assets and to other third parties. Diluent is natural gas condensate or other light hydrocarbons addedthe 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 crude bitumen to facilitate transportationrate of recovery from the COVID-19 pandemic, as well as the occurrence and severity of future outbreaks, the responsive actions taken by pipelinegovernments and rail. During 2020, average net production at Kearl was about 219 thousand barrels per day.
Primarily as a result of very low prices during 2020, under the SEC definition of proved reserves, the entire 3.1 billion barrels of bitumen at Kearl did not qualify as proved reserves at year-end 2020. Among the factors that could result in portions of these amounts being recognized again as proved reserves at some point in the future are a recovery in the SEC price basis, cost reductions, and/or operating efficiencies.
5. Present Activities
A. Wells Drilling
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year-End 2020 | | Year-End 2019 |
| | Gross | | Net | | Gross | | Net |
| Wells Drilling | | | | | | | |
| Consolidated Subsidiaries | | | | | | | |
| United States | 1,206 | | | 741 | | | 1,133 | | | 704 | |
| Canada/Other Americas | 38 | | | 29 | | | 27 | | | 20 | |
| Europe | 13 | | | 6 | | | 16 | | | 7 | |
| Africa | 14 | | | 3 | | | 4 | | | 1 | |
| Asia | 14 | | | 4 | | | 46 | | | 14 | |
| Australia/Oceania | — | | | — | | | 14 | | | 4 | |
| Total Consolidated Subsidiaries | 1,285 | | | 783 | | | 1,240 | | | 750 | |
| | | | | | | |
| Equity Companies | | | | | | | |
| United States | 3 | | | 1 | | | 3 | | | 1 | |
| Europe | 1 | | | 1 | | | — | | | — | |
| Africa | 6 | | | 1 | | | 6 | | | 1 | |
| Asia | 2 | | | 1 | | | 11 | | | 3 | |
| Total Equity Companies | 12 | | | 4 | | | 20 | | | 5 | |
| Total gross and net wells drilling | 1,297 | | | 787 | | | 1,260 | | | 755 | |
B. Review of Principal Ongoing Activities
UNITED STATES
ExxonMobil’s year-end 2020 acreage holdings totaled 11.2 million net acres, of which 0.4 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, 478.9 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 2020 was 0.3 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 2.7 net development wells completed.
CANADA / OTHER AMERICAS
Canada
Oil and Gas Operations: ExxonMobil’s year-end 2020 acreage holdings totaled 7.4 million net acres, of which 4.6 million net acres were offshore. A total of 6.1 net exploration and development wells were completed during the year.
In Situ Bitumen Operations: ExxonMobil’s year-end 2020 in situ bitumen acreage holdings totaled 0.6 million net onshore acres. A total of 28 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 2020. During the year, a total of 1.8 net development wells were completed.
Guyana
ExxonMobil’s net acreage totaled 4.6 million offshore acres at year-end 2020. During the year, 2.4 net exploration and development wells were completed. Development activities continued on the Liza Phase 2 project,others, and the Payara project was funded in 2020.
EUROPE
Germany
ExxonMobil’s net acreage totaled 1.7 million onshore acres at year-end 2020. During the year, 0.8 net explorationresulting effects on regional and development wells were completed.
Netherlands
ExxonMobil’s net interest in licenses totaled approximately 1.4 million acres, of which 1.0 million acres were onshore at year-end 2020. During the year, a total of 1.3 net explorationglobal markets and development wells were completed. In 2020, the Dutch Government further reduced Groningen gas extraction and maintained its plan to terminate Groningen production in 2022.
United Kingdom
ExxonMobil’s net interest in licenses totaled approximately 0.3 million offshore acres at year-end 2020. During the year, a total of 1.9 net development wells were completed. Development activities continued on the Penguins Redevelopment project.
AFRICAOther 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.
AngolaOther 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 net acreage totaled approximately 3.0 million acres,results can be adversely affected by political or regulatory developments affecting our operations.
Access limitations. A number of which 2.9 million net acres were offshore at year-end 2020. Duringcountries 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 year,extent governments view such measures as a total of 0.3 net development wells were completed. In 2020, ExxonMobil acquired approximately 2.7 million net acres in three offshore blocks locatedviable approach for pursuing national and global energy and climate policies. Restrictions on foreign investment in the Namibe basin.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.
ChadRestrictions 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.
ExxonMobil’s net acreage holdings totaled 46 thousand onshore acres at year-end 2020.
Equatorial Guinea
ExxonMobil’s net acreage totaled 0.5 million offshore acres at year-end 2020. DuringLack 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 year, a totaladequacy of 0.8 net development well was completed.
Mozambique
ExxonMobil’s net acreage totaled approximately 1.8 million offshore acres at year-end 2020. Development activities continuedthis remedy may still depend on the Coral South Floating LNG project during the year.local legal system to enforce an award.
NigeriaRegulatory 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:
ExxonMobil’s net acreage totaled 0.9 million•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 acres at year-end 2020. During the year, a total of 1.8 net exploration and development wells were completed.
ASIA
Azerbaijan
ExxonMobil's net acreage totaled 7 thousand offshore acres at year-end 2020. 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 2020.
Iraq
ExxonMobil’s net acreage totaled 0.1 million onshore acres at year-end 2020. During the year, a total of 8.2 net development wells were completed at the West Qurna Phase I oil field. Oil field rehabilitation activities continued during 2020 and across the life of this project will include drilling operations, water use, emissions, hydraulic fracturing, or production or use of new wells, working overor recycled plastics);
•actions by policy-makers, regulators, or other actors to delay or deny necessary licenses and permits, restrict the availability of existing wells,oil and optimization, debottleneckinggas 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 expansion of facilities. In
•government actions to cancel contracts, redenominate the Kurdistan Region of Iraq, ExxonMobil has continued exploration activities.
Kazakhstan
ExxonMobil’s net acreage totaled 0.3 million acres, of which 0.2 million net acres were offshore at year-end 2020. During the year, a total of 4.5 net development wells were completed. Development activities continuedofficial currency, renounce or default on the Tengiz Expansion project.
Malaysia
ExxonMobil’s interests in production sharing contracts covered 0.2 million net acres offshore at year-end 2020. During the year, a total of 2.0 net development wells were completed. In 2020, ExxonMobil relinquished approximately 2.3 million net acres in three Sabah offshore blocks.
Qatar
Through our joint ventures with Qatar Petroleum, ExxonMobil’s net acreage totaled 65 thousand acres offshore at year-end 2020. 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 0.3 net development well was completed. The Barzan project started up in 2020.obligations, renegotiate terms unilaterally, or expropriate assets.
RussiaLegal remedies available to compensate us for expropriation or other takings may be inadequate.
ExxonMobil’s net acreage holdingsWe also may be adversely affected by the outcome of litigation, especially in Sakhalin totaled 85 thousand offshore acres at year-end 2020. Duringcountries such as the year, a totalUnited 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 2.7 net exploration and development wells were completed.
Thailand
ExxonMobil’s net onshore acreage in Thailand concessions totaled 16 thousand acres at year-end 2020. Duringhydrocarbon products through litigation targeting the year, a totalcompany or other industry participants), gain political notoriety, or obtain monetary awards from the company. The adoption of 0.5 net exploration and development wells were completed.
United Arab Emirates
ExxonMobil’s net acreagesimilar legal practices in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acresEuropean 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 year-end 2020. Duringour 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 year,Energy Transition
Net-zero scenarios. Driven by concern over the risks of climate change, a totalnumber of 1.7 net development wells were completed. The Upper Zakum 750 project started up in 2020 while commissioning continued oncountries have adopted, or are considering the final systems. Development activities continued onadoption of, regulatory frameworks to reduce greenhouse gas emissions including emissions from the Upper Zakum 1 MBD project.
AUSTRALIA / OCEANIA
Australia
ExxonMobil’s net acreage totaled 1.8 million acres offshore and 10 thousand acres onshore at year-end 2020. During the year, a total of 3.8 net development wells were completed. Development activities continued on the West Barracouta project during the year.
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 during the year.
Papua New Guinea
ExxonMobil’s net acreage totaled 5.5 million acres, of which 3.3 million net acres were offshore at year-end 2020. During the year, a total of 0.8 net exploration and development wells were completed. In 2020, ExxonMobil relinquished approximately 1.4 million net onshore 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 2020, 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 29.8 million net acres were held at year-end 2020 and 0.7 net exploration 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 31 million barrelsuse of oil and 2,600 billion cubic feetgas and their products. These actions are being taken both independently by national and regional governments and within the framework of natural gasUnited 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 periodenergy 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 2021 through 2023. We expecthigh-intensity industrial activities, can assist in meeting society’s objective to fulfillmitigate atmospheric greenhouse gas levels while also helping ensure the majorityavailability 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 delivery commitmentstechnologies 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 production fromleading universities and with commercial partners involved in advanced lower-emission energy technologies. Our future results and ability to grow our proved developed reserves. Any remaining commitmentsLCS business, help nations meet their emission-reduction goals, and succeed through the energy transition will be fulfilled with production from our proved undeveloped reserves and purchasesdepend in part on the open market as necessary.
7. Oilsuccess of these research and Gas Properties, Wells, Operationscollaboration efforts and Acreage
A. Grosson our ability to adapt and Net Productive Wells
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year-End 2020 | | Year-End 2019 |
| | Oil | | Gas | | Oil | | Gas |
| | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Gross and Net Productive Wells | | | | | | | | | | | | | | | |
| Consolidated Subsidiaries | | | | | | | | | | | | | | | |
| United States | 19,631 | | | 7,878 | | | 20,480 | | | 12,195 | | | 20,559 | | | 8,502 | | | 21,893 | | | 13,182 | |
| Canada/Other Americas | 4,754 | | | 4,644 | | | 3,276 | | | 1,275 | | | 4,905 | | | 4,724 | | | 3,441 | | | 1,347 | |
| Europe | 559 | | | 126 | | | 487 | | | 221 | | | 741 | | | 207 | | | 517 | | | 236 | |
| Africa | 1,141 | | | 432 | | | 26 | | | 10 | | | 1,191 | | | 456 | | | 13 | | | 5 | |
| Asia | 974 | | | 310 | | | 132 | | | 78 | | | 943 | | | 301 | | | 133 | | | 79 | |
| Australia/Oceania | 540 | | | 102 | | | 90 | | | 38 | | | 582 | | | 120 | | | 87 | | | 36 | |
| Total Consolidated Subsidiaries | 27,599 | | | 13,492 | | | 24,491 | | | 13,817 | | | 28,921 | | | 14,310 | | | 26,084 | | | 14,885 | |
| | | | | | | | | | | | | | | |
| Equity Companies | | | | | | | | | | | | | | | |
| United States | 12,368 | | | 4,851 | | | 4,223 | | | 417 | | | 12,947 | | | 5,328 | | | 4,500 | | | 577 | |
| Europe | 57 | | | 20 | | | 552 | | | 172 | | | 57 | | | 20 | | | 561 | | | 175 | |
| Asia | 217 | | | 54 | | | 157 | | | 32 | | | 194 | | | 49 | | | 126 | | | 30 | |
| Total Equity Companies | 12,642 | | | 4,925 | | | 4,932 | | | 621 | | | 13,198 | | | 5,397 | | | 5,187 | | | 782 | |
| Total gross and net productive wells | 40,241 | | | 18,417 | | | 29,423 | | | 14,438 | | | 42,119 | | | 19,707 | | | 31,271 | | | 15,667 | |
There were 25,595 gross and 22,239 net operated wells at year-end 2020 and 27,532 gross and 23,857 net operated wells at year-end 2019. The numberapply the strengths of wells with multiple completions was 1,067 grossour current business model to providing the energy products of the future in 2020 and 1,023 gross in 2019.
B. GrossPolicy and Net Developed Acreage
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year-End 2020 | | Year-End 2019 |
| | Gross | | Net | | Gross | | Net |
| | (thousands of acres) |
| Gross and Net Developed Acreage | | | | | | | |
| Consolidated Subsidiaries | | | | | | | |
| United States | 12,834 | | | 7,971 | | | 13,283 | | | 8,097 | |
Canada/Other Americas (1) | 2,944 | | | 2,071 | | | 3,020 | | | 2,100 | |
| Europe | 2,231 | | | 1,189 | | | 2,229 | | | 1,182 | |
| Africa | 2,409 | | | 818 | | | 2,409 | | | 832 | |
| Asia | 1,938 | | | 561 | | | 1,938 | | | 561 | |
| Australia/Oceania | 3,262 | | | 1,068 | | | 3,262 | | | 1,068 | |
| Total Consolidated Subsidiaries | 25,618 | | | 13,678 | | | 26,141 | | | 13,840 | |
| | | | | | | |
| Equity Companies | | | | | | | |
| United States | 928 | | | 208 | | | 926 | | | 207 | |
| Europe | 3,667 | | | 1,118 | | | 4,069 | | | 1,280 | |
| Asia | 701 | | | 160 | | | 628 | | | 155 | |
| Total Equity Companies | 5,296 | | | 1,486 | | | 5,623 | | | 1,642 | |
| Total gross and net developed acreage | 30,914 | | | 15,164 | | | 31,764 | | | 15,482 | |
(1)market development.Includes developed acreage in Other Americas of 490 gross and 311 net thousands of acres for 2020 and 472 gross and 295 net thousands of acres for 2019.
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 2020 | | Year-End 2019 |
| | Gross | | Net | | Gross | | Net |
| | (thousands of acres) |
| Gross and Net Undeveloped Acreage | | | | | | | |
| Consolidated Subsidiaries | | | | | | | |
| United States | 6,969 | | | 2,967 | | | 7,123 | | | 3,146 | |
Canada/Other Americas (1) | 37,833 | | | 18,985 | | | 36,509 | | | 17,950 | |
| Europe | 14,802 | | | 6,018 | | | 18,212 | | | 7,619 | |
| Africa | 35,956 | | | 24,558 | | | 56,049 | | | 32,449 | |
| Asia | 888 | | | 280 | | | 6,880 | | | 2,911 | |
| Australia/Oceania | 12,971 | | | 6,265 | | | 14,773 | | | 7,689 | |
| Total Consolidated Subsidiaries | 109,419 | | | 59,073 | | | 139,546 | | | 71,764 | |
| | | | | | | |
| Equity Companies | | | | | | | |
| United States | 160 | | | 64 | | | 189 | | | 73 | |
| Europe | 765 | | | 214 | | | 366 | | | 105 | |
| Africa | 596 | | | 149 | | | 596 | | | 149 | |
| Asia | — | | | — | | | 73 | | | 5 | |
| Total Equity Companies | 1,521 | | | 427 | | | 1,224 | | | 332 | |
| Total gross and net undeveloped acreage | 110,940 | | | 59,500 | | | 140,770 | | | 72,096 | |
(1)Includes undeveloped acreage in Other Americas of 26,084 gross and 12,471 net thousands of acres for 2020 and 25,327 gross and 12,065 net thousands of acres for 2019.
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 advancescale of the contractual expiration date ifworld’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 evaluation process is completeglobal economy. Our ability to develop and theredeploy 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 business basis for extension. In cases where additional time may be required to fully evaluate acreage,guarantee that those policies will continue in the Corporation has generally been successfulfuture. See also the discussion of “Supply and Demand,” “Government and Political Factors,” and “Operational and Other Factors” 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
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM10-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
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 1-2256
Exxon Mobil Corporation
(Exact name of registrant as specified in its charter)
| | | | | | | | |
| New Jersey | | 13-5409005 |
(State or other jurisdiction of
incorporation or organization) | | (I.R.S. Employer
Identification Number) |
5959 Las Colinas Boulevard,Irving,Texas75039-2298
(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 | |
| Item 1A. | Risk Factors | |
| Item 1B. | Unresolved Staff Comments | |
| Item 2. | Properties | |
| Item 3. | Legal Proceedings | |
| Item 4. | Mine Safety Disclosures | |
| Information about our Executive Officers | |
| | |
| PART II |
| | |
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | |
| | |
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | |
| Item 8. | Financial Statements and Supplementary Data | |
| Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | |
| Item 9A. | Controls and Procedures | |
| Item 9B. | Other Information | |
| Item 9C. | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | |
| | |
| PART III |
| | |
| Item 10. | Directors, Executive Officers and Corporate Governance | |
| Item 11. | Executive Compensation | |
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | |
| Item 13. | Certain Relationships and Related Transactions, and Director Independence | |
| Item 14. | Principal Accounting Fees and Services | |
| | |
| PART IV |
| | |
| Item 15. | Exhibit and Financial Statement Schedules | |
| Item 16. | Form 10-K Summary | |
| | |
| Financial Section | |
| Index to Exhibits | |
| Signatures | |
| Exhibits 31 and 32 — Certifications | |
PART I
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.
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.
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
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
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.
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.
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.
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
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.
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
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gross and Net Productive Wells | Year-End 2022 | | Year-End 2021 |
| Oil | Gas | | Oil | Gas |
| Gross | | Net | Gross | | Net | | Gross | | Net | Gross | | Net |
| Consolidated Subsidiaries | | | | | | | | | | | | | |
| United States | 19,006 | | | 7,576 | | 11,495 | | | 7,516 | | | 19,401 | | | 7,566 | | 18,670 | | | 10,773 | |
| Canada/Other Americas | 4,394 | | | 4,310 | | 2,903 | | | 1,033 | | | 4,656 | | | 4,548 | | 3,209 | | | 1,247 | |
| Europe | 536 | | | 127 | | 433 | | | 205 | | | 439 | | | 116 | | 441 | | | 207 | |
| Africa | 590 | | | 191 | | 24 | | | 10 | | | 1,102 | | | 416 | | 24 | | | 10 | |
| Asia | 999 | | | 318 | | 147 | | | 86 | | | 1,038 | | | 333 | | 137 | | | 80 | |
| Australia/Oceania | 473 | | | 89 | | 92 | | | 38 | | | 522 | | | 99 | | 94 | | | 40 | |
| Total Consolidated Subsidiaries | 25,998 | | | 12,611 | | 15,094 | | | 8,888 | | | 27,158 | | | 13,078 | | 22,575 | | | 12,357 | |
| | | | | | | | | | | | | |
| Equity Companies | | | | | | | | | | | | | |
| United States | 12,068 | | | 4,777 | | 3,341 | | | 331 | | | 12,108 | | | 4,793 | | 3,355 | | | 333 | |
| Europe | 57 | | | 20 | | 482 | | | 150 | | | 57 | | | 20 | | 547 | | | 171 | |
| Africa | — | | | — | | 6 | | | 2 | | | — | | | — | | — | | | — | |
| Asia | 233 | | | 58 | | 145 | | | 33 | | | 225 | | | 56 | | 168 | | | 35 | |
| Total Equity Companies | 12,358 | | | 4,855 | | 3,974 | | | 516 | | | 12,390 | | | 4,869 | | 4,070 | | | 539 | |
| Total gross and net productive wells | 38,356 | | | 17,466 | | 19,068 | | | 9,404 | | | 39,548 | | | 17,947 | | 26,645 | | | 12,896 | |
There were 19,571 gross and 17,165 net operated wells at year-end 2022 and 23,645 gross and 20,528 net operated wells at year-end 2021. The number of wells with multiple completions was 1,010 gross in 2022 and 1,082 gross in 2021.
B. Gross and Net Developed Acreage
| | | | | | | | | | | | | | | | | | | | | | | |
Gross and Net Developed Acreage (thousands of acres) | Year-End 2022 | | Year-End 2021 |
| Gross | | Net | | Gross | | Net |
| | | | | | | |
| Consolidated Subsidiaries | | | | | | | |
| United States | 11,022 | | | 6,681 | | | 12,180 | | | 7,503 | |
Canada/Other Americas (1) | 2,113 | | | 1,509 | | | 2,905 | | | 2,075 | |
Europe (2) | 1,238 | | | 580 | | | 1,234 | | | 580 | |
| Africa | 2,186 | | | 736 | | | 2,409 | | | 818 | |
| Asia | 1,582 | | | 462 | | | 1,929 | | | 557 | |
| Australia/Oceania | 3,242 | | | 1,067 | | | 3,242 | | | 1,067 | |
| Total Consolidated Subsidiaries | 21,383 | | | 11,035 | | | 23,899 | | | 12,600 | |
| | | | | | | |
| Equity Companies | | | | | | | |
| United States | 702 | | | 166 | | | 687 | | | 163 | |
| Europe | 3,646 | | | 1,117 | | | 3,646 | | | 1,116 | |
| Africa | 178 | | | 44 | | | — | | | — | |
| Asia | 665 | | | 157 | | | 701 | | | 160 | |
| Total Equity Companies | 5,191 | | | 1,484 | | | 5,034 | | | 1,439 | |
| Total gross and net developed acreage | 26,574 | | | 12,519 | | | 28,933 | | | 14,039 | |
| | | | | | | |
(1) Includes developed acreage in Other Americas of 490 gross and 311 net thousands of acres for 2022 and 2021. (2) Year-end 2021 developed acreage in Europe was restated for gross and net. |
Separate acreage data for oil and gas are not maintained because, in many instances, both are produced from the same acreage.
C. Gross and Net Undeveloped Acreage
| | | | | | | | | | | | | | | | | | | | | | | |
Gross and Net Undeveloped Acreage (thousands of acres) | Year-End 2022 | | Year-End 2021 |
| Gross | | Net | | Gross | | Net |
| | | | | | | |
| Consolidated Subsidiaries | | | | | | | |
| United States | 6,455 | | | 2,587 | | | 6,751 | | | 2,807 | |
Canada/Other Americas (1) | 32,441 | | | 15,838 | | | 36,764 | | | 18,246 | |
Europe (2) | 12,592 | | | 8,231 | | | 14,811 | | | 6,163 | |
| Africa | 20,620 | | | 13,113 | | | 23,797 | | | 15,186 | |
| Asia | 766 | | | 227 | | | 766 | | | 227 | |
| Australia/Oceania | 4,811 | | | 2,309 | | | 8,638 | | | 4,112 | |
| Total Consolidated Subsidiaries | 77,685 | | | 42,305 | | | 91,527 | | | 46,741 | |
| | | | | | | |
| Equity Companies | | | | | | | |
| United States | 150 | | | 61 | | | 159 | | | 64 | |
| Europe | 482 | | | 131 | | | 596 | | | 139 | |
| Africa | 418 | | | 104 | | | 596 | | | 149 | |
| Asia | 296 | | | 19 | | | — | | | — | |
| Total Equity Companies | 1,346 | | | 315 | | | 1,351 | | | 352 | |
| Total gross and net undeveloped acreage | 79,031 | | | 42,620 | | | 92,878 | | | 47,093 | |
| | | | | | | |
(1) Includes undeveloped acreage in Other Americas of 25,096 gross and 11,977 net thousands of acres for 2022 and 26,084 gross and 12,471 net thousands of acres for 2021. (2) Year-end 2021 undeveloped acreage in Europe was restated for gross and net. |
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
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 ten10 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
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
Brazil
The exploration concessions were initially granted prior to the amendment and production of oil and gas are governed under Provincial Law with expiration terms through 2024.by concession contracts and production sharing contracts. Concession contracts provide for an exploration period of up to eight years and a production period of 27 years. Production sharing contracts provide for an exploration period of up to seven 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.
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.
Terms for exploration acreage in technically challenged areas are governed by frontier production licenses, generally covering a larger initial area than traditional licenses, with an initial exploration term of six or nine years with a second term extension of six years, and a final production term of 18 years, with relinquishment of 75 percent of the original area after three years and 50 percent of the remaining acreage after the next three years. Innovate licenses issued replace traditional and frontier licenses and offer greater flexibility with respect to periods and work program commitments.
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 (PSCs) negotiated with the State Ministry of Mines and Hydrocarbons. A new PSC was ratified in 2018; the initial exploration period is five years for oil and gas, with multi-year extensions available at the discretion of the Ministry and limited relinquishments in the absence of commercial discoveries. The production period for crude oil ranges from 25 tois 30 years, while the production period for natural gas ranges from 25 to 50 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, which havewith blocks Z5-C and Z5-D having an initial exploration phase that expired in 2022, resulting in a relinquishment of acreage in those blocks. Block A5-B's initial exploration phase expires in 2022 with the possibility of two additional exploration phases expiring in 2024 and 2026. The EPCCs provide2023. A5-B's EPCC provides 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.
Some exploration activitiesextended, subject to the partial relinquishment. In August 16, 2021, the Petroleum Industry Act (PIA) was enacted to replace the Petroleum Act of 1969. This granted Petroleum Prospecting Licenses (PPLs - replacing OPLs) with an initial term of five years and optional five-year extension. Petroleum Mining Leases (PMLs - replacing OMLs) are carried out in deepwater by joint ventures with local companies holding interests in an OPL. OPLs in deepwater offshore areas are validgranted for 10 years, while in all other areas the licenses are for five years. Demonstrating aeach commercial discovery isin the basisPPL for conversiona 20-year term. The PIA also had a "savings provision" which allowed NNPC to renegotiate its PSCs and renew their OMLs for 20 years under existing 1969 Act terms, within 12 months from the enactment of an OPL to an OML.the PIA. On August 11, 2022, the leases for OML 133 and 138 were renewed under the savings provision.
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. All future renewals will be conducted under PIA terms.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,March 11, 2011, 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.Act (PPT). This was also repealed by the PIA in August 2021 with lease holders having the option to convert to PIA terms or retain PPT terms until their current leases expire.
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.
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.
Other exploration and production activities are governed by PSAs negotiated with the national oil company of Azerbaijan. The exploration period typically consists of three or four years with the possibility of a one to three-year extension. The production period, which includes development, is for 25 years or 35 years with the possibility of one or two five-year extensions.
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 up to 10once for a period of four years andwith a total contract period of 30 years including an exploitation periodperiod. PSC terms can be extended for a maximum of 20 years. PSCs generally requireyears for each extension with the contractor to relinquish 10 to 20 percentapproval of the contract area after three years and generally allow the contractor to retain no more than 50 to 80 percent of the original contract area after six years, depending on the acreage and terms.government.
Iraq
Development and production activities in the state-owned oil and gas fields are governed by contracts with regional oil companies of the Iraqi Ministry of Oil. An ExxonMobil affiliate entered into a contract with Basra Oil Company of the Iraqi Ministry of Oil for the rights to participate in the development and production activities of the West Qurna Phase I oil and gas field effective March 1, 2010. The term of the contract is 20 years with the right to extend for a period of five to 15 years. The contract provides for cost recovery plus per-barrel fees for incremental production above specified levels.
Exploration and production activities in the Kurdistan Region of Iraq are governed by production sharing contracts (PSCs) negotiated with the regional government of Kurdistan in 2011. The exploration term is for five years, with extensions available as provided by the PSCs and at the discretion of the regional government of Kurdistan. Current PSCs remain in effect by agreement of the regional government to allow additional time for exploration or evaluation of commerciality. The production period is 20 years with the right to extend for five years.
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 arewere fixed by the currenta production sharing agreement between the Russian government and the Sakhalin-1 consortium, of which ExxonMobil iswas the operator. 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
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. The term of one of the two concessions expires in 2021.
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 expectedlikely to become commercially viable within 15 years. These are granted for periods of five years, and renewals may be requested. Prior to July 1998, production licenses were granted initially for 21 years, with a further renewal of 21 years and thereafter indefinitely, i.e., for the life of the field. Effective from July 1998, new production licenses are granted indefinitely. In each case, a production license may be terminated if no production operations have been carried on for five years.
Papua New Guinea
Exploration and production activities are governed by the Oil and Gas Act. Petroleum prospecting licenses are granted for an initial term of six years with a five-year extension possible (an additional extension of three years is possible in certain circumstances). Generally, a 50-percent relinquishment of the license area is required at the end of the initial six-year term, if extended. Petroleum development licenses are granted for an initial 25-year period. An extension for further consecutive period(s) of up to 20 years may be granted at the Minister’s discretion. Petroleum retention licenses may be granted for gas resources that are not commercially viable at the time of application but may become commercially viable within the maximum possible retention time of 15 years. Petroleum retention licenses are granted for an initial five-year terms,period, and may only 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.
Information with regard to the Downstream segment follows:refining capacity:
ExxonMobil’s Downstream segmentExxonMobil 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, feedstocks, and other products and feedstocks to our customers around the world.
Refining Capacity At Year-End 2020(1)
| Refining Capacity At Year-End 2022 (1) | | Refining Capacity At Year-End 2022 (1) |
| | | | | | | ExxonMobil Share KBD (2) | | ExxonMobil
Interest % | | | | | | | ExxonMobil Share KBD (2) | | ExxonMobil
Interest % |
| United States | United States | | | | | | | United States | | | | | | | | |
| Joliet | Joliet | | Illinois | | 254 | | | 100 | Joliet | | Illinois | n | | | 258 | | | 100 |
| Baton Rouge | Baton Rouge | | Louisiana | | 520 | | | 100 | Baton Rouge | | Louisiana | n | | ▲ | | 523 | | | 100 |
| Billings | | Montana | | 60 | | | 100 | |
Billings (3) | | Billings (3) | | Montana | n | | | 60 | | | 100 |
| Baytown | Baytown | | Texas | | 561 | | | 100 | Baytown | | Texas | n | | ▲ | | 565 | | | 100 |
| Beaumont | Beaumont | | Texas | | 369 | | | 100 | Beaumont | | Texas | n | | ▲ | | 369 | | | 100 |
| Total United States | Total United States | | | | 1,764 | | | | Total United States | | | | | | 1,775 | | | |
| | Canada | Canada | | | | | | | Canada | | | | | | | | |
| Strathcona | Strathcona | | Alberta | | 196 | | | 69.6 | Strathcona | | Alberta | n | | | 197 | | | 69.6 |
| Nanticoke | Nanticoke | | Ontario | | 113 | | | 69.6 | Nanticoke | | Ontario | n | | | 113 | | | 69.6 |
| Sarnia | Sarnia | | Ontario | | 119 | | | 69.6 | Sarnia | | Ontario | n | | | 123 | | | 69.6 |
| Total Canada | Total Canada | | | | 428 | | | | Total Canada | | | | | | 433 | | | |
| | Europe | Europe | | | | | | | Europe | | | | | | | | |
| Antwerp | Antwerp | | Belgium | | 307 | | | 100 | Antwerp | | Belgium | n | | | 307 | | | 100 |
| Fos-sur-Mer | Fos-sur-Mer | | France | | 133 | | | 82.9 | Fos-sur-Mer | | France | n | | | 133 | | | 82.9 |
| Gravenchon | Gravenchon | | France | | 244 | | | 82.9 | Gravenchon | | France | n | | ▲ | | 244 | | | 82.9 |
| Karlsruhe | Karlsruhe | | Germany | | 78 | | | 25 | Karlsruhe | | Germany | n | | | 78 | | | 25 |
| Trecate | | Italy | | 132 | | | 75.2 | |
Trecate (3) | | Trecate (3) | | Italy | n | | | 132 | | | 75 |
| Rotterdam | Rotterdam | | Netherlands | | 192 | | | 100 | Rotterdam | | Netherlands | n | | ▲ | | 192 | | | 100 |
| Slagen | | Norway | | 116 | | | 100 | |
| | Fawley | Fawley | | United Kingdom | | 262 | | | 100 | Fawley | | United Kingdom | n | | ▲ | | 262 | | | 100 |
| Total Europe | Total Europe | | | | 1,464 | | | | Total Europe | | | | | | 1,348 | | | |
| | Asia Pacific | Asia Pacific | | | | | | | Asia Pacific | | | | | | | | |
Altona (3) | | Australia | | 88 | | | 100 | |
| | Fujian | Fujian | | China | | 67 | | | 25 | Fujian | | China | n | | | 67 | | | 25 |
| Jurong/PAC | Jurong/PAC | | Singapore | | 592 | | | 100 | Jurong/PAC | | Singapore | n | | ▲ | | 592 | | | 100 |
| Sriracha | | Thailand | | 167 | | | 66 | |
Sriracha (3) | | Sriracha (3) | | Thailand | n | | | 167 | | | 66 |
| Total Asia Pacific | Total Asia Pacific | | | | 914 | | | | Total Asia Pacific | | | | | | 826 | | | |
| | Middle East | Middle East | | | | | | | Middle East | | | | | | | | |
| Yanbu | Yanbu | | Saudi Arabia | | 200 | | | 50 | Yanbu | | Saudi Arabia | n | | | 200 | | | 50 |
| | Total Worldwide | Total Worldwide | | | | 4,770 | | | | Total Worldwide | | | | | | 4,582 | | | |
| n Energy Products ▲ Specialty Products | | n Energy Products ▲ Specialty Products |
| (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 the Laffan Refinery in Qatar for which results are reported in the Upstream segment. | | (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 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. | | (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. |
(3) The Corporation announced sales agreements relating to these assets and expects the transactions to close in 2023. | | (3) The Corporation announced sales agreements relating to these assets and expects the transactions to close in 2023. |
(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.
(3)The Corporation expects to convert the Altona refinery into a terminal in 2021.
Information with regard to retail fuel sites:
The marketing operationsWithin the Energy Products segment, retail fuels sites sell products and services throughout the world through our Exxon, Esso, and Mobil brands.
| | | | | | | | | | | |
| Number of Retail Fuel Sites At Year-End 2022 | | |
| | | |
| Owned/leased | Distributors/resellers | Total |
| | | |
United States (1) | — | | 11,139 | | 11,139 | |
| Canada | — | | 2,415 | | 2,415 | |
Europe (2) | 197 | | 5,830 | | 6,027 | |
Asia Pacific (3) | 563 | | 1,438 | | 2,001 | |
| Latin America | — | | 510 | | 510 | |
| Middle East/Africa | 221 | | 200 | | 421 | |
| Worldwide | 981 | | 21,532 | | 22,513 | |
| | | |
(1) In October 2022, the Corporation reached an agreement with Par Pacific Holdings for the sale of the Billings refinery and select midstream assets, which includes about 300 retail fuel sites, and expects the transaction to close in 2023. |
(2) In December 2022, the Corporation reached an agreement with Italiana Petroli for the sale of the Italy fuels business, which includes about 2,300 retail fuel sites, and expects the transaction to close in 2023. |
(3) In January 2023, the Corporation announced the sale of its interest in Esso Thailand, which includes a network of about 800 retail fuel sites, and expects the transaction to close in 2023. |
Retail Sites At Year-End 2020
| | | | | |
United States
| |
Owned/leased | — | |
Distributors/resellers | 10,982 | |
Total United States | 10,982 | |
| |
Canada | |
Owned/leased | — | |
Distributors/resellers | 2,370 | |
Total Canada | 2,370 | |
| |
Europe | |
Owned/leased | 197 | |
Distributors/resellers | 5,764 | |
Total Europe | 5,961 | |
| |
Asia Pacific | |
Owned/leased | 569 | |
Distributors/resellers | 1,243 | |
Total Asia Pacific | 1,812 | |
| |
Latin America | |
Owned/leased | — | |
Distributors/resellers | 411 | |
Total Latin America | 411 | |
| |
Middle East/Africa | |
Owned/leased | 225 | |
Distributors/resellers | 192 | |
Total Middle East/Africa | 417 | |
| |
Worldwide | |
Owned/leased | 991 | |
Distributors/resellers | 20,962 | |
Total Worldwide | 21,953 | |
Information with regard to the Chemical segment follows:chemical complex capacity:
ExxonMobil’s Chemical segmentExxonMobil manufactures and sells petrochemicals. The Chemical business supplieslarge/integrated chemical complexes supply olefins, polyolefins, aromatics, and a wide variety of other petrochemicals.petrochemical products.
Chemical Complex Capacity At Year-End 2020(1)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Ethylene | | Polyethylene | | Polypropylene | | Paraxylene | | ExxonMobil
Interest % |
| | | | | (millions of metric tons per year) | | |
| North America | | | | | | | | | | | | |
| Baton Rouge | | Louisiana | | 1.1 | | | 1.3 | | | 0.4 | | | — | | | 100 | |
| Baytown | | Texas | | 3.9 | | | — | | | 0.7 | | | 0.6 | | | 100 | |
| Beaumont | | Texas | | 0.9 | | | 1.7 | | | — | | | 0.3 | | | 100 | |
| Mont Belvieu | | Texas | | — | | | 2.3 | | | — | | | — | | | 100 | |
| Sarnia | | Ontario | | 0.3 | | | 0.5 | | | — | | | — | | | 69.6 | |
| Total North America | | | | 6.2 | | | 5.8 | | | 1.1 | | | 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 | | 0.6 | | | 0.7 | | | — | | | — | | | 50 | |
| Yanbu | | Saudi Arabia | | 1.0 | | | 0.7 | | | 0.2 | | | — | | | 50 | |
| Total Middle East | | | | 1.6 | | | 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 | | | | 10.8 | | | 10.6 | | | 2.7 | | | 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. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Chemical Complex Capacity At Year-End 2022 (1) |
| | | | | | | | | | |
| (millions of metric tons per year, unless otherwise noted) | | Ethylene | | Polyethylene | | Polypropylene | | ExxonMobil
Interest % |
| | | | | | | | | | |
| North America | | | | | | | | | | |
| Baton Rouge | | Louisiana | | 1.1 | | | 1.3 | | | 0.9 | | | 100 | |
| Baytown | | Texas | | 4.0 | | | — | | | 0.7 | | | 100 | |
| Beaumont | | Texas | | 0.9 | | | 1.7 | | | — | | | 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 | | | 1.6 | | | |
| | | | | | | | | | |
| 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 | |
| Total Europe | | | | 0.8 | | | 1.3 | | | 0.3 | | | |
| | | | | | | | | | |
| 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 | | | 25 | |
| Singapore | | Singapore | | 1.9 | | | 1.9 | | | 0.9 | | | 100 | |
| Total Asia Pacific | | | | 2.2 | | | 2.1 | | | 1.1 | | | |
| | | | | | | | | | |
| Total Worldwide | | | | 11.9 | | | 11.2 | | | 3.2 | | | |
| | | | | | | | | | |
(1) Capacity reflects 100 percent for operations of 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. |
ITEM 3. | | | | | | | | | | | | | | |
| ITEM 3. LEGAL PROCEEDINGS | | | | |
ExxonMobil has elected to use a $1 million threshold for disclosing environmental proceedings.
On August 4, 2022, XTO Energy, Inc. (“XTO”) received a letter from the Department of Justice (“DOJ”) notifying XTO of the United States Environmental Protection Agency’s (“EPA”) request to initiate a potential civil action against XTO regarding the Schnegg well in Powhatan Point, Ohio. The letter did not quantify an associated civil penalty potentially sought by the DOJ. The EPA alleges XTO breached its duty under the General Duty Clause of the Clean Air Act for the Schnegg well, and such breaches resulted in the 2018 well blowout. Neither a civil action has been filed nor a draft consent decree has been provided by the DOJ. XTO is assessing the factual basis of the allegation and any associated penalties. In discussions in January 2023, the DOJ indicated it may seek a potential penalty substantially in excess of $1 million and XTO strongly disagrees with DOJ’s initial position.
On November 21, 2022, the State of Texas, acting by and through its Attorney General (“State”), filed a complaint against the Corporation (captioned State of Texas v. Exxon Mobil Corporation) in Travis County District Court, TX, Cause No. D-1-GN-22-006534, for alleged violations of the Texas Clean Air Act at the Baytown Olefins Plant located in Baytown, Texas. The complaint seeks civil penalties for alleged unauthorized air pollution, unauthorized outdoor burning, nuisance, and unauthorized visible emissions associated with multiple alleged air emissions events between 2018 and 2022 in an amount in excess of $1 million and injunctive relief against the Corporation to enjoin a violation or threatened violation of any Texas Commission on Environmental Quality statute. The State also seeks to recover its fees and costs of litigation.
Refer to the relevant portions of “Note 16: Litigation and Other Contingencies” of the Financial Section of this report for additional information on legal proceedings.
ITEM 4.MINE SAFETY DISCLOSURES
Not applicable.
Information about our Executive Officers
(positions and ages as of February 24, 2021)
| | | | | | | | | | | | | | |
Darren W. Woods | Chairman of the Board |
| | |
Held current title since: | January 1, 2017 | Age: 56 |
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: 58 |
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. |
| | |
Andrew P. Swiger | Senior Vice President | |
| | |
Held current title since: | April 1, 2009 | Age: 64 |
Mr. Andrew P. Swiger became Senior Vice President of Exxon Mobil Corporation on April 1, 2009, a position he continues to hold as of this filing date. |
| | |
Jack P. Williams, Jr. | Senior Vice President | |
| | |
Held current title since: | June 1, 2014 | Age: 57 |
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 PresidentITEM 4. MINE SAFETY DISCLOSURES | |
| | |
|
Not applicable.
Held current title since:
September 1, 2020 | Age: 57 | 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: 56 |
Ms. Linda D. DuCharme was Vice President, Americas, Africa and Asia, ExxonMobil Gas & Power Marketing Company July 1, 2015 – July 31, 2016. She 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. |
| | |
Neil W. Duffin | President, ExxonMobil Global Projects Company |
| | |
Held current title since: | April 1, 2019 | Age: 64 |
Mr. Neil W. Duffin was President of ExxonMobil Development Company April 13, 2007 – December 31, 2016. He was President of ExxonMobil Production Company and Vice President of Exxon Mobil Corporation January 1, 2017 – March 31, 2019. He became President of ExxonMobil Global Projects Company on April 1, 2019, a position he continues to hold as of this filing date. |
| | |
| | | | | | | | |
StephenInformation about our Executive Officers (positions and ages as of February 22, 2023)
|
| | |
| Name | Age | Current and Prior Positions (up to five years) |
| | |
| Darren W. Woods | 58 | Chairman of the Boardand Chief Executive Officer (since January 1, 2017) Director and President (since January 1, 2016) |
| | |
Neil A. LittletonChapman | 60 | Senior Vice President (since January 1, 2018) |
| | |
| Kathryn A. Mikells | 57 | Senior Vice President and Chief Financial Officer (since August 9, 2021) Chief Financial Officer and a member of the board of directors for Diageo plc (November 2015 - June 2021) |
| | |
| Jack P. Williams, Jr. | 59 | Senior Vice President (since June 1, 2014) |
| | |
| James R. Chapman | 53 | Vice President, – Investor RelationsTax and SecretaryTreasurer(since November 28, 2022) Dominion Energy, Inc. (prior to November 28, 2022): Executive Vice President, Chief Financial Officer and Treasurer (January 2019 - November 2022) Senior Vice President, CFO and Treasurer (November 2018 - December 2018) Senior Vice President, Mergers & Acquisitions and Treasurer (February 2016 - October 2018) |
| | |
Len M. Fox
| 59 | Vice President and Controller |
Held current title since: | (since March 15, 20201, 2021 following a special assignment) | Age: 55 |
Mr. Stephen A. Littleton was Assistant Controller ofTreasurer, Exxon Mobil Corporation June(February 1, 2020 - December 31, 2020) Vice President, Chemical Business Services and Treasurer (June 1, 2015 - January 31, 2020) |
| | |
Jon M. Gibbs
| 51 | President of ExxonMobil Global Projects Company (since April 30, 2018. He was1, 2021) Senior Vice President, Downstream Business Services and Downstream Controller MayGlobal Project Delivery, ExxonMobil Global Projects Company (July 1, 20182020 - March 14, 2020. He became 31, 2021) President, ExxonMobil Global Services Company (April 1, 2019 - June 30, 2020) Upstream Organization Design Team Lead, ExxonMobil Development Company (January 15, 2019 - March 31, 2019) Vice President, – Investor RelationsAsia Pacific and Secretary of Exxon Mobil Corporation on March 15, 2020, positions he continues to hold as of this filing date.Middle East, ExxonMobil Development Company (January 1, 2016 - January 14, 2019) |
| | |
Liam M. Mallon
| 60 | Vice President | |
| | |
Held current title since: | (since April 1, 20192019) | Age: 58 |
Mr. Liam M. Mallon was Executive Vice President, ExxonMobil DevelopmentUpstream Company February(since April 1, 2014 – December 31, 2016. He was 2022) 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(April 1, 2019 positions he continues to hold as of this filing date.- March 31, 2022) President, ExxonMobil Development Company (January 1, 2017 - March 31, 2019) |
| | |
Karen T. McKee
| 56 | Vice President | |
| | |
Held current title since: | (since April 1, 20192019) | Age: 54 |
Ms. Karen T. McKee was Vice President, Basic Chemicals,ExxonMobil Product Solutions Company (since April 1, 2022) President, ExxonMobil Chemical Company May(April 1, 2014 – July2019 - March 31, 2017. She was 2022) Senior Vice President, Basic Chemicals, Integration & Growth, ExxonMobil Chemical Company August (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.2019) |
| | |
Craig S. Morford
| 64 | Vice President and General Counsel | |
| | |
Held current title since: | (since November 1, 20202020) | Age: 62Secretary
|
Mr. Craig S. Morford was (since March 1, 2022)Deputy General Counsel (May 1, 2019 - October 31, 2020) Chief Legal and Compliance Officer of Cardinal Heath,Health, 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. |
| | |
David S. Rosenthal | Vice President and Controller | |
| | |
Held current title since: | October 1, 2008 (Vice President)(until March 2019)
September 1, 2014 (Controller)
|
Age: 64 |
Mr. David S. Rosenthal was Vice President – Investor Relations and Secretary of Exxon Mobil Corporation October 1, 2008 – August 31, 2014. He became Vice President and Controller of Exxon Mobil Corporation on September 1, 2014, 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:Darrin L. Talley
| 58 | March 1, 2010 (Vice President and General Tax Counsel)
April 1, 2020 (Treasurer) | Age: 59 |
Mr. James M. Spellings, Jr. became Vice President and General Tax Counsel of Exxon Mobil Corporation 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 (since April 1, 20172022) | Age: 61 |
Mr. Theodore J. Wojnar, Jr. was President, of ExxonMobil Research and Engineering Company April(April 1, 2011 – July2020 - March 31, 2017. He became Vice President –2022) Manager, Corporate Strategy, Corporate Strategic Planning of Exxon Mobil Corporation on August 1,(March 15, 2017 a position he continues to hold as of this filing date. |
| | - March 31, 2020) |
Officers are generally elected by the Board of Directors at its meeting on the day of each annual election of directors, with each such officer serving until a successor has been elected and qualified. The above-named officers are required to file reports under Section 16 of the Securities Exchange Act of 1934.
PART II
ITEM 5. | | |
| 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 343,633310,437 registered shareholders of ExxonMobil common stock at December 31, 2020.2022. At January 31, 2021,2023, the registered shareholders of ExxonMobil common stock numbered 341,925.308,630.
On January 27, 2021,30, 2023, the Corporation declared an $0.87a $0.91 dividend per common share, payable March 10, 2021.2023.
Reference is made to Item 12 in Part III of this report.
| | | | | | | | | | | | | | |
Issuer Purchases of Equity Securities for Quarter Ended December 31, 2020 |
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 2020 | - | | - | |
November 2020 | - | | - | |
December 2020 | - | | - | |
Total | — | | — | (See Note 1) |
| | | | | | | | | | | | | | |
| Issuer Purchases of Equity Securities for Quarter Ended December 31, 2022 |
| Total Number of Shares Purchased (1) | Average Price Paid per Share (2) | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (3) | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program
(Billions of dollars) |
| October 2022 | 14,693,713 | $102.09 | 14,693,705 | $37.9 |
| November 2022 | 15,273,566 | $112.13 | 12,755,411 | $36.5 |
| December 2022 | 13,674,403 | $106.99 | 13,674,403 | $35.0 |
| Total | 43,641,682 | $107.14 | 41,123,519 | |
| | | | |
(1) Includes shares withheld from participants in the company's incentive program for personal income taxes. |
(2) The full-year average price paid per share is $93.15. |
(3) In its 2022 Corporate Plan Update released December 8, 2022, the Corporation stated that the company expanded its share repurchase program to up to $50 billion through 2024, including $15 billion of repurchases in 2022. |
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 its earnings release dated February 2, 2021, the Corporation stated that it had suspended its first quarter 2021 anti-dilutive share repurchase program due to market uncertainty and intends to resume this program in the future as market conditions improve.
| | |
| ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Reference is made to the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Financial Section of this report.
| | | | | | | | | | | | | | |
| ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Reference is made to the section entitled “Market Risks, Inflation and Other Uncertainties”, excluding the part entitled “Inflation and Other Uncertainties”,Risks” in the Financial Section of this report. All statements, other than historical information incorporated in this Item 7A, are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things, factors discussed in this report.
ITEM 8. | | | | | | | | |
| 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 24, 2021,22, 2023, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” and continuing through “Note 20: RestructuringDivestment Activities”;
•“Supplemental Information on Oil and Gas Exploration and Production Activities” (unaudited); and
•“Frequently Used Terms” (unaudited).
Financial Statement Schedules have been omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto.
| | |
| ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
| | | | | | | | |
| ITEM 9A. CONTROLS AND PROCEDURES | | |
Management’s Evaluation of Disclosure Controls and Procedures
As indicated in the certifications in Exhibit 31 of this report, the Corporation’s Chief Executive Officer, PrincipalChief Financial Officer, and Principal Accounting Officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2020.2022. 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, PrincipalChief 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, 2020.2022.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2020,2022, as stated in their report included in the Financial Section of this report.
Changes in Internal Control Over Financial Reporting
There were no changes during the Corporation’s last fiscal quarter that materially affected, or are reasonably likely to materially affect, the Corporation’s internal control over financial reporting.
| | | | | | | | |
| ITEM 9B. OTHER INFORMATION | | |
None.
ITEM 9B.OTHER INFORMATION | | |
| ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS |
None.Not applicable.
PART III
| | |
| ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Reference is made to the section of this report titled “Information about our Executive Officers”.
Incorporated by reference to the following from the registrant’s definitive proxy statement for the 20212023 annual meeting of shareholders (the “2021“2023 Proxy Statement”):
•The section entitled “Election of Directors”;
•The portion entitled “Delinquent Section 16(a) Reports” of the section entitled “Director and Executive Officer Stock Ownership”;
•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, and the membership table of the portions entitled “Board Meetings and Annual Meeting Attendance” andportion, the membership table of the portion entitled “Board Committees”, the "Audit Committee" portion and the "Nominating and Governance Committee" portion of the section entitled “Corporate Governance”.
ITEM 11. | | |
| 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”, and "Pay Versus Performance" of the registrant’s 20212023 Proxy Statement.
| | |
| ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
The information required under Item 403 of Regulation S-K is incorporated by reference to the sections “Certain Beneficial Owners” and “Director and Executive Officer Stock Ownership” and “Certain Beneficial Owners” of the registrant’s 20212023 Proxy Statement.
| | Equity Compensation Plan Information | Equity Compensation Plan Information | Equity Compensation Plan Information |
| | | (a) | | (b) | | (c) | | (a) | | (b) | | (c) |
| Plan Category | 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)] | 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 | Equity compensation plans approved by security holders | 42,714,580 | | | (1) | | — | | 70,944,592 | | | (2)(3) | Equity compensation plans approved by security holders | 42,542,460 | | | (1) | | — | | 60,288,068 | | | (2)(3) |
| | Equity compensation plans not approved by security holders | Equity compensation plans not approved by security holders | — | | | | | — | | — | | | | Equity compensation plans not approved by security holders | — | | | | | — | | — | | | |
| | Total | Total | 42,714,580 | | | | | — | | 70,944,592 | | | | Total | 42,542,460 | | | | | — | | 60,288,068 | | | |
| (1) The number of restricted stock units to be settled in shares. | | (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 59,964,868 shares available for award under the 2003 Incentive Program and 323,200 shares available for award under the 2004 Non-Employee Director Restricted Stock Plan. | | (2) Available shares can be granted in the form of restricted stock or other stock-based awards. Includes 59,964,868 shares available for award under the 2003 Incentive Program and 323,200 shares available for award under the 2004 Non-Employee Director Restricted Stock Plan. |
(3) Under the 2004 Non-Employee Director Restricted Stock Plan approved by shareholders in May 2004, and the related standing resolution adopted by the Board, each non-employee director automatically receives 8,000 shares of restricted stock when first elected to the Board and, if the director remains in office, an additional 2,500 restricted shares each following year. While on the Board, each non-employee director receives the same cash dividends on restricted shares as a holder of regular common stock, but the director is not allowed to sell the shares. The restricted shares may be forfeited if the director leaves the Board early. | | (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. |
(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 70,523,392 shares available for award under the 2003 Incentive Program and 421,200 shares available for award under the 2004 Non-Employee Director Restricted Stock Plan.
(3)Under the 2004 Non-Employee Director Restricted Stock Plan approved by shareholders in May 2004, and the related standing resolution adopted by the Board, each non-employee director automatically receives 8,000 shares of restricted stock when first elected to the Board and, if the director remains in office, an additional 2,500 restricted shares each following year. While on the Board, each non-employee director receives the same cash dividends on restricted shares as a holder of regular common stock, but the director is not allowed to sell the shares. The restricted shares may be forfeited if the director leaves the Board early.
| | |
| ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Incorporated by reference to the portion entitled “Related Person Transactions and Procedures” of the section entitled “Director and Executive Officer Stock Ownership”; and the portion entitled “Director Independence” of the section entitled “Corporate Governance” of the registrant’s 20212023 Proxy Statement.
| | |
| ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES |
Incorporated by reference to the portion entitled “Audit Committee” of the section entitled “Corporate Governance” and the section entitled “Ratification of Independent Auditors” of the registrant’s 20212023 Proxy Statement.
PART IV
ITEM 15.EXHIBITS, | | |
| ITEM 15. EXHIBIT AND FINANCIAL STATEMENT SCHEDULES |
(a)(1) and (2) Financial Statements:
See Table of Contents of the Financial Section of this report.
(b)(3) Exhibits:
See Index to Exhibits of this report.
| | |
| ITEM 16. FORM 10-K SUMMARY |
None.
FINANCIAL SECTION
| | | | | |
| TABLE OF CONTENTS | |
| |
| Business Profile | | |
| Financial Information | | |
| Frequently Used Terms | |
| |
| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Functional Earnings | 39 | |
| Forward-Looking Statements | | |
| Overview | | |
Business Environment and Risk Assessment | | |
Review of 2020 and 2019Business Results | 44 | |
| Liquidity and Capital Resources | | |
| Capital and Exploration Expenditures | | |
| Taxes | | |
| Environmental Matters | | |
Market Risks Inflation and Other Uncertainties | | |
Restructuring Activities | 55 | |
| Critical Accounting Estimates | |
| |
| Management’s Report on Internal Control Over Financial Reporting | | |
| Report of Independent Registered Public Accounting Firm | |
| |
| Consolidated Financial Statements | |
| |
| Statement of Income | | |
| Statement of Comprehensive Income | | |
| Balance Sheet | | |
| Statement of Cash Flows | | |
| Statement of Changes in Equity | |
| |
| Notes to Consolidated Financial Statements | |
| |
| 1. Summary of Accounting Policies | | |
2. Accounting ChangesRussia | | |
| 3. Miscellaneous Financial Information | | |
| 4. Other Comprehensive Income Information | | |
| 5. Cash Flow Information | | |
| 6. Additional Working Capital Information | | |
| 7. Equity Company Information | | |
| 8. Investments, Advances and Long-Term Receivables | | |
| 9. Property, Plant and Equipment and Asset Retirement Obligations | | |
| 10. Accounting for Suspended Exploratory Well Costs | | |
| 11. Leases | | |
| 12. Earnings Per Share | | |
| 13. Financial Instruments and Derivatives | | |
| 14. Long-Term Debt | | |
| 15. Incentive Program | | |
| 16. Litigation and Other Contingencies | | |
| 17. Pension and Other Postretirement Benefits | | |
| 18. Disclosures about Segments and Related Information | | |
| 19. Income and Other Taxes | | |
20. RestructuringDivestment Activities | |
| |
| Supplemental Information on Oil and Gas Exploration and Production Activities | | |
Operating Information | 123 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Earnings (Loss) After
Income Taxes | | Average Capital
Employed | | Return on
Average Capital
Employed | | Capital and
Exploration
Expenditures |
| Financial | 2020 | | 2019 | | 2020 | | 2019 | | 2020 | | 2019 | | 2020 | | 2019 |
| | (millions of dollars) | | (percent) | | (millions of dollars) |
| Upstream | | | | | | | | | | | | | | | |
| United States | (19,385) | | | 536 | | | 65,780 | | | 72,152 | | | (29.5) | | 0.7 | | 6,817 | | | 11,653 | |
| Non-U.S. | (645) | | | 13,906 | | | 107,506 | | | 107,271 | | | (0.6) | | 13.0 | | 7,614 | | | 11,832 | |
| Total | (20,030) | | | 14,442 | | | 173,286 | | | 179,423 | | | (11.6) | | 8.0 | | 14,431 | | | 23,485 | |
| Downstream | | | | | | | | | | | | | | | |
| United States | (852) | | | 1,717 | | | 11,472 | | | 9,515 | | | (7.4) | | 18.0 | | 2,344 | | | 2,353 | |
| Non-U.S. | (225) | | | 606 | | | 18,682 | | | 18,518 | | | (1.2) | | 3.3 | | 1,877 | | | 2,018 | |
| Total | (1,077) | | | 2,323 | | | 30,154 | | | 28,033 | | | (3.6) | | 8.3 | | 4,221 | | | 4,371 | |
| Chemical | | | | | | | | | | | | | | | |
| United States | 1,277 | | | 206 | | | 14,436 | | | 13,196 | | | 8.8 | | 1.6 | | 2,002 | | | 2,547 | |
| Non-U.S. | 686 | | | 386 | | | 17,600 | | | 18,113 | | | 3.9 | | 2.1 | | 714 | | | 718 | |
| Total | 1,963 | | | 592 | | | 32,036 | | | 31,309 | | | 6.1 | | 1.9 | | 2,716 | | | 3,265 | |
| Corporate and financing | (3,296) | | | (3,017) | | | (1,445) | | | (2,162) | | | — | | — | | 6 | | | 27 | |
| Total | (22,440) | | | 14,340 | | | 234,031 | | | 236,603 | | | (9.3) | | 6.5 | | 21,374 | | | 31,148 | |
See Frequently Used Terms for a definition and calculation of capital employed and return on average capital employed. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Earnings (Loss) After
Income Taxes | | Average Capital Employed (Non-GAAP) | | Return on Average Capital Employed (Non-GAAP) | | Capital and
Exploration
Expenditures |
| Financial | | 2022 | | 2021 | | 2022 | | 2021 | | 2022 | | 2021 | | 2022 | | 2021 |
| | | (millions of dollars) | | (millions of dollars) | | (percent) | | (millions of dollars) |
| Upstream | | | | | | | | | | | | | | | | |
| United States | | 11,728 | | | 3,663 | | | 52,555 | | | 55,305 | | | 22.3 | | 6.6 | | 6,968 | | | 4,018 | |
| Non-U.S. | | 24,751 | | | 12,112 | | | 93,250 | | | 101,645 | | | 26.5 | | 11.9 | | 10,034 | | | 8,236 | |
| Total | | 36,479 | | | 15,775 | | | 145,805 | | | 156,950 | | | 25.0 | | 10.1 | | 17,002 | | | 12,254 | |
| | | | | | | | | | | | | | | | |
| Energy Products | | | | | | | | | | | | | | | | |
| United States | | 8,340 | | | 668 | | | 11,787 | | | 11,902 | | | 70.8 | | 5.6 | | 1,351 | | | 982 | |
| Non-U.S. | | 6,626 | | | (1,014) | | | 18,855 | | | 18,537 | | | 35.1 | | (5.5) | | 1,059 | | | 1,005 | |
| Total | | 14,966 | | | (347) | | | 30,642 | | | 30,439 | | | 48.8 | | (1.1) | | 2,410 | | | 1,987 | |
| | | | | | | | | | | | | | | | |
| Chemical Products | | | | | | | | | | | | | | | | |
| United States | | 2,328 | | | 3,697 | | | 14,694 | | | 14,107 | | | 15.8 | | 26.2 | | 1,123 | | | 1,200 | |
| Non-U.S. | | 1,215 | | | 3,292 | | | 12,513 | | | 11,758 | | | 9.7 | | 28.0 | | 1,842 | | | 825 | |
| Total | | 3,543 | | | 6,989 | | | 27,207 | | | 25,865 | | | 13.0 | | 27.0 | | 2,965 | | | 2,025 | |
| | | | | | | | | | | | | | | | |
| Specialty Products | | | | | | | | | | | | | | | | |
| United States | | 1,190 | | | 1,452 | | | 2,072 | | | 1,997 | | | 57.4 | | 72.7 | | 46 | | | 185 | |
| Non-U.S. | | 1,225 | | | 1,807 | | | 6,207 | | | 5,915 | | | 19.7 | | 30.5 | | 222 | | | 141 | |
| Total | | 2,415 | | | 3,259 | | | 8,279 | | | 7,912 | | | 29.2 | | 41.2 | | 268 | | | 326 | |
| | | | | | | | | | | | | | | | |
| Corporate and Financing | | (1,663) | | | (2,636) | | | 16,471 | | | 1,724 | | | — | | — | | 59 | | | 3 | |
| Corporate total | | 55,740 | | | 23,040 | | | 228,404 | | | 222,890 | | | 24.9 | | 10.9 | | 22,704 | | | 16,595 | |
| | | | | | | | | | | | | | | | |
| See Frequently Used Terms for a definition and calculation of capital employed and return on average capital employed. |
| Due to rounding, numbers presented may not add up precisely to the totals indicated. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating | 2020 | | 2019 | | | | 2020 | | 2019 |
| (thousands of barrels daily) | | (thousands of barrels daily) |
| Net liquids production | | | | | Refinery throughput | | | | |
| United States | 685 | | | 646 | | | United States | | 1,549 | | | 1,532 | |
| Non-U.S. | 1,664 | | | 1,740 | | | Non-U.S. | | 2,224 | | | 2,449 | |
| Total | 2,349 | | | 2,386 | | | Total | | 3,773 | | | 3,981 | |
| | | | | | | | | |
| (millions of cubic feet daily) | | (thousands of barrels daily) |
| Natural gas production available for sale | | | | | Petroleum product sales (2) | | | | |
| United States | 2,691 | | | 2,778 | | | United States | | 2,154 | | | 2,292 | |
| Non-U.S. | 5,780 | | | 6,616 | | | Non-U.S. | | 2,741 | | | 3,160 | |
| Total | 8,471 | | | 9,394 | | | Total | | 4,895 | | | 5,452 | |
| | | | | | | | | |
| (thousands of oil-equivalent barrels daily) | | (thousands of metric tons) |
Oil-equivalent production (1) | 3,761 | | | 3,952 | | | Chemical prime product sales (2) (3) | | | | |
| | | | | | United States | | 9,010 | | | 9,127 | |
| | | | | | Non-U.S. | | 16,439 | | | 17,389 | |
| | | | | | Total | | 25,449 | | | 26,516 | |
(1)Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.
(2)Petroleum product and chemical prime product sales data reported net of purchases/sales contracts with the same counterparty.
(3)Prime product sales are total product sales including ExxonMobil’s share of equity company volumes and finished-product transfers to the Downstream.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating | 2022 | | 2021 | | | | 2022 | | 2021 |
Net liquids production (thousands of barrels daily) | | | | | Refinery throughput (thousands of barrels daily) | | | | |
| United States | 776 | | | 721 | | | United States | | 1,702 | | | 1,623 | |
| Non-U.S. | 1,578 | | | 1,568 | | | Non-U.S. | | 2,328 | | | 2,322 | |
| Total | 2,354 | | | 2,289 | | | Total | | 4,030 | | | 3,945 | |
| | | | | | | | | |
Natural gas production available for sale (millions of cubic feet daily) | | | | | Energy Products sales (2) (thousands of barrels daily) | | | | |
| United States | 2,551 | | | 2,746 | | | United States | | 2,426 | | | 2,267 | |
| Non-U.S. | 5,744 | | | 5,791 | | | Non-U.S. | | 2,921 | | | 2,863 | |
| Total | 8,295 | | | 8,537 | | | Total | | 5,347 | | | 5,130 | |
| | | | | | | | | |
Oil-equivalent production (1) (thousands of oil-equivalent barrels daily) | 3,737 | | | 3,712 | | | Chemical Products sales (2) (thousands of metric tons) | | | | |
| | | | | United States | | 7,270 | | | 7,017 | |
| | | | | | Non-U.S. | | 11,897 | | | 12,126 | |
| | | | | Total | | 19,167 | | | 19,142 | |
| | | | | | | | | |
| | | | | Specialty Products sales (2) (thousands of metric tons) | | | | |
| | | | | United States | | 2,049 | | | 1,943 | |
| | | | | Non-U.S. | | 5,762 | | | 5,723 | |
| | | | | | Total | | 7,810 | | | 7,666 | |
| | | | | | | | | |
(1) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. |
(2) Data reported net of purchases/sales contracts with the same counterparty. |
| Due to rounding, numbers presented may not add up precisely to the totals indicated. |
| | (millions of dollars, except where stated otherwise) | | (millions of dollars, except where stated otherwise) | | 2022 | | 2021 | | 2020 | |
| Sales and other operating revenue | | Sales and other operating revenue | | 398,675 | | | 276,692 | | | 178,574 | | |
| | | | | 2020 | | 2019 | | 2018 | | | |
| | | | (millions of dollars, except where stated otherwise) | | |
| Sales and other operating revenue | | 178,574 | | | 255,583 | | | 279,332 | | | | |
| Earnings (Loss) | | | |
| Upstream | | (20,030) | | | 14,442 | | | 14,079 | | | | |
| Downstream | | (1,077) | | | 2,323 | | | 6,010 | | | | |
| Chemical | | 1,963 | | | 592 | | | 3,351 | | | | |
| Corporate and financing | | (3,296) | | | (3,017) | | | (2,600) | | | | |
| | Net income (loss) attributable to ExxonMobil | Net income (loss) attributable to ExxonMobil | | (22,440) | | | 14,340 | | | 20,840 | | | | Net income (loss) attributable to ExxonMobil | | 55,740 | | | 23,040 | | | (22,440) | | |
| Earnings (Loss) per common share (dollars) | | (5.25) | | | 3.36 | | | 4.88 | | | | |
| Earnings (Loss) per common share – assuming dilution (dollars) | | (5.25) | | | 3.36 | | | 4.88 | | | | |
| | Earnings (Loss) to average ExxonMobil share of equity (percent) | | (12.9) | | | 7.5 | | | 11.0 | | | | |
| Earnings (loss) per common share (dollars) | | Earnings (loss) per common share (dollars) | | 13.26 | | | 5.39 | | | (5.25) | | |
| Earnings (loss) per common share – assuming dilution (dollars) | | Earnings (loss) per common share – assuming dilution (dollars) | | 13.26 | | | 5.39 | | | (5.25) | | |
| | Earnings (loss) to average ExxonMobil share of equity (percent) | | Earnings (loss) to average ExxonMobil share of equity (percent) | | 30.7 | | | 14.1 | | | (12.9) | | |
| | Working capital | Working capital | | (11,470) | | | (13,937) | | | (9,165) | | | | Working capital | | 28,586 | | | 2,511 | | | (11,470) | | |
| Ratio of current assets to current liabilities (times) | Ratio of current assets to current liabilities (times) | | 0.80 | | | 0.78 | | | 0.84 | | | | Ratio of current assets to current liabilities (times) | | 1.41 | | | 1.04 | | | 0.80 | | |
| | Additions to property, plant and equipment | Additions to property, plant and equipment | | 17,342 | | | 24,904 | | | 20,051 | | | | Additions to property, plant and equipment | | 18,338 | | | 12,541 | | | 17,342 | | |
| Property, plant and equipment, less allowances | Property, plant and equipment, less allowances | | 227,553 | | | 253,018 | | | 247,101 | | | | Property, plant and equipment, less allowances | | 204,692 | | | 216,552 | | | 227,553 | | |
| Total assets | Total assets | | 332,750 | | | 362,597 | | | 346,196 | | | | Total assets | | 369,067 | | | 338,923 | | | 332,750 | | |
| | Exploration expenses, including dry holes | Exploration expenses, including dry holes | | 1,285 | | | 1,269 | | | 1,466 | | | | Exploration expenses, including dry holes | | 1,025 | | | 1,054 | | | 1,285 | | |
| Research and development costs | Research and development costs | | 1,016 | | | 1,214 | | | 1,116 | | | | Research and development costs | | 824 | | | 843 | | | 1,016 | | |
| | Long-term debt | Long-term debt | | 47,182 | | | 26,342 | | | 20,538 | | | | Long-term debt | | 40,559 | | | 43,428 | | | 47,182 | | |
| Total debt | Total debt | | 67,640 | | | 46,920 | | | 37,796 | | | | Total debt | | 41,193 | | | 47,704 | | | 67,640 | | |
| Debt to capital (percent) | Debt to capital (percent) | | 29.2 | | | 19.1 | | | 16.0 | | | | Debt to capital (percent) | | 16.9 | | | 21.4 | | | 29.2 | | |
Net debt to capital (percent) (1) | Net debt to capital (percent) (1) | | 27.8 | | | 18.1 | | | 14.9 | | | | Net debt to capital (percent) (1) | | 5.4 | | | 18.9 | | | 27.8 | | |
| | ExxonMobil share of equity at year-end | ExxonMobil share of equity at year-end | | 157,150 | | | 191,650 | | | 191,794 | | | | ExxonMobil share of equity at year-end | | 195,049 | | | 168,577 | | | 157,150 | | |
| ExxonMobil share of equity per common share (dollars) | ExxonMobil share of equity per common share (dollars) | | 37.12 | | | 45.26 | | | 45.27 | | | | ExxonMobil share of equity per common share (dollars) | | 47.78 | | | 39.77 | | | 37.12 | | |
Weighted average number of common shares
outstanding (millions) | Weighted average number of common shares
outstanding (millions) | | 4,271 | | | 4,270 | | | 4,270 | | | | Weighted average number of common shares outstanding (millions) | | 4,205 | | | 4,275 | | | 4,271 | | |
| Number of regular employees at year-end (thousands) (2) | Number of regular employees at year-end (thousands) (2) | | 72.0 | | | 74.9 | | | 71.0 | | | | Number of regular employees at year-end (thousands) (2) | | 62.3 | | | 63.0 | | | 72.0 | | |
| (1) Debt net of cash. | | (1) Debt net of cash. | |
(2) 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. | | (2) 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. | |
(1)Debt net of cash.
(2)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.
Listed below are definitions of several of ExxonMobil’s key business and financial performance measures. These definitions are provided to facilitate understanding of the terms and their calculation.
Cash Flow From Operations and Asset Sales (Non-GAAP)
Cash flow from operations and asset sales is the sum of the net cash provided by operating activities and proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments from the Consolidated Statement of Cash Flows. This cash flow reflects the total sources of cash both from operating the Corporation’s assets and from the divesting of assets. The Corporation employs a long-standing and regular disciplined review process to ensure that assets are contributing to the Corporation’s strategic objectives. Assets are divested when they are no longer meeting these objectives or are worth considerably more to others. Because of the regular nature of this activity, we believe it is useful for investors to consider proceeds associated with asset sales together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions.
| | | | | | | | | | | | | | | | | |
Cash Flow From Operations and Asset Sales Cash flow from operations and asset sales is the sum(millions of the netdollars)
| 2022 | | 2021 | | 2020 |
Net cash provided by operating activities and proceeds | 76,797 | | | 48,129 | | | 14,668 | |
| Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments | 5,247 | | | 3,176 | | | 999 | |
Cash flow from the Consolidated Statement of Cash Flows. This cash flow reflects the total sources of cash from both operating the Corporation’s assetsoperations and from the divesting of assets. The Corporation employs a long-standing and regular disciplined review process to ensure that assets are contributing to the Corporation’s strategic objectives. Assets are divested when they are no longer meeting these objectives or are worth considerably more to others. Because of the regular nature of this activity, we believe it is useful for investors to consider proceeds associated with asset sales together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions. | | | | | | | | | | | | | | | | | | | Cash flow from operations and asset sales | 2020 | | 2019 | | 2018 | | | (millions of dollars) | | Net cash provided by operating activities | 14,668 | | | 29,716 | | | 36,014 | | | Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments | 999 | | | 3,692 | | | 4,123 | | | Cash flow from operations and asset sales | 15,667 | | | 33,408 | | | 40,137 | |
Capital Employed
Capital employed is a measure of net investment. When viewed from the perspective of how the capital is used by the businesses, it includes ExxonMobil’s net share of property, plant and equipment and other assets less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed in total for the Corporation, it includes ExxonMobil’s share of total debt and equity. Both of these views include ExxonMobil’s share of amounts applicable to equity companies, which the Corporation believes should be included to provide a more comprehensive measure of capital employed.
| | | | | | | | | | | | | | | | | | | Capital employed | 2020 | | 2019 | | 2018 | | | (millions of dollars) | | Business uses: asset and liability perspective | | | | | | | Total assets | 332,750 | | | 362,597 | | | 346,196 | | | Less liabilities and noncontrolling interests share of assets and liabilities | | | | | | | Total current liabilities excluding notes and loans payable | (35,905) | | | (43,411) | | | (39,880) | | | Total long-term liabilities excluding long-term debt | (65,075) | | | (73,328) | | | (69,992) | | | Noncontrolling interests share of assets and liabilities | (8,773) | | | (8,839) | | | (7,958) | | | Add ExxonMobil share of debt-financed equity company net assets | 4,140 | | | 3,906 | | | 3,914 | | | Total capital employed | 227,137 | | | 240,925 | | | 232,280 | | | | | | | | | Total corporate sources: debt and equity perspective | | | | | | | Notes and loans payable | 20,458 | | | 20,578 | | | 17,258 | | | Long-term debt | 47,182 | | | 26,342 | | | 20,538 | | | ExxonMobil share of equity | 157,150 | | | 191,650 | | | 191,794 | | | Less noncontrolling interests share of total debt | (1,793) | | | (1,551) | | | (1,224) | | | Add ExxonMobil share of equity company debt | 4,140 | | | 3,906 | | | 3,914 | | | Total capital employed | 227,137 | | | 240,925 | | | 232,280 | |
Return on Average Capital Employed
Return on average capital employed (ROCE) is a performance measure ratio. From the perspective of the business segments, ROCE is annual business segment earnings divided by average business segment capital employed (average of beginning and end-of-year amounts). These segment earnings include ExxonMobil’s share of segment earnings of equity companies, consistent with our capital employed definition, and exclude the cost of financing. The Corporation’s total ROCE is net income attributable to ExxonMobil excluding the after-tax cost of financing, divided by total corporate average capital employed. The Corporation has consistently applied its ROCE definition for many years and views it as the best measure of historical capital productivity in our capital-intensive, long-term industry. Additional measures, which are more cash flow based, are used to make investment decisions.
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| | | | | | | | | | | | | | | | | | | Return on average capital employed | 2020 | | 2019 | | 2018 | | | (millions of dollars) | | Net income (loss) attributable to ExxonMobil | (22,440) | | | 14,340 | | | 20,840 | | | Financing costs (after tax) | | | | | | | Gross third-party debt | (1,272) | | | (1,075) | | | (912) | | | ExxonMobil share of equity companies | (182) | | | (207) | | | (192) | | | All other financing costs – net | 666 | | | 141 | | | 498 | | | Total financing costs | (788) | | | (1,141) | | | (606) | | | Earnings (Loss) excluding financing costs | (21,652) | | | 15,481 | | | 21,446 | | | | | | | | | Average capital employed | 234,031 | | | 236,603 | | | 232,374 | | | | | | | | | Return on average capital employed – corporate total | (9.3) | % | | 6.5 | % | | 9.2 | % |
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | |
| | | | | | | | | | | | | | | | | | | FUNCTIONAL EARNINGS | 2020 | | 2019 | | 2018 | | | (millions of dollars, except per share amounts) | | Earnings (Loss) (U.S. GAAP) | | | | | | | Upstream | | | | | | | United States | (19,385) | | | 536 | | | 1,739 | | | Non-U.S. | (645) | | | 13,906 | | | 12,340 | | | Downstream | | | | | | | United States | (852) | | | 1,717 | | | 2,962 | | | Non-U.S. | (225) | | | 606 | | | 3,048 | | | Chemical | | | | | | | United States | 1,277 | | | 206 | | | 1,642 | | | Non-U.S. | 686 | | | 386 | | | 1,709 | | | Corporate and financing | (3,296) | | | (3,017) | | | (2,600) | | | Net income (loss) attributable to ExxonMobil (U.S. GAAP) | (22,440) | | | 14,340 | | | 20,840 | | | | | | | | | Earnings (Loss) per common share | (5.25) | | | 3.36 | | | 4.88 | | | Earnings (Loss) per common share – assuming dilution | (5.25) | | | 3.36 | | | 4.88 | |
References in this discussion to total corporate earnings (loss) mean net income (loss) attributable to ExxonMobil (U.S. GAAP) from the consolidated income statement. Unless otherwise indicated, references to earnings (loss), Upstream, Downstream, Chemical and Corporate and financing segment earnings (loss), and earnings (loss) per share are
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Capital Employed (Non-GAAP)
Capital employed is a measure of net investment. When viewed from the perspective of how the capital is used by the businesses, it includes ExxonMobil’s net share of property, plant and equipment and other assets less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed in total for the Corporation, it includes ExxonMobil’s share of total debt and equity. Both of these views include ExxonMobil’s share of amounts applicable to equity companies, which the Corporation believes should be included to provide a more comprehensive measure of capital employed.
| | | | | | | | | | | | | | | | | |
Capital Employed (millions of dollars) | 2022 | | 2021 | | 2020 |
| Business uses: asset and liability perspective | | | | | |
| Total assets | 369,067 | | | 338,923 | | | 332,750 | |
| Less liabilities and noncontrolling interests share of assets and liabilities | | | | | |
| Total current liabilities excluding notes and loans payable | (68,411) | | | (52,367) | | | (35,905) | |
| Total long-term liabilities excluding long-term debt | (56,990) | | | (63,169) | | | (65,075) | |
| Noncontrolling interests share of assets and liabilities | (9,205) | | | (8,746) | | | (8,773) | |
| Add ExxonMobil share of debt-financed equity company net assets | 3,705 | | | 4,001 | | | 4,140 | |
Total capital employed (Non-GAAP) | 238,166 | | | 218,642 | | | 227,137 | |
| | | | | |
| Total corporate sources: debt and equity perspective | | | | | |
| Notes and loans payable | 634 | | | 4,276 | | | 20,458 | |
| Long-term debt | 40,559 | | | 43,428 | | | 47,182 | |
| ExxonMobil share of equity | 195,049 | | | 168,577 | | | 157,150 | |
| Less noncontrolling interests share of total debt | (1,781) | | | (1,640) | | | (1,793) | |
| Add ExxonMobil share of equity company debt | 3,705 | | | 4,001 | | | 4,140 | |
Total capital employed (Non-GAAP) | 238,166 | | | 218,642 | | | 227,137 | |
Return on Average Capital Employed (Non-GAAP)
Return on average capital employed (ROCE) is a performance measure ratio. From the perspective of the business segments, ROCE is annual business segment earnings divided by average business segment capital employed (average of beginning and end-of-year amounts). These segment earnings include ExxonMobil’s share of segment earnings of equity companies, consistent with our capital employed definition, and exclude the cost of financing. The Corporation’s total ROCE is net income attributable to ExxonMobil excluding the after-tax cost of financing, divided by total corporate average capital employed. The Corporation has consistently applied its ROCE definition for many years and views it as one of the best measures of historical capital productivity in our capital-intensive, long-term industry. Additional measures, which are more cash flow based, are used to make investment decisions.
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Return on Average Capital Employed (millions of dollars) | 2022 | | 2021 | | 2020 |
| Net income (loss) attributable to ExxonMobil | 55,740 | | | 23,040 | | | (22,440) | |
| Financing costs (after-tax) | | | | | |
| Gross third-party debt | (1,213) | | | (1,196) | | | (1,272) | |
| ExxonMobil share of equity companies | (198) | | | (170) | | | (182) | |
| All other financing costs – net | 276 | | | 11 | | | 666 | |
| Total financing costs | (1,135) | | | (1,355) | | | (788) | |
Earnings (loss) excluding financing costs (Non-GAAP) | 56,875 | | | 24,395 | | | (21,652) | |
| | | | | |
| Average capital employed | 228,404 | | | 222,890 | | | 234,031 | |
| | | | | |
Return on average capital employed – corporate total (Non-GAAP) | 24.9% | | 10.9% | | (9.3)% |
Structural Cost Savings
Structural cost savings describe decreases in certain expenses as a result of operational efficiencies, workforce reductions, and other cost saving measures that are expected to be sustainable compared to 2019 levels. Relative to 2019, estimated cumulative annual structural cost savings totaled $7 billion. The total change between periods in expenses below will reflect both structural cost savings and other changes in spend, including market factors, such as inflation and foreign exchange impacts, as well as changes in activity levels and costs associated with new operations. Estimates of cumulative annual structural savings may be revised depending on whether cost reductions realized in prior periods are determined to be sustainable compared to 2019 levels. Structural cost savings are stewarded internally to support management’s oversight of spending over time. This measure is useful for investors to understand the Corporation’s efforts to optimize spending through disciplined expense management.
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Calculation of Structural Cost Savings (billions of dollars) | 2019 | | | | 2022 |
| Components of operating costs | | | | | |
From ExxonMobil’s Consolidated Statement of Income
(U.S. GAAP) | | | | | |
| Production and manufacturing expenses | 36.8 | | | | | 42.6 | |
| Selling, general and administrative expenses | 11.4 | | | | | 10.1 | |
| Depreciation and depletion (includes impairments) | 19.0 | | | | | 24.0 | |
| Exploration expenses, including dry holes | 1.3 | | | | | 1.0 | |
| Non-service pension and postretirement benefit expense | 1.2 | | | | | 0.5 | |
| Subtotal | 69.7 | | | | | 78.2 | |
| ExxonMobil’s share of equity company expenses | 9.1 | | | | | 13.0 | |
Total operating costs (Non-GAAP) | 78.8 | | | | | 91.2 | |
| | | | | |
| Less: | | | | | |
| Depreciation and depletion (includes impairments) | 19.0 | | | | | 24.0 | |
| Non-service pension and postretirement benefit expense | 1.2 | | | | | 0.5 | |
Other adjustments (includes equity company depreciation
and depletion) | 3.6 | | | | | 3.5 | |
Total cash operating expenses (cash opex) (Non-GAAP) | 55.0 | | | | | 63.2 | |
| | | | | |
| Energy and production taxes | 11.0 | | | | | 23.8 | |
| | | | | |
| | Market | Activity /
Other | Structural
Savings | |
Total cash operating expenses (cash opex) excluding energy and production taxes (Non-GAAP) | 44.0 | | +3 | -1 | -7 | 39.4 | |
Earnings (Loss) excluding Identified Items (Non-GAAP)
Earnings (loss) excluding Identified Items, are earnings (loss) excluding individually significant non-operational events with an absolute corporate total earnings impact of at least $250 million in a given quarter. The earnings (loss) impact of an Identified Item for an individual segment in a given quarter may be less than $250 million when the item impacts several segments or several periods. Management uses these figures to improve comparability of the underlying business across multiple periods by isolating and removing significant non-operational events from business results. The Corporation believes this view provides investors increased transparency into business results and trends, and provides investors with a view of the business as seen through the eyes of management. Earnings (loss) excluding Identified Items is not meant to be viewed in isolation or as a substitute for net income (loss) attributable to ExxonMobil as prepared in accordance with U.S. GAAP.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Upstream | | | 2022 | | | | 2021 | | | | 2020 | |
| (millions of dollars) | | U.S. | Non-U.S. | Total | | U.S. | Non-U.S. | Total | | U.S. | Non-U.S. | Total |
| Earnings (loss) (U.S. GAAP) | | 11,728 | | 24,751 | | 36,479 | | | 3,663 | | 12,112 | | 15,775 | | | (19,385) | | (645) | | (20,030) | |
| Impairments | | — | | (3,790) | | (3,790) | | | (263) | | (489) | | (752) | | | (17,092) | | (2,244) | | (19,336) | |
| Gain/(loss) on sale of assets | | 299 | | 587 | | 886 | | | — | | 459 | | 459 | | | — | | — | | — | |
| Inventory valuation - lower of cost or market | | — | | — | | — | | | — | | — | | — | | | — | | (61) | | (61) | |
| Tax-related items | | — | | (1,415) | | (1,415) | | | — | | — | | — | | | — | | (297) | | (297) | |
| | | | | | | | | | | | |
| Contractual provisions | | — | | — | | — | | | — | | (250) | | (250) | | | — | | — | | — | |
| Other | | — | | 1,380 | | 1,380 | | | — | | — | | — | | | — | | — | | — | |
| Identified Items | | 299 | | (3,238) | | (2,939) | | | (263) | | (280) | | (543) | | | (17,092) | | (2,602) | | (19,694) | |
Earnings (loss) excluding Identified Items (Non-GAAP) | | 11,429 | | 27,989 | | 39,418 | | | 3,926 | | 12,392 | | 16,318 | | | (2,293) | | 1,957 | | (336) | |
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| Energy Products | | | 2022 | | | | 2021 | | | | 2020 | |
| (millions of dollars) | | U.S. | Non-U.S. | Total | | U.S. | Non-U.S. | Total | | U.S. | Non-U.S. | Total |
| Earnings (loss) (U.S. GAAP) | | 8,340 | | 6,626 | | 14,966 | | | 668 | | (1,014) | | (347) | | | (1,342) | | (1,230) | | (2,572) | |
| Impairments | | (58) | | (216) | | (274) | | | — | | — | | — | | | (4) | | (374) | | (378) | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Tax-related items | | — | | (410) | | (410) | | | — | | — | | — | | | — | | (262) | | (262) | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Identified Items | | (58) | | (626) | | (684) | | | — | | — | | — | | | (4) | | (636) | | (640) | |
Earnings (loss) excluding Identified Items (Non-GAAP) | | 8,398 | | 7,252 | | 15,650 | | | 668 | | (1,014) | | (347) | | | (1,338) | | (594) | | (1,932) | |
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| Chemical Products | | | 2022 | | | | 2021 | | | | 2020 | |
| (millions of dollars) | | U.S. | Non-U.S. | Total | | U.S. | Non-U.S. | Total | | U.S. | Non-U.S. | Total |
| Earnings (loss) (U.S. GAAP) | | 2,328 | | 1,215 | | 3,543 | | | 3,697 | | 3,292 | | 6,989 | | | 1,196 | | 1,061 | | 2,257 | |
| Impairments | | — | | — | | — | | | — | | — | | — | | | (90) | | (2) | | (92) | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Tax-related items | | — | | — | | — | | | — | | — | | — | | | — | | (13) | | (13) | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Identified Items | | — | | — | | — | | | — | | — | | — | | | (90) | | (15) | | (105) | |
Earnings (loss) excluding Identified Items (Non-GAAP) | | 2,328 | | 1,215 | | 3,543 | | | 3,697 | | 3,292 | | 6,989 | | | 1,286 | | 1,076 | | 2,362 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Specialty Products | | | 2022 | | | | 2021 | | | | 2020 | |
| (millions of dollars) | | U.S. | Non-U.S. | Total | | U.S. | Non-U.S. | Total | | U.S. | Non-U.S. | Total |
| Earnings (loss) (U.S. GAAP) | | 1,190 | | 1,225 | | 2,415 | | | 1,452 | | 1,807 | | 3,259 | | | 571 | | 630 | | 1,201 | |
| Impairments | | — | | (40) | | (40) | | | — | | — | | — | | | — | | (219) | | (219) | |
| Gain/(loss) on sale of assets | | — | | — | | — | | | 498 | | 136 | | 634 | | | — | | — | | — | |
| | | | | | | | | | | | |
| Tax-related items | | — | | — | | — | | | — | | — | | — | | | — | | (9) | | (9) | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Identified Items | | — | | (40) | | (40) | | | 498 | | 136 | | 634 | | | — | | (228) | | (228) | |
Earnings (loss) excluding Identified Items (Non-GAAP) | | 1,190 | | 1,265 | | 2,455 | | | 954 | | 1,672 | | 2,625 | | | 571 | | 858 | | 1,429 | |
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Corporate and Financing (millions of dollars) | | 2022 | | 2021 | | 2020 |
| Earnings (loss) (U.S. GAAP) | | (1,663) | | | (2,636) | | | (3,296) | |
| Impairments | | (98) | | | — | | | (35) | |
| Gain/(loss) on sale of assets | | — | | | (12) | | | — | |
| | | | | | |
| Tax-related items | | 324 | | | — | | | — | |
| Severance charges | | — | | | (52) | | | (326) | |
| | | | | | |
| Other | | 76 | | | — | | | — | |
| Identified Items | | 302 | | | (64) | | | (361) | |
Earnings (loss) excluding Identified Items (Non-GAAP) | | (1,965) | | | (2,572) | | | (2,935) | |
| | | | | | | | | | | | | | | | | | | | |
Corporate Total (millions of dollars) | | 2022 | | 2021 | | 2020 |
| Net income (loss) attributable to ExxonMobil (U.S. GAAP) | | 55,740 | | | 23,040 | | | (22,440) | |
| Impairments | | (4,202) | | | (752) | | | (20,060) | |
| Gain/(loss) on sale of assets | | 886 | | | 1,081 | | | — | |
| Inventory valuation - lower of cost or market | | — | | | — | | | (61) | |
| Tax-related items | | (1,501) | | | — | | | (581) | |
| Severance charges | | — | | | (52) | | | (326) | |
| Contractual provisions | | — | | | (250) | | | — | |
| Other | | 1,456 | | | — | | | — | |
| Identified Items | | (3,361) | | | 27 | | | (21,028) | |
Earnings (loss) excluding Identified Items (Non-GAAP) | | 59,101 | | | 23,013 | | | (1,412) | |
References in this discussion to Corporate earnings (loss) mean net income (loss) attributable to ExxonMobil (U.S. GAAP) from the Consolidated Statement of Income. Unless otherwise indicated, references to earnings (loss), Upstream, Energy Products, Chemical Products, Specialty Products, and Corporate and Financing earnings (loss), and earnings (loss) per share are ExxonMobil's share after excluding amounts attributable to noncontrolling interests.
Due to rounding, numbers presented may not add up precisely to the totals indicated.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS
Outlooks, projections, goals, targets,Statements related to outlooks; projections; descriptions of strategic, operating, and financial plans and objectives,objectives; statements of future ambitions and plans; and other statements of future events or conditions in this release are forward-looking statements. Similarly, discussion of emission-reduction roadmaps or future plans related to carbon capture, biofuel, hydrogen, plastics recycling, and other plans to drive towards net-zero emissions are dependent on future market factors, such as continued technological progress and policy support, and represent forward-looking statements. Actual future results, including energy demand growth and mix; financial and operating performance; volume growth;total capital expenditures and mix, including allocations of capital to low carbon solutions; cost reductions and efficiency gains, including the ability to offset inflationary pressure; ambitions to achieve net-zero operated Scope 1 and Scope 2 emissions by 2050; plans to reach net-zero operated Scope 1 and 2 emissions in our unconventional Permian Basis operated assets by 2030, to eliminate routine flaring in-line with World Bank Zero Routine Flaring, and to reach near-zero methane emissions from operated assets, within evolving growth, start-up, divestment, and technological efforts; timing and outcome of projects to capture and store CO2, and produced biofuels; timing and outcome of hydrogen projects; timing to increase the use of plastic waste as feedstock for advanced recycling; cash flow, dividends and shareholder returns, including the timing and amounts of share repurchases; future debt levels and credit ratings; business and project plans, timing, costs, capacities and capacities; capital expenditures including environmental expenditures; cost reductions; emission intensity reductions; the impact of new technologies; capital expendituresreturns; and mix; investment returns; accountingresource recoveries and financial reporting effects resulting from market developments and ExxonMobil’s responsive actions, including potential impairment charges; the benefits of business integration; future debt levels and ability to reduce debt; the outcome of litigation and tax contingencies; and the impact of the COVID-19 pandemic on results,production rates could differ materially due to a number of factors. These include global or regional changes in the supply and demand for oil, natural gas, petrochemicals, and feedstocks and other market factors, economic conditions or seasonal fluctuations that impact prices and differentials;differentials for our product; government policies supporting lower carbon investment opportunities such as the impactU.S. Inflation Reduction Act or policies limiting the attractiveness of company actions to protectfuture investment such as the healthadditional European taxes on the energy sector; variable impacts of trading activities on our margins and safety of employees, vendors, customers, and communities;results each quarter; actions of competitors and commercial counterparties; the outcome of commercial negotiations, including final agreed terms and conditions; the ability to access short- and long-term debt markets on a timely and affordable basis;markets; the severity, length and ultimate impactimpacts of COVID-19 andor other public health crises, including the effects of government responses on people and economies; reservoir performance;performance, including variability and timing factors applicable to unconventional resources; the level and outcome of exploration projects and decisions to invest in future reserves; timely completion of development and other construction projects; final management approval of future projects and any changes in the scope, terms, or costs of such projects as approved; changes in law, taxes, or regulation including environmental regulations, trade sanctions, and timely granting of governmental permits;permits and certifications; government policies and support and market demand for low carbon technologies; war, trade agreements and patterns, shipping blockadescivil unrest, attacks against the company or harassment,industry, and other political or security disturbances; expropriations, seizure, or capacity, insurance or shipping limitations by foreign governments or laws; opportunities for and regulatory approval of potential investments or divestments; the actionsdivestments and satisfaction of competitors;applicable conditions to closing, including regulatory approvals; the capture of efficiencies within and between business lines and the ability to maintain near-term cost reductions as ongoing efficiencies while maintaining future competitive positioning;efficiencies; unforeseen technical or operating difficulties;difficulties and unplanned maintenance; the development and competitiveness of alternative energy and emission reductionemission-reduction technologies; the results of research programs;programs and the ability to bring new technologies to commercial scale on a cost-competitive basis; general economic conditions including the occurrence and duration of economic recessions; and other factors discussed under Item 1A. Risk Factors.
Forward-looking and other statements regarding our environmental, social and other sustainability efforts and aspirations are not an indication that these statements are necessarily material to investors or requiring disclosure in our filing with the SEC. In addition, historical, current, and forward-looking environmental, social and sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future, including future rule-making.
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.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
The following discussion and analysis of ExxonMobil’s financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Exxon Mobil Corporation. The Corporation’s accounting and financial reporting fairly reflect its integrated business model involving exploration for, and production of, crude oil and natural gas andgas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals, and a wide variety of specialty products.products; and pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen, and lower-emission fuels. ExxonMobil's operating segments are Upstream, Energy Products, Chemical Products, and Specialty Products. Where applicable, ExxonMobil voluntarily discloses additional U.S., Non-U.S., and regional splits to help investors better understand the company's operations.
Effective April 2022, the Corporation streamlined its business structure by combining the Chemical and Downstream businesses into Product Solutions. The company is organized along three businesses – Upstream, Product Solutions, and Low Carbon Solutions, aligning along market-focused value chains. Product Solutions consists of Energy Products, Chemical Products, and Specialty Products. Low Carbon Solutions will continue to be included in Corporate and Financing as the business continues to mature through commercialization and deployment of technology. The businesses are supported by a combined technology organization, and other centralized service-delivery groups, including a global projects organization.
ExxonMobil, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well-positioned to participate in substantial investments to develop new energy supplies. The company’s integrated business model, with significant investments in Upstream, DownstreamEnergy Products, Chemical Products, and ChemicalSpecialty Products segments and Low Carbon Solutions business, generally reduces the Corporation’s risk from changes in commodity prices. While commodity prices depend on supply and demand and may be volatile on a short-term basis, ExxonMobil’s investment decisions are grounded on fundamentals reflected in our long-term business outlook, and use a disciplined approach in selecting and pursuing the most attractive investment opportunities.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The corporate planCorporate Plan is a fundamental annual management process that is the basis for setting operating and capital objectives in addition to providing the economic assumptions used for investment evaluation purposes. VolumeThe foundation for the assumptions supporting the Corporate Plan is the Outlook for Energy (Outlook), and Corporate Plan volume projections are based on individual field production profiles, which are also updated at least annually. Price ranges for crude oil, natural gas, refined products,including price differentials, refinery and chemical productsmargins, volumes, development and operating costs, including greenhouse gas emissions pricing, and foreign currency exchange rates are based on corporate planCorporate Plan assumptions developed annually by major region and are utilized for investment evaluation purposes. Major investment opportunities are evaluated over a range of potential market conditions. Once we make major investments, are made,we complete a reappraisal process is completed to ensure relevantwe learn from the investment decision and incorporate the lessons are learned and improvements are incorporated into future projects.
BUSINESS ENVIRONMENT AND RISK ASSESSMENT
Long-Term Business Outlook
GivenExxonMobil’s business planning is underpinned by a deep understanding of long-term market fundamentals. These fundamentals include supply and demand trends, the uncertainty aroundscale and variety of energy needs worldwide; capability, practicality and affordability of energy alternatives including low-carbon solutions; greenhouse gas emission-reduction technologies; and supportive government policies. The company’s Outlook considers these fundamentals to form the near-term impactsbasis for the company’s long-term business planning, investment decisions, and research programs. The Outlook reflects the company’s view of COVID-19 on economic growth,global energy demand and energy supply through 2050. It is a projection based on current trends in technology, government policies, consumer preferences, geopolitics, and lack of precedent, the Company is consideringeconomic development.
In addition, ExxonMobil considers a range of recovery pathways to guide near-term plans. These pathways expect that energy demand will grow beyond 2019 levels as early as 2022 reflecting the phase out of COVID-19 impacts and re-establishment of long-term supply/demand fundamentals. The Corporation’s Outlook for Energy combined with the near-term pathways are usedscenarios - including remote scenarios - to help inform our long-term business strategies and investment plans.
By 2040, the world’s population is projected at around 9.1 billion people, or about 1.6 billion more than in 2018. Coincident with this population increase, the Corporation expects worldwide economic growth to average close to 2.5 percent per year, with economic output growing by around 75 percent by 2040. As economies and populations grow, and as living standards improve for billions of people, the need for energy is expected to continue to rise. Even with significant efficiency gains, global energy demand is projected to rise by more than 10 percent from 2018 to 2040. This increase in energy demand is expected to be driven by developing countries (i.e., those that are not member nationsperspective of the Organisation for Economic Co-operationfuture and Development (OECD)).enhance strategic thinking over time. Included in the range of these scenarios are the Intergovernmental Panel on Climate Change Lower 2°C scenarios and the IEA NZE by 2050 scenario. The IEA describes the IEA NZE as extremely challenging, requiring all stakeholders – governments, businesses, investors, and citizens – to take immediate, unprecedented action. The IEA acknowledges that society is not currently on the IEA NZE pathway. No single transition pathway can be reasonably predicted, given the wide range of uncertainties. Key unknowns include yet-to-be-developed government policies, market conditions, and advances in technology that may influence the cost, pace, and potential availability of certain pathways. Scenarios that employ a full complement of technology options are likely to provide the most economically efficient pathways.
As expanding prosperity helps drive globalUsing our own experts and third-party sources, we monitor a variety of signposts that may indicate a potential shift in the energy demand higher, increasing usetransition. For example, the regional pace of the transition could be influenced by the cost of new technologies compared to existing or alternative energy efficient technologies and practices as well as lower-emission products will continuesources. To effectively evaluate the pace of change, ExxonMobil uses many scenarios to help significantly reduce energy consumptionidentify signposts that provide leading indicators of future developments and emissions per unit of economic output over time. Substantial efficiency gains are likely in all key aspectsallow for timely adjustments to future versions of the world’s economy through 2040, affecting energy requirements for power generation, transportation, industrial applications, and residential and commercial needs.Outlook.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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Non-OECD countries projected to drive energy demand growth Primary energy, quadrillion BTUs Source: ExxonMobil 2022 Outlook for Energy | By 2050, the world’s population is projected at around 9.7 billion people, or about 2 billion more than in 2021. Coincident with this population increase, the Outlook projects worldwide economic growth to average close to 2.5 percent per year, with economic output growing by around 110 percent by 2050 compared to 2021. As economies and populations grow, and as living standards improve for billions of people, the need for energy is expected to continue to rise. Even with significant efficiency gains, global energy demand is projected to rise by almost 15 percent from 2021 to 2050. This increase in energy demand is expected to be driven by developing countries (i.e., those that are not member nations of the Organization for Economic Co-operation and Development (OECD)).
As expanding prosperity drives global energy demand higher, increasing use of energy-efficient technologies and practices as well as lower-emission products will continue to help significantly reduce energy consumption and CO2 emissions per unit of economic output over time. Substantial efficiency gains are likely in all key aspects of the world’s economy through 2050, affecting energy requirements for power generation, transportation, industrial applications, and residential and commercial needs. |
Under our Outlook, global electricity demand is expected to increase approximately 50over 75 percent from 20182021 to 2040,2050, with developing countries likely to account for about 8580 percent of the increase. Consistent with this projection, power generation is expected to remain the largest and fastest growing major segment of global primary energy demand, supported by a wide variety of energy sources. The share of coal firedcoal-fired generation is likelyexpected to decline substantially and approach 2015 percent of the world’s electricity in 2040,2050, versus nearly 4035 percent in 2018,2021, in part as a result ofdue to policies to improve air quality as well as reduce greenhouse gas emissions to address the risks related to climate change. From 20182021 to 2040,2050, the amount of electricity supplied using natural gas, nuclear power, and renewables is likelyexpected to nearlymore than double, accounting for the entire growth in electricity supplies and offsetting the reduction of coal. Electricity from wind and solar is likelyexpected to increase about 400more than 550 percent, helping total renewables (including other sources, e.g., hydropower) to account for aboutover 80 percent of the increase in electricity supplies worldwide through 2040.2050. Total renewables will likelyare expected to reach about 50 percent of global electricity supplies by 2040.2050. Natural gas and nuclear are also expected to increase shares over the period to 2040, reaching more thanbe about 25 percent and about 10 percent, respectively, of global electricity supplies respectively by 2040.2050. Supplies of electricity by energy type will reflect significant differences across regions reflecting a wide range of factors including the cost and availability of various energy supplies and policy developments.
EnergyUnder our Outlook, energy for transportation –- including cars, trucks, ships, trains and airplanes –- is expected to increase by about 20over 30 percent from 20182021 to 2040.2050. Transportation energy demand is likelyexpected to account for over 60around 65 percent of the growth in liquid fuels demand worldwide over this period. Light-duty vehicle demand for liquid fuels is projected to peak prior toby around 2025, and then decline to levels seen in the early-2010searly-2000s by 20402050, as the impact of better fuel economy and significant growth in electric cars, led by China, Europe, and the United States, work to offset growth in the worldwide car fleet of about 60almost 70 percent. By 2040,2050, light-duty vehicles are expected to account for about 20around 15 percent of global liquid fuels demand. During the same time period, nearly all the world’s commercial transportation fleets are likelyexpected to continue to run on liquid fuels, including biofuels, which are expected to be widely available and offer practical advantages in providing a large quantity of energy in small volumes.
Almost half of the world’s energy use is dedicated to industrial activity. As the global middle class continues to grow, demand for durable products, appliances, and consumable goods will increase. Industry uses energy products both as a fuel and as a feedstock for chemicals, asphalt, lubricants, waxes, and other specialty products. The Outlook anticipates technology advances, as well as the increasing shift toward cleaner forms of energy, such as electricity and natural gas, with coal declining. Demand for oil will continue to grow as a feedstock for industry.
As populations grow and prosperity rises, more energy will be needed to power homes, offices, schools, shopping centers, hospitals, etc. Combined residential and commercial energy demand is projected to rise by around 15 percent through 2050. Led by the growing economies of developing nations, average worldwide household electricity use will rise about 75 percent between 2021 and 2050.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Liquid fuels provide the largest share of global energy supplies today reflecting broad-based availability, affordability, ease of transportation, and fitness as a practical solution to meet a wide variety of needs. By 2040,2050, global demand for liquid fuels is projected to grow to approximately 110 million barrels of oil equivalent barrels per day, an increase of about 917 percent from 2018.2021. The non-OECD share of global liquid fuels demand is expected to increase to about 65nearly 70 percent by 2040,2050, as liquid fuels demand in the OECD is likelyexpected to decline by close to 15around 20 percent. Much of the global liquid fuels demand today is met by crude production from traditional conventional sources; these supplies will remain important, and significant development activity is expected to offset much of the natural declines from these fields. At the same time, a variety of emerging supply sources –- including tight oil, deepwater, oil sands, natural gas liquids, and biofuels –- are expected to grow to help meet rising demand. The world’s resource base is sufficient to meet projected demand through 20402050 as technology advances continue to expand the availability of more economic and lower carbonlower-carbon supply options. However, timely investments will remain critical to meeting global needs with reliable and affordable supplies.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Natural gas is a lower-emission, versatile and practical fuel for a wide variety of applications, and it is expected to grow the most of any primary energy type from 20182021 to 2040,2050, meeting about 5040 percent of global energy demand growth. Global natural gas demand is expected to rise aboutnearly 25 percent from 20182021 to 2040,2050, with about halfaround two-thirds of that increase coming from the Asia Pacific region. Significant growth in supplies of unconventional gas –- the natural gas found in shale and other tight rock formations –- will help meet these needs. In total, about 5550 percent of the growth in natural gas supplies is expected to be from unconventional sources. At the same time, conventionally-produced natural gas is likely to remain the cornerstone of global supply, meeting more than two thirdsaround two-thirds of worldwide demand in 2040. Liquefied natural gas (LNG)2050. LNG trade will expand significantly, meeting about 4050 percent of the increase in global demand growth, with much of this supply expected to help meet rising demand in Asia Pacific.
Oil and natural gas projected to play a critical role in the global energy mix
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| Primary energy - Quadrillion Btu | Percent of primary energy |
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| Source: ExxonMobil 2022 Outlook for Energy | Source: ExxonMobil 2022 Outlook for Energy |
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The world’s energy mix is highly diverse and will remain so through 2040.2050. Oil is expected to remain the largest source of energy with its share remaining close to 30 percent in 2040.2050. Coal is currentlyand gas are the secondnext largest sourcesources of energy but it is likely to lose that position to natural gas intoday, with the next few years. The share of natural gas is expectedgrowing to reach more than 25 percent by 2040,2050, while the share of coal falls to about two thirdshalf that of the natural gas share.gas. Nuclear power is projected to grow, significantly, as many nations are likely to expand nuclear capacity to address rising electricity needs as well as energy security and environmental issues. Total renewable energy is likelyexpected to exceed 1520 percent of global energy by 2040,2050, with other renewables (e.g., biomass, hydro and geothermalhydropower, geothermal) contributing a combined share of more than 10 percent. Total energy supplied from wind solar and biofuelssolar is expected to increase rapidly, growing over 350480 percent from 20182021 to 2040,2050, when they will likelyare projected to be just over 6around 10 percent of the world energy mix.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Decarbonization of industry activities will require a suite of nascent or future lower-carbon technologies and supporting policies. Lower-emission fuels, hydrogen-based fuels, and carbon capture and storage are three key lower-carbon solutions needed to support a lower-emission future, in addition to wind and solar. Along with electrification, lower-emission fuels are expected to play an important role in decarbonization of the transportation sector, particularly in hard-to-decarbonize areas, such as aviation. Low-carbon hydrogen will be a key enabler replacing traditional furnace fuel to decarbonize the industrial sector. Hydrogen and hydrogen-based fuels like ammonia are also expected to make inroads into commercial transportation as technology improves to lower its cost and policy develops to support the needed infrastructure development. Carbon capture and storage on its own, or in combination with hydrogen production, is among the few proven technologies that could enable CO2 emission reductions from high-emitting and hard-to-decarbonize sectors such as power generation and heavy industries, including manufacturing, refining, and petrochemicals.
Significant oil and natural gas investment needed to meet projected global demand
Projected oil supply and demand
Million barrels per day
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| Excludes biofuels; IEA STEPS and IEA NZE Source: IEA WEO 2021; Outlook Source: ExxonMobil 2022 Outlook for Energy; Average IPCC Lower 2°C Source: IPCC AR6 Scenarios Database hosted by IIASA release 1.0 average IPCC C3: 311 “Likely below 2°C” scenarios used | |
Projected global natural gas supply and demand
Billion cubic feet per day
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| IEA STEPS and IEA NZE Source: IEA WEO 2021; Outlook Source: ExxonMobil 2022 Outlook for Energy; Average IPCC Lower 2°C Source: IPCC AR6 Scenarios Database hosted by IIASA release 1.0 average IPCC C3: 311 “Likely below 2°C” scenarios used | |
To meet this projected demand under our Outlook and the IEA's Stated Policies Scenario (STEPS), the Corporation anticipates that the world’s available oil and gas resource base will grow, not only from new discoveries, but also from increases in previously discovered fields. Technology will underpin these increases. The investments to develop and supply resources to meet global demand through 20402050 will be significant, –and would be needed to meet even ifthe rapidly declining demand remains flat. This reflects a fundamental aspect of thefor oil and natural gas business as the International Energy Agency (IEA) describesenvisioned in its World Energy Outlook 2020. According to the IEA’s Stated Energy Policies Scenario, the investment required to meet oil and natural gas supply requirements worldwide over the period 2019-2040 will be about $17 trillion (measured in 2019 dollars). In the IEA’s Sustainable Development Scenario, which is in line with the objectives of the Paris Agreement on climate change, the investment need would still accumulate to $12 trillion.Net Zero Emissions by 2050 scenario.
International accords and underlying regional and national regulations covering greenhouse gas emissions continue to evolve with uncertain timing and outcome, making it difficult to predict their business impact. For many years, the Corporation has taken into account policies established to reduce energy-related greenhouse gas emissions in its long-term Outlook for Energy.Outlook. The climate accord reached at the Conference of the Parties (COP 21) in Paris set many new goals, and many related policies are still emerging. Our Outlook reflects an environment with increasingly stringent climate policies and is consistent with the global aggregation of Nationally Determined Contributions (NDCs), which were submitted by the nations that are signatories to the United Nations Framework Convention on Climate Change (UNFCCC) 2015 Paris Agreement.Agreement, as available at the end of 2021. Our Outlook seeks to identify potential impacts of climate relatedclimate-related government policies, which often target specific sectors. It estimates potential impacts of these policies on consumer energy demand by using various assumptions and tools – including, depending on the sector, application of a proxy cost of carbon or assessment of targeted policies (e.g. automotive fuel economy standards). For purposes of the Outlook, a proxy cost on energy-related CO2CO2 emissions is assumed, based on regional considerations and relative levels of economic development, and by 2050, reaches up to reach about $80$150 per tonne in 2040 inmetric ton for OECD nations and up to $100 per metric ton for non-OECD nations. China and other leading non-OECD nations are expected to trail OECD policy initiatives. Nevertheless, as people and nations look for ways to reduce risks of global climate change, they will continue to need practical solutions that do not jeopardize the affordability or reliability of the energy they need. The Corporation continues to monitor the updates to the NDCs that nations are expected to provideprovided around COP 27 in preparation for COP 26 in GlasgowEgypt in November 20212022 as well as other policy developments in light of net zeronet-zero ambitions recently formulated by some nations.
The information provided in the Long-Term Business Outlook includes ExxonMobil’s internal estimates and projections based upon internal data and analyses as well as publicly available information from external sources including the International Energy Agency.
Positioning for a Lower-Carbon Energy Future
Practical solutions to the world’s energy and climate challenges will benefit from market competition in addition to well-informed, well-designed, and transparent policy approaches that carefully weigh costs and benefits. Such policies are likely to help manage the risks of climate change while also enabling societies to pursue other high priority goals around the world – including clean air and water, access to reliable and affordable energy, and economic progress for all people. ExxonMobil encourages sound policy solutions that reduce climate-related risks across the economy at the lowest societal cost. All practical and economically-viable energy sources will need to be pursued to continue meeting global energy demand, recognizing the scale and variety of worldwide energy needs as well as the importance of expanding access to modern energy to promote better standards of living for billions of people.
ExxonMobil is committed to advancing sustainable, effective solutions that address both the world’s growing demand for energy and the risks of climate change. The Company’s plans aim for industry-leading greenhouse gas performance across its businesses by 2030. These plans include a reduction of the intensity of operated upstream greenhouse gas emissions by 15 to 20 percent in 2025, compared to 2016 levels, which will be supported by a 40 to 50 percent decrease in methane intensity and a 35 to 45 percent decrease in flaring intensity across the Corporation’s global operations. The 2025 emission reduction plans are expected to result in a reduction of absolute emissions by approximately 30 percent for the Company’s current Upstream business by 2025 when compared to 2016 levels. The emission plans cover Scope 1 and Scope 2 emissions from assets operated by the Corporation.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Progress Reducing Emissions
The Corporation’s strategy seeks to maximize the advantages of our scale, business integration, leading technology, functional excellence, and our people to build globally competitive businesses that lead industry in earnings and cash flow growth across a range of future scenarios. We strive to play a leading role in the energy transition, bringing to bear these same advantages while retaining investment flexibility across a portfolio of evolving opportunities to grow shareholder value.
With advances in technology and the support of clear and consistent government policies, we aim to achieve net-zero operated Scope 1 and 2 greenhouse gas emissions by 2050. To this end, we have taken a comprehensive approach to create greenhouse gas emission-reduction roadmaps for our major operated assets. The roadmaps build on the company’s 2030 emission-reduction plans and, notably, include reaching net-zero emissions (Scopes 1 and 2) in our unconventional Permian Basin operated assets by 2030. We completed these roadmaps in 2022. Many of the required reduction steps are unaffordable with today's technology and policy support. We plan to update the roadmaps as needed to reflect technology, policy, and other necessary developments, including the development and acquisition of major operated assets.
Compared to 2016 levels, our 2030 emission-reduction plans include a 20-30 percent reduction in corporate-wide greenhouse gas intensity, 40-50 percent reduction in upstream greenhouse gas intensity, 70-80 percent reduction in company-wide methane intensity, and 60-70 percent reduction in corporate-wide hydrocarbon flaring intensity. In achieving these objectives, we also expect to see absolute reduction in:
•World Bank Zero Routine Flaring by 2030.
Commercially viable technology advances will be needed to achieve the Paris Agreement objectives at the lowest societal cost. While many potential pathways exist, ExxonMobil cannot predict how these objectives will become achievable given the range of uncertainties. ExxonMobil is working to develop breakthrough solutions in areas such as carbon capture, biofuels, hydrogen,These emission-reduction plans cover Scope 1 and energy-efficiency process technology that can help achieve the Paris Agreement objectives. In early 2021 ExxonMobil announced the creation of a new business, ExxonMobil2 emissions from assets we operate.
Since formally launching ExxonMobil’s Low Carbon Solutions to commercialize low-carbon technologies. The business will initially focus onin early 2021, the Corporation has significantly grown the pipeline of emission-reduction opportunities in carbon capture and storage, (CCS), onehydrogen, and lower-emission fuels. Low Carbon Solutions leverages the Corporation’s unique combination of existing assets, technical capabilities, project management skills, and broad relationships with industry and governments to accelerate emission reductions for customers and help to reduce emissions in our existing businesses.
The Corporation plans to invest in initiatives to lower greenhouse gas emissions. These investments are designed to reduce emissions in the company’s operations and are also directed toward reducing others’ emissions through commercializing and scaling carbon capture and storage, hydrogen, and lower-emission fuels. Policy support, along with technology advancements, are important to the development and deployment of lower-emission technologies necessary for a net-zero future.
Recent Business Environment
Prior to the COVID-19 pandemic, many companies in the industry invested below the levels needed to maintain or increase production capacity to meet anticipated demand. During the COVID-19 pandemic, this decline in investments accelerated as industry revenue collapsed resulting in underinvestment and supply tightness as demand for petroleum and petrochemical products recovered. In addition, industry rationalization of refining assets resulted in more than 3 million barrels per day of capacity being taken offline. Across late 2021 and the first half of 2022, these reductions, along with supply chain constraints, and a continuation of demand recovery led to a steady increase in oil and natural gas prices and refining margins.
Demand for petroleum and petrochemical products grew in 2022, with the Corporation's financial results benefiting from stronger prices and margins, notably for crude oil and natural gas as well as refining products. The rate and pace of recovery, however, has varied across geographies and business lines, with industry Chemical margins falling below the bottom of the critical technologies10-year range late in 2022 reflecting weakening global demand and capacity additions. Commodity and product prices are expected to remain volatile given the current global economic uncertainty and geopolitical events affecting supply and demand.
The general rate of inflation across major countries experienced a brief decline in the initial stage of the COVID-19 pandemic, before starting to increase steadily in 2021 due to an imbalance in supply and demand. The underlying factors include, but are not limited to, time cycle of capacity investments, supply chain disruptions, shipping bottlenecks, labor constraints, and side effects from monetary and fiscal expansions. Inflationary pressure intensified in 2022 with additional impacts from the Russia-Ukraine conflict, and currently remains elevated despite policy tightening by major central banks and a moderating pace of world economic expansion. The Corporation closely monitors market trends and works to mitigate both operating and capital cost impacts in all price environments.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Organizational changes implemented over the past several years enabled the Corporation to realize $7 billion of structural cost savings(1) versus 2019, through increased operational efficiencies and reduced overhead costs. Included in these savings is the completion of the workforce reduction programs, which are estimated to generate savings of approximately $2 billion per year compared to 2019 from lower employee and contractor costs. The company continues to take actions to streamline its business structure to improve effectiveness and reduce costs. The changes more fully leverage global functional capabilities, improve line of sight to markets, and enhance resource allocation to the highest corporate priorities.
(1) Refer to Frequently Used Terms for definition of structural cost savings.
Russia-Ukraine Conflict
In response to Russia’s military action in Ukraine, the Corporation announced in early 2022 that it planned to discontinue operations on the Sakhalin-1 project (“Sakhalin”) and develop steps to exit the venture. The Corporation’s first-quarter results included after-tax charges of $3.4 billion largely representing the impairment of its operations related to Sakhalin (refer to Note 2 for further information on Russia). While the Corporation’s affiliate was in force majeure due to the impact of global sanctions, it continued to make concerted attempts to engage in good-faith exit discussions with the Russian government and all Sakhalin partners. The Corporation remained focused on safety of people, protection of the environment, and integrity of operations. Effective October 14, through two decrees the Russian government unilaterally terminated the Corporation’s interests in Sakhalin, transferring operations to a Russian operator.
The Corporation’s fourth-quarter results include an after-tax benefit of $1.1 billion largely reflecting the impact of the expropriation on the company’s various obligations related to Sakhalin. The Corporation's exit from the project results in approximately 150 million oil-equivalent barrels no longer qualifying as proved reserves at year-end 2022.
The Corporation holds a 25 percent interest in Tengizchevroil, LLP (TCO), which operates the Tengiz and Korolev oil fields in Kazakhstan, and a 16.8 percent working interest in the Kashagan field in Kazakhstan. Oil production from those operations is exported through the Caspian Pipeline Consortium (CPC), in which the Corporation holds a 7.5 percent interest. CPC traverses parts of Kazakhstan and Russia to tanker-loading facilities on the Russian coast of the Black Sea. In the event that Russia takes countermeasures in response to existing sanctions related to its military actions in Ukraine, it is possible that the transportation of Kazakhstan oil through the CPC pipeline could be disrupted, curtailed, temporarily suspended, or otherwise restricted. In such a case, the Corporation could experience a loss of cash flows of uncertain duration from its operations in Kazakhstan. For reference, after-tax earnings related to the Corporation’s interests in Kazakhstan in 2022 were approximately $2.5 billion, and its share of combined oil and gas production was approximately 246 thousand oil-equivalent barrels per day.
Additional European Taxes on the Energy Sector
On October 6, 2022, European Union (“EU”) Member States adopted an EU Council Regulation which, along with other measures, introduced a new tax described as an emergency intervention to address high energy prices. This regulation imposed a mandatory tax on certain companies active in the crude petroleum, coal, natural gas, and refinery sectors. The regulation required Member States to levy a minimum 33 percent tax on in-scope companies’ 2022 and/or 2023 “surplus profits", defined in the regulation as taxable profits exceeding 120 percent of the annual average profits during the 2018-2021 period. EU Member States were required to achieveimplement the climate objectives outlinedtax, or an equivalent national measure, by December 31, 2022. The enactment of these regulations by Member States resulted in an after-tax charge of approximately $1.8 billion to the Corporation’s fourth-quarter 2022 results, mainly reflected in the Paris Agreement. In additionline “Income tax expense (benefit)” on the Consolidated Statement of Income.
The future impact of this regulation and other measures directed at the energy sector which were imposed by EU Member States and the UK over the last few months could be a reduction to CCS, the business will also leverage ExxonMobil’s significant experience in the productionearnings of hydrogen which, when coupled with CCS, is likelyup to play a critical role in a lower-carbon energy system. Other technology focus areas will be added in the future as they mature to commercialization.$2 billion depending on commodity prices and levels of taxable income.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
BUSINESS RESULTS
ExxonMobil continues to sustain a diverse growth portfolio of exploration and development opportunities, which enables the Corporation to be selective, maximizing shareholder value and mitigating political and technical risks. ExxonMobil’s fundamental strategies guide our global Upstream business, including capturing material and accretive opportunities to continually high-grade the resource portfolio, selectively developing attractive oil and natural gas resources, developing and applying high-impact technologies, and pursuing productivity and efficiency gains.gains as well as a reduction in greenhouse gas emissions. These strategies are underpinned by a relentless focus on operational excellence, development of our employees, and investment in the communities within which we operate.
As future development projects and drilling activities bring new production online, the Corporation expects a shift in the geographic mix and in the type of opportunities from which volumes are produced. Based on current investment plans, the proportion of oil-equivalent production from the Americas is generally expected to increase over the next several years. Further,About half of the proportion of ourCorporation's global production comes from unconventional, deepwater, and deepwater resources, as well as LNG currently contributes nearly half of global production, andresources. This proportion is generally expected to grow inover the next few years.
The Upstream capital program continues to prioritize low cost-of-supply opportunities. ExxonMobil has a strong pipeline of development projects including continued growth in Guyana, Brazil, the Permian Basin, as well as LNG expansion opportunities in Qatar, Mozambique, Papua New Guinea, and the United States.
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; international trade patterns and relations; and other factors described in Item 1A. Risk Factors.
The markets for crude oil and natural gas have a history of significant price volatility. Market demand and prices experienced sharp decline in the first half of 2020 largely driven by the COVID-19 pandemic. Following this decline, prices increased in the second half of the year as supply and demand began to rebalance. ExxonMobil believes prices over the long term will continue to be driven by market supply and demand, with the demand side largely being a function of general economic activities, levels of prosperity, technology advances, consumer preference and government policies. On the supply side, prices may be significantly impacted by political events, the actions of OPEC and other large government resource owners, alternative energy sources, and other factors. To manage the risks associated with price, ExxonMobil evaluates annual plans and major investments across a range of price scenarios.
In 2020, the Upstream business produced 3.8 million oil-equivalent barrels per day and matched best-ever reliability performance with continued focus on delivering best in class operations in all aspects of the business while prioritizing cash flow generation and return on investment. Government-mandated and economic curtailments negatively impacted 2020 production by approximately 0.2 million oil-equivalent barrels per day.
Key Recent Events
Significant progress was made on key new developments in Guyana and in the Permian basin during 2020. In Guyana, exploration2022.
Guyana: Exploration success continued with three10 additional discoveries increasing the estimated recoverable resource to nearly 9 billion oil-equivalent barrels onin 2022 in the Stabroek block. In the Permian, despite economic curtailmentsThe Liza Phase 2 Unity floating production, storage and reduced capital investment,offloading vessel started production volumes averaged 367in February 2022, and our combined Liza Phase 1 and 2 developments produced above previous expectations, averaging more than 360 thousand oil-equivalent barrels per day in 2020, a 35 percent year-on-year production increase which exceeded expectations, whilethe fourth quarter. On Payara, the third project, development drilling continued and operating costs were significantly reduced. Alsoanticipated start-up timing has been accelerated to year-end 2023. Yellowtail is the fourth and largest world-class development project and is expected to achieve first oil in 2025.
Brazil: Development work is progressing on the Bacalhau Phase 1 project.
Permian: Production volumes averaged about 550 thousand oil-equivalent barrels per day (koebd) in 2022, approximately 90 koebd higher than the previous year. The Corporation was successful in increasing drilling performance and continuing to improve capital efficiency. ExxonMobil previously announced plans to achieve net-zero greenhouse gas emissions (Scope 1 and 2) from our operated unconventional operations in the Permian Basin by 2030. Towards this objective, we started up the Delaware basin central processingadvanced several emissions-reduction initiatives in 2022 including elimination of all routine flaring(1), progress with pneumatic device replacement, electrification of equipment and stabilization facility which enhances the company’s integration advantages by collectingenhancements to methane emissions detection technology.
LNG: ExxonMobil continued work to expand its LNG portfolio and processing oil and natural gas for delivery to Gulf Coast markets.
Downstream
ExxonMobil’s Downstream is a large, diversified business with global logistics, trading, refining, and marketing. The Corporation has a well-established presencesecured participation in the Americas, Europe,Qatar North Field East project, which will increase ExxonMobil’s participation in Qatar LNG production from 52 to 60 million metric tons per year. The Coral South Floating LNG development began production in October 2022 as the first development in Mozambique’s Rovuma Basin, and growing Asia Pacific region.
Downstream strategies competitively positionis expected to produce up to 3.4 million metric tons of LNG per year. The company also completed key commercial milestones to begin the business across a range of market conditions. These strategies focusPapua New Guinea expansion, and the Golden Pass LNG project remains on providing quality, differentiated, and valued products and services to customers, targeting bestschedule for 2024 start-up in class operations performance, capitalizing on integration across all ExxonMobil businesses, maximizing value from advantaged technology, and selectively investing for resilient, advantaged returns.the U.S. Gulf Coast.
ExxonMobil’s operating results, as noted in Item 2. Properties, reflect 21 refineries, located in 14 countries,(1) References to routine flaring herein are consistent with distillation capacitythe World Bank's Zero Routine Flaring Reduction Partnership's (GGFRP) principle of 4.8 million barrels per day (MBD)routine flaring, and lubricant base stock manufacturing capacity of 129 thousand barrels per day. ExxonMobil’s fuelsexcludes safety and lubes value chains have significant global reach, with multiple channels to market serving a diverse customer base. Our portfolio of world-renowned brands includes Exxon, Mobil, Esso, Synergy, and Mobil 1.non-routine flaring.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | | | | |
| (millions of dollars) | 2022 | | 2021 | | 2020 |
Earnings (loss) (U.S. GAAP) | | | | | |
| United States | 11,728 | | | 3,663 | | | (19,385) | |
| Non-U.S. | 24,751 | | | 12,112 | | | (645) | |
| Total | 36,479 | | | 15,775 | | | (20,030) | |
| | | | | |
Identified Items (1) | | | | | |
| United States | 299 | | | (263) | | | (17,092) | |
| Non-U.S. | (3,238) | | | (280) | | | (2,602) | |
| Total | (2,939) | | | (543) | | | (19,694) | |
| | | | | |
Earnings (loss) excluding Identified Items (1) (Non-GAAP) | | | | | |
| United States | 11,429 | | | 3,926 | | | (2,293) | |
| Non-U.S. | 27,989 | | | 12,392 | | | 1,957 | |
| Total | 39,418 | | | 16,318 | | | (336) | |
| | | | | |
(1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. | | | | | |
|
| | | | | | | | | | | | | | |
| 2022 Upstream Earnings Factor Analysis | | | | |
| (millions of dollars) | | | | |
Fuels demand in 2020 was significantly impacted– Higher realizations increased earnings by the COVID-19 pandemic. During the second quarter downturn, global demand for gasoline, diesel,$21,290 million reflecting tight supply and jet fuel declined about 23 percent versus 2019. While demand partially recovered in the second half of the year, fourth quarter total products demand remained 10 percent below 2019 levels. This unprecedented demand impact adversely affected refining margins resulting in historically low market conditions, with announced refinery closures four times higher than 10-year historical levels. In the near-term, refining margins will continue to be impacted by COVID-19 demand recovery. Finished lubricant demand was also impacted by COVID-19, with ExxonMobil’s estimate of industry demand down 5 to 10 percent versus 2019.
Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery pays for its raw materials and the market prices for the range of products produced. Crude oil and many products are widely traded with published prices, including those quoted on multiple exchanges around the world (e.g., New York Mercantile Exchange and Intercontinental Exchange). Prices for these commodities are determined by the global marketplace and are influenced by many factors, including global and regional supply/demand balances, inventory levels, industry refinery operations, import/export balances, currency fluctuations, seasonal demand, weather, and political climate.
ExxonMobil’s long-term outlook is that industry refining margins will remain volatile subject to shifting consumer demand as well as capacity changes from refinery additions and closures. ExxonMobil’s significant integration both within the Downstream value chains including lubricants, logistics, trading, refining, and marketing, as well as with Upstream and Chemical, improves our ability to generate shareholder value in different market conditions.
As described in Item 1A. Risk Factors, proposed carbon policy and other climate related regulations in many countries, as well as the continued growth in biofuels mandates, could have negative impacts on the Downstream business.
ExxonMobil continually evaluates the Downstream portfolio during all phases of the business cycle, which has resulted in numerous asset divestments over the past decade to strengthen overall profitability and resiliency. When investing in the Downstream, ExxonMobil remains focused on select and resilient projects across a broad range of market conditions. In 2020, the Strathcona Cogeneration project started up to improve refinery energy efficiency and reduce greenhouse gas emissions. In addition, the main segment of the Wink to Webster pipeline system, operated by ExxonMobil Pipeline Company, started transporting Permian crude from Midland to Houston. Finally, deferral costs associated with pacing previously announced Downstream projects will be offset with efficiencies captured during the market downturn.
ExxonMobil continues to grow fuels product sales in new markets near major production assets with continued progress in the Mexico and Indonesia market entries. The lubricants business continues to grow, leveraging world class brands and integration with industry leading basestock refining capability. Through the Mobil branded properties, such as Mobil 1, ExxonMobil is the worldwide leader in synthetic motor oils.
Chemical
ExxonMobil is a major manufacturer and marketer of petrochemicals, including a wide variety of performance products that sustainably support improved living standards around the globe. ExxonMobil sustains its competitive advantage through continued operational excellence, investment and cost discipline, a balanced portfolio of products, and unparalleled integration with Downstream and Upstream operations, all underpinned by proprietary technology.
In 2020, many markets were heavily impacted by COVID-19, however demand for chemical products remained resilient in several key segments including food packaging, hygiene and medical. Overall Chemical margins improved compared to 2019 due to lower feedstock costs, continued strong packagingrecovering demand, and industry supply disruptions through the second halffavorable mark-to-market impacts of 2020. We were uniquely positioned to capture value from the market volatility in 2020 due to our integration, enabling nimble feed and product optimization. This, in addition to our outstanding safety and reliability performance and structural cost improvement, delivered industry leading earnings.
Over the long term, demand for chemical products is forecast to outpace growth in global GDP and energy demand. ExxonMobil estimates that worldwide demand for chemicals will rise by over 40 percent by 2030, driven by continued global population growth and an expanding middle class. ExxonMobil’s integration with refining, together with our high-value performance products and unique project execution capability, enhances our ability to generate industry-leading returns on investments across a range of market environments. In 2020, construction progressed on our joint venture ethane cracker and associated units near Corpus Christi, Texas. The project is below budget and expected to start up ahead of schedule in the fourth quarter of 2021. We made the decision to slow the pace of other U.S. Gulf Coast growth projects, capturing current market efficiencies to offset deferral costs. In addition, we continued to progress plans for a world-scale steam cracker and performance derivative units in Guangdong Province, China.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
REVIEW OF 2020 AND 2019 RESULTS
During the first and second quarters of 2020, the balance of supply and demand for petroleum and petrochemical products experienced two significant disruptive effects. On the demand side, the COVID-19 pandemic spread rapidly through most areas of the world resulting in substantial reductions in consumer and business activity and significantly reduced demand for crude oil, natural gas, and petroleum products. This reduction in demand coincided with announcements of increased production in certain key oil-producing countries which led to increases in inventory levels and sharp declines in prices for crude oil, natural gas, and petroleum products.
Market conditions continued to reflect considerable uncertainty throughout 2020 as consumer and business activity exhibited some degree of recovery, but remained lower when compared to prior periods as a result of the pandemic. Despite actions taken by key oil-producing countries to reduce oversupply, the unfavorable economic impacts are likely to persist to some extent well into 2021.
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| | (millions of dollars) |
| Earnings (Loss) (U.S. GAAP) | | | | | |
| Net income (loss) attributable to ExxonMobil (U.S. GAAP) | (22,440) | | | 14,340 | | | 20,840 | |
| | | | | | | | | | | | | | | | | |
| Upstream | | | | | |
| | 2020 | | 2019 | | 2018 |
| | (millions of dollars) |
| Upstream | | | | | |
| United States | (19,385) | | | 536 | | | 1,739 | |
| Non-U.S. | (645) | | | 13,906 | | | 12,340 | |
| Total | (20,030) | | | 14,442 | | | 14,079 | |
2020
Upstream results were a loss of $20,030 million, down $34,472 million from 2019.
•Lower realizations reduced earnings by $11.2 billion.
•Unfavorable volumeVolume/Mix – Volume and mix effects decreased earnings by $300$110 million. The earnings benefit from volume growth in Guyana and the Permian was offset by the volume loss from divestments, the Russia expropriation, and other impacts including weather-related downtime.
•Other – All other items decreased earnings by $23 billion,$880 million as strong cost control partly offset impacts from inflation and increased activity.
Identified Items(1) – 2021 $(543) million loss as a result of impairments of $19.4 billion$(752) million and the absencecontractual provisions of the $3.7 billion$(250) million, partly offset by a $459 million gain from the 2019 Norway non-operated divestment wereU.K Central and Northern North Sea divestment; 2022 $(2,939) million loss mainly driven by the Russia expropriation $(2,185) million and impacts from additional European taxes $(1,415) million, partly offset by lower expensesgains of $1 billion.$886 million on the sale of the Romania, U.S. Barnett Shale, and XTO Energy Canada assets.
•(1)U.S. Upstream results were a loss Refer to Frequently Used Terms for definition of $19,385 millionIdentified Items and included asset impairments of $17.1 billion.
•Non-U.S. Upstream results were a loss of $645 million, including asset impairments of $2.3 billion and the absence of the $3.7 billion gain from the Norway non-operated divestment.
•On an oil-equivalent basis, production of 3.8 million barrels per day was down 5 percent compared to 2019.
•Liquids production of 2.3 million barrels per day decreased 37,000 barrels per day reflecting the impacts of government mandates, divestments, and lower demand, partly offset by growth and lower downtime.
•Natural gas production of 8.5 billion cubic feet per day decreased 923 million cubic feet per day from 2019, reflecting divestments, lower demand, and higher downtime, partly offset by growth.
2019
Upstream earnings were $14,442 million, up $363 million from 2018.
•Lower realizations reduced earnings by $2.7 billion.
•Favorable volume and mix effects increased earnings by $860 million.
•All other items increased earnings by $2.2 billion, as a $3.7 billion gain from the Norway non-operated divestment was partly offset by higher expenses of $1.1 billion.
•U.S. Upstream earnings were $536 million and included asset impairments of $146 million.
•Non-U.S. Upstream earnings were $13,906 million, including the $3.7 billion gain from the Norway non-operated divestment.
•On an oil-equivalent basis, production of 4.0 million barrels per day was up 3 percent compared to 2018.
•Liquids production of 2.4 million barrels per day increased 120,000 barrels per day reflecting growth and higher entitlements.
•Natural gas production of 9.4 billion cubic feet per day decreased 11 million cubic feet per day from 2018, with the impact from divestments and higher downtime offset by growth and higher entitlements.(loss) excluding Identified Items.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | |
| 2021 Upstream Earnings Factor Analysis | | | | |
| (millions of dollars) | | | | |
Volume/Mix – Unfavorable volume and mix effects decreased earnings by $340 million.
Other – All other items increased earnings by $2,040 million, primarily driven by lower expenses of $1,360 million and one-time favorable tax items.
Identified Items(1) – 2020 $(19,694) million loss primarily reflected impairments of dry gas assets; 2021 $(543) million loss was as a result of impairments of $(752) million and contractual provisions of $(250) million, partly offset by a $459 million gain from the U.K Central and Northern North Sea divestment.
(1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items.
| | | | | | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 | | 2020 | | | | |
Net production of crude oil, natural gas liquids, bitumen and synthetic oil (thousands of barrels daily) | | | | | | | | | |
| United States | 776 | | 721 | | 685 | | | | |
| Canada/Other Americas | 588 | | 560 | | 536 | | | | |
| Europe | 4 | | 22 | | 30 | | | | |
| Africa | 238 | | 248 | | 312 | | | | |
| Asia | 705 | | 695 | | 742 | | | | |
| Australia/Oceania | 43 | | 43 | | 44 | | | | |
| Worldwide | 2,354 | | 2,289 | | 2,349 | | | | |
| | | | | | | | | |
Net natural gas production available for sale (millions of cubic feet daily) | | | | | | | | | |
| United States | 2,551 | | 2,746 | | 2,691 | | | | |
| Canada/Other Americas | 148 | | 195 | | 277 | | | | |
| Europe | 667 | | 808 | | 789 | | | | |
| Africa | 71 | | 43 | | 9 | | | | |
| Asia | 3,418 | | 3,465 | | 3,486 | | | | |
| Australia/Oceania | 1,440 | | 1,280 | | 1,219 | | | | |
| Worldwide | 8,295 | | 8,537 | | 8,471 | | | | |
| | | | | | | | | |
Oil-equivalent production (2) (thousands of oil-equivalent barrels daily) | 3,737 | | 3,712 | | 3,761 | | | | |
| | | | | | | | | |
(2) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. | | | | |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | Upstream Additional Information | Upstream Additional Information | | | | Upstream Additional Information | | | |
| | 2020 | | 2019 | |
| | (thousands of barrels daily) | |
| (thousands of barrels daily) | | (thousands of barrels daily) | 2022 | | 2021 |
Volumes Reconciliation (Oil-equivalent production) (1) | Volumes Reconciliation (Oil-equivalent production) (1) | | | | Volumes Reconciliation (Oil-equivalent production) (1) | | | |
| Prior Year | Prior Year | 3,952 | | | 3,833 | | Prior Year | 3,712 | | | 3,761 | |
| Entitlements - Net Interest | Entitlements - Net Interest | (9) | | | (1) | | Entitlements - Net Interest | (44) | | | (1) | |
| Entitlements - Price / Spend / Other | Entitlements - Price / Spend / Other | 67 | | | 34 | | Entitlements - Price / Spend / Other | (34) | | | (97) | |
| Government Mandates | Government Mandates | (110) | | | (3) | | Government Mandates | 80 | | | 8 | |
| Divestments | Divestments | (151) | | | (27) | | Divestments | (71) | | | (24) | |
| Growth / Other | Growth / Other | 12 | | | 116 | | Growth / Other | 94 | | | 65 | |
| Current Year | Current Year | 3,761 | | | 3,952 | | Current Year | 3,737 | | | 3,712 | |
| | (1) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. | (1) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. | (1) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. |
| | | | | |
| 2022 versus 2021 | 2022 production of 3.7 million oil-equivalent barrels per day increased 25 thousand barrels per day from 2021. Growth in the Permian and Guyana, and easing government-mandated curtailments more than offset the impacts from divestments, the Russia expropriation, and lower entitlements due to higher prices. |
| 2021 versus 2020 | 2021 production of 3.7 million oil-equivalent barrels per day decreased 49 thousand barrels per day from 2020, as higher demand and growth were more than offset by lower entitlements due to higher prices, decline, and divestments. |
Listed below are descriptions of ExxonMobil’s volumes reconciliation factors, which are provided to facilitate understanding of the terms.
Entitlements - Net Interest are changes to ExxonMobil’s share of production volumes caused by non-operational changes to volume-determining factors. These factors consist of net interest changes specified in Production Sharing Contracts (PSCs), which typically occur when cumulative investment returns or production volumes achieve defined thresholds, changes in equity upon achieving pay-out in partner investment carry situations, equity redeterminations as specified in venture agreements, or as a result of the termination or expiry of a concession. Once a net interest change has occurred, it typically will not be reversed by subsequent events, such as lower crude oil prices.
Entitlements - Price, Spend and Other are changes to ExxonMobil’s share of production volumes resulting from temporary changes to non-operational volume-determining factors. These factors include changes in oil and gas prices or spending levels from one period to another. According to the terms of contractual arrangements or government royalty regimes, price or spending variability can increase or decrease royalty burdens and/or volumes attributable to ExxonMobil. For example, at higher prices, fewer barrels are required for ExxonMobil to recover its costs. These effects generally vary from period to period with field spending patterns or market prices for oil and natural gas. Such factors can also include other temporary changes in net interest as dictated by specific provisions in production agreements.
Government Mandates are changes to ExxonMobil's sustainable production levels due toas a result of temporary non-operational production limits or sanctions imposed by governments, generally upon a country, sector, type or method of production.
Divestments are reductions in ExxonMobil’s production arising from commercial arrangements to fully or partially reduce equity in a field or asset in exchange for financial or other economic consideration.
Growth and Other factors comprise all other operational and non-operational factors not covered by the above definitions that may affect volumes attributable to ExxonMobil. Such factors include, but are not limited to, production enhancements from project and work program activities, acquisitions including additions from asset exchanges, downtime, market demand, natural field decline, and any fiscal or commercial terms that do not affect entitlements.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | | | | |
| Downstream | | |
| | 2020 | | 2019 | | 2018 |
| | (millions of dollars) |
| Downstream | | | | | |
| United States | (852) | | | 1,717 | | | 2,962 | |
| Non-U.S. | (225) | | | 606 | | | 3,048 | |
| Total | (1,077) | | | 2,323 | | | 6,010 | |
2020
Downstream results of a $1,077 million loss decreased $3,400 million from 2019.
•Margins decreased earnings by $3.8 billion including the impact of weaker industry refining conditions.
•Volume and mix effects increased earnings by $370 million as manufacturing/yield improvement impacts were partly offset by weaker demand.
•All other items increased earnings by $50 million, as lower expenses of $1.3 billion were offset by impairments of $620 million, unfavorable LIFO inventory impacts of $410 million, and unfavorable tax items of $240 million.
•U.S. Downstream results were a loss of $852 million, compared to earnings of $1,717 million in the prior year.
•Non-U.S. Downstream results were a loss of $225 million, compared to earnings of $606 million in the prior year.
•Petroleum product sales of 4.9 million barrels per day were 557,000 barrels per day lower than 2019.
2019
Downstream earnings of $2,323 million decreased $3,687 million from 2018.
•Margins decreased earnings by $3 billion including the impact of lower North American crude differentials.
•Volume and mix effects lowered earnings by $50 million as project contributions and portfolio improvement were more than offset by increased downtime/maintenance and unfavorable yield/sales mix.
•All other items decreased earnings by $660 million, mainly driven by the absence of prior year divestment gains and higher expenses reflecting increased maintenance and project startups, partly offset by favorable foreign exchange impacts and LIFO inventory gains.
•U.S. Downstream earnings were $1,717 million, compared to $2,962 million in the prior year.
•Non-U.S. Downstream earnings were $606 million, compared to $3,048 million in the prior year.
•Petroleum product sales of 5.5 million barrels per day were 60,000 barrels per day lower than 2018.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | | | | |
| Chemical | | |
| | 2020 | | 2019 | | 2018 |
| | (millions of dollars) |
| Chemical | | | | | |
| United States | 1,277 | | | 206 | | | 1,642 | |
| Non-U.S. | 686 | | | 386 | | | 1,709 | |
| Total | 1,963 | | | 592 | | | 3,351 | |
2020
Chemical earnings of $1,963 million increased $1,371 million from 2019.
•Stronger margins increased earnings by $930 million.
•Volume and mix effects decreased earnings by $150 million.
•All other items increased earnings by $590 million as lower expenses of $710 million were partly offset by unfavorable one-time items, mainly impairments.
•U.S. Chemical earnings were $1,277 million in 2020, compared with $206 million in the prior year.
•Non-U.S. Chemical earnings were $686 million, compared with $386 million in the prior year.
•Prime product sales of 25.4 million metric tons were down 1.1 million metric tons from 2019.
2019
Chemical earnings of $592 million decreased $2,759 million from 2018.
•Weaker margins decreased earnings by $1.8 billion.
•Volume and mix effects were essentially flat, as lower sales volumes were offset by new asset contributions.
•All other items decreased earnings by $940 million, primarily due to higher expenses associated with new assets, business growth, and maintenance activity, the absence of a favorable tax item in the prior year, and unfavorable foreign exchange impacts.
•U.S. Chemical earnings were $206 million in 2019, compared with $1,642 million in the prior year.
•Non-U.S. Chemical earnings were $386 million, compared with $1,709 million in the prior year.
•Prime product sales of 26.5 million metric tons were down 0.4 million metric tons from 2018.
| | | | | | | | | | | | | | | | | |
| Corporate and Financing | | |
| | 2020 | | 2019 | | 2018 |
| | (millions of dollars) |
| Corporate and financing | (3,296) | | | (3,017) | | | (2,600) | |
2020
Corporate and financing expenses were $3,296 million in 2020 compared to $3,017 million in 2019, with the increase mainly due to higher financing costs and employee severance costs, partly offset by lower corporate costs.
2019
Corporate and financing expenses were $3,017 million in 2019 compared to $2,600 million in 2018, with the increase mainly due to unfavorable tax impacts and higher financing costs.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ExxonMobil's Energy Products is one of the largest, most integrated businesses of its kind among international oil companies, with significant representation across the entire fuels value chain including refining, logistics, trading, and marketing. This segment brings fuels and aromatics value chains together, recognizing their history of working closely to optimize manufacturing sites, and includes catalysts and licensing.
With the largest refining footprint among international oil companies, ExxonMobil’s Energy Products earnings are closely tied to industry refining margins. Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery pays for its raw materials and the market prices for the products produced. Crude oil and many products are widely traded with published prices, including those quoted on multiple exchanges around the world (e.g. New York Mercantile Exchange and Intercontinental Exchange). Prices for these commodities are determined by the global marketplace and are influenced by many factors, including global and regional supply/demand balances, inventory levels, industry refinery operations, import/export balances, currency fluctuations, seasonal demand, weather, and political considerations. While industry refining margins significantly impact Energy Products earnings, strong operations performance, product mix optimization, and disciplined cost control are also critical to strong financial performance.
Refining margins increased sharply in 2022, well above the top of the 10-year historical range (2010–2019). Demand for gasoline and diesel recovered to pre-pandemic levels, while jet fuel demand remained below historical levels reflecting continued COVID-19 impacts. Refinery shutdowns and lack of investments driven by the pandemic reduced industry capacity and resulted in a tight market.
Refining margins are anticipated to remain volatile in the near term as a result of significant global factors including China demand recovery and export quotas, recession fears, impacts from price caps and sanctions, low inventory levels, and new refining capacity additions.
Key Recent Events
Future capacity additions: The company mechanically completed its Beaumont Refinery expansion. This expansion will bring 250,000 barrels per day of crude distillation capacity to the market in first quarter 2023.
Strathcona Renewable Diesel Project: Progressed 20,000 barrels per day renewable diesel project, culminating in final investment decision in January 2023 for the largest such facility in Canada.
Billings divestment(1): In October 2022, ExxonMobil and its affiliates reached an agreement with Par Pacific Holdings for the sale of the Billings Refinery and select midstream assets in Montana and Washington.
Italy Fuels divestment(1): In December 2022, ExxonMobil reached an agreement with Italiana Petroli to sell its interest in the Trecate Refinery joint venture, select midstream assets, and the fuels marketing business.
Esso Thailand divestment(1): In January 2023, ExxonMobil reached an agreement with Bangchak Corporation to sell its interest in Esso Thailand, which includes the Sriracha Refinery, select distribution terminals, and a network of Esso-branded retail stations.
(1) The Corporation expects the transactions to close in 2023.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Energy Products Financial Results
| | | | | | | | | | | | | | | | | |
| (millions of dollars) | 2022 | | 2021 | | 2020 |
Earnings (loss) (U.S. GAAP) | | | | | |
| United States | 8,340 | | | 668 | | | (1,342) | |
| Non-U.S. | 6,626 | | | (1,014) | | | (1,230) | |
| Total | 14,966 | | | (347) | | | (2,572) | |
| | | | | |
Identified Items (1) | | | | | |
| United States | (58) | | | — | | | (4) | |
| Non-U.S. | (626) | | | — | | | (636) | |
| Total | (684) | | | — | | | (640) | |
| | | | | |
Earnings (loss) excluding Identified Items (1) (Non-GAAP) | | | | | |
| United States | 8,398 | | | 668 | | | (1,338) | |
| Non-U.S. | 7,252 | | | (1,014) | | | (594) | |
| Total | 15,650 | | | (347) | | | (1,932) | |
| | | | | |
(1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. | | | | | |
| Due to rounding, numbers presented may not add up precisely to the totals indicated. |
|
| | | | | | | | | | | | | | |
| 2022 Energy Products Earnings Factor Analysis | | | | |
| (millions of dollars) | | | | |
Volume/Mix – Increased earnings by $1,060 million reflecting improved product yields and higher throughput.
Other – Increased earnings by $570 million due to favorable foreign exchange and year-end inventory effects.
Identified Items(1)– 2022 $(684) million loss was driven by additional European taxes on the energy sector and impairments.
(1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items.
| | | | | | | | | | | | | | | | | |
| LIQUIDITY AND CAPITAL RESOURCES | | | | |
| Sources and Uses of Cash | | |
| | 2020 | | 2019 | | 2018 |
| | (millions of dollars) |
| Net cash provided by/(used in) | | | | | |
| Operating activities | 14,668 | | | 29,716 | | | 36,014 | |
| Investing activities | (18,459) | | | (23,084) | | | (16,446) | |
| Financing activities | 5,285 | | | (6,618) | | | (19,446) | |
| Effect of exchange rate changes | (219) | | | 33 | | | (257) | |
| Increase/(decrease) in cash and cash equivalents | 1,275 | | | 47 | | | (135) | |
| | | | | |
| | (December 31) |
| Total cash and cash equivalents | 4,364 | | | 3,089 | | | 3,042 | |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | |
| 2021 Energy Products Earnings Factor Analysis | | | | |
| (millions of dollars) | | | | |
Margins– Increased earnings by $1,360 million as industry refining conditions improved.
Volume/Mix – Decreased earnings by $90 million reflecting higher planned maintenance.
Other – Increased earnings by $320 million due to lower expenses, partly offset by unfavorable foreign exchange impacts.
Identified Items(1)– 2020 $(640) million loss was primarily as a result of impairments and unfavorable tax items.
(1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items.
Energy Products Operational Results
| | | | | | | | | | | | | | | | | | | | | | | | |
| (thousands of barrels daily) | | 2022 | | 2021 | | 2020 | | | | |
| Refinery throughput | | | | | | | | | | |
| United States | | 1,702 | | 1,623 | | 1,549 | | | | |
| Canada | | 418 | | 379 | | 340 | | | | |
| Europe | | 1,192 | | 1,210 | | 1,173 | | | | |
| Asia Pacific | | 539 | | 571 | | 553 | | | | |
| Other | | 179 | | 162 | | 158 | | | | |
| Worldwide | | 4,030 | | 3,945 | | 3,773 | | | | |
| | | | | | | | | | |
Energy Products sales (2) | | | | | | | | | | |
| United States | | 2,426 | | 2,267 | | 2,159 | | | | |
| Non-U.S. | | 2,921 | | 2,863 | | 2,704 | | | | |
| Worldwide | | 5,347 | | 5,130 | | 4,863 | | | | |
| | | | | | | | | | |
| Gasoline, naphthas | | 2,232 | | 2,158 | | 1,994 | | | | |
| Heating oils, kerosene, diesel | | 1,774 | | 1,749 | | 1,751 | | | | |
| Aviation fuels | | 338 | | 220 | | 213 | | | | |
| Heavy fuels | | 235 | | 269 | | 249 | | | | |
| Other energy products | | 768 | | 734 | | 656 | | | | |
| Worldwide | | 5,347 | | 5,130 | | 4,863 | | | | |
| | | | | | | | | | |
(2) Data reported net of purchases/sales contracts with the same counterparty. | | | | |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ExxonMobil is a leading global manufacturer and marketer of petrochemicals that support modern living. Chemical Products helps meet society’s evolving needs by providing a wide range of innovative, valuable products in an efficient and responsible manner. This is supported by our unique combination of industry-leading scale and integration along with ExxonMobil’s proprietary technology, which is fundamental to producing performance products that enable lighter, more durable solutions that use less material, save energy, and reduce costs and waste. These competitive advantages are underpinned by operational excellence, advantaged investments, and cost discipline. This segment includes olefins, polyolefins, and intermediates.
Over the long term, worldwide demand for chemicals is expected to grow faster than the economy as a whole, driven by global population growth, an expanding middle class, and improving living standards. Chemical Products integration with refineries, performance product mix, and project execution capability improves returns on investments across a range of market environments.
In 2022, chemical industry margins decreased, falling below the 10-year historical range (2010-2019), reflecting bottom-of-cycle conditions in Asia Pacific, increased industry capacity, and the closure of the regional pricing disconnect between Asia and the Atlantic Basin. Despite the decline in industry margins, Chemical Products earnings remained above the segment’s 10-year average, benefiting from strong reliability, expense management, and mix of performance products.
Key Recent Events
Polypropylene expansion: ExxonMobil successfully started up a new polypropylene unit in Baton Rouge, Louisiana. This increased capacity by 450,000 metric tons per year, meeting growing demand for high-performance, lightweight, and durable plastics.
Advanced recycling: ExxonMobil started up one of North America’s largest advanced recycling units at our integrated manufacturing complex in Baytown, Texas. This facility uses proprietary technology to break down hard-to-recycle plastics and transform them into raw materials for new products. It is capable of processing more than 80 million pounds of plastic waste per year, supporting a circular economy for post-use plastics and helping divert plastic waste currently sent to landfills.
Future capacity additions: ExxonMobil is making additional, long-term chemical investments with our Chemical expansion in Baytown, Texas, which will produce performance chemicals such as Vistamaxx™ polymers and Elevexx™ linear alpha olefins, and in China, where we continue to progress construction of our multi-billion dollar chemical complex in the Dayawan Petrochemical Industrial Park in Huizhou, Guangdong Province.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Chemical Products Financial Results
| | | | | | | | | | | | | | | | | |
| (millions of dollars) | 2022 | | 2021 | | 2020 |
Earnings (loss) (U.S. GAAP) | | | | | |
| United States | 2,328 | | | 3,697 | | | 1,196 | |
| Non-U.S. | 1,215 | | | 3,292 | | | 1,061 | |
| Total | 3,543 | | | 6,989 | | | 2,257 | |
| | | | | |
Identified Items (1) | | | | | |
| United States | — | | | — | | | (90) | |
| Non-U.S. | — | | | — | | | (15) | |
| Total | — | | | — | | | (105) | |
| | | | | |
Earnings (loss) excluding Identified Items (1) (Non-GAAP) | | | | | |
| United States | 2,328 | | | 3,697 | | | 1,286 | |
| Non-U.S. | 1,215 | | | 3,292 | | | 1,076 | |
| Total | 3,543 | | | 6,989 | | | 2,362 | |
| | | | | |
(1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. |
|
| | | | | |
| | | | | | | | | | | | | | |
| 2022 Chemical Products Earnings Factor Analysis | | | | |
| (millions of dollars) | | | | |
Margins– Lower margins decreased earnings by $3,030 million with normalization of regional prices during the year, increased supply, and bottom-of-cycle conditions in Asia Pacific.
Volume/Mix – Product mix decreased earnings by $170 million.
Other – All other items decreased earnings by $250 million primarily as a result of higher expenses from production capacity additions, and foreign exchange effects from a stronger U.S. dollar.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | |
| 2021 Chemical Products Earnings Factor Analysis | | | | |
| (millions of dollars) | | | | |
Margins– Stronger margins increased earnings by $4,370 million.
Volume/Mix – Higher volumes increased earnings by $130 million.
Other – All other items increased earnings by $130 million primarily as a result of lower expenses.
Identified Items(1) – 2020 $(105) million loss was driven by impairments.
(1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items.
Chemical Products Operational Results
| | | | | | | | | | | | | | | | | | | | |
| (thousands of metric tons) | | 2022 | | 2021 | | 2020 |
Chemical prime product sales (2) | | | | | | |
| United States | | 7,270 | | | 7,017 | | | 6,602 | |
| Non-U.S. | | 11,897 | | | 12,126 | | | 12,186 | |
| Worldwide | | 19,167 | | | 19,142 | | | 18,787 | |
| | | | | | |
(2) Data reported net of purchases/sales contracts with the same counterparty. |
| Due to rounding, numbers presented may not add up precisely to the totals indicated. | | | | | | |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ExxonMobil Specialty Products is a combination of business units that manufacture and market a range of performance products including high-quality lubricants, basestocks, waxes, synthetics, elastomers, and resins. Leveraging ExxonMobil’s proprietary technologies, Specialty Products focuses on providing performance products that help customers improve efficiency in the transportation and industrial sectors.
Demand for lubricants is expected to remain strong and grow in the industrial, aviation, and marine sectors. Specialty Products is well-positioned to help meet that demand through advantaged projects that leverage ExxonMobil's integration and world-class brands, such as Mobil 1.
In 2021, ExxonMobil completed the acquisition of Materia, a U.S.-based specialty chemical company. This business, built on proprietary technology, is now a part of the Specialty Products segment. Materia’s new class of polymers has properties well-suited for infrastructure, oil and gas, and mobility segments, notably wind turbine blades, steel rebar replacement, and anti-corrosion paints. Plans are being progressed to bring the product to market at scale.
Key Recent Events
Singapore Resid Upgrade Project: Progressed project which will leverage two proprietary technologies to upgrade fuel oil to Group II lubes and clean products, further strengthening ExxonMobil’s position as the largest basestock producer in the world.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Specialty Products Financial Results
| | | | | | | | | | | | | | | | | |
| (millions of dollars) | 2022 | | 2021 | | 2020 |
Earnings (loss) (U.S. GAAP) | | | | | |
| United States | 1,190 | | | 1,452 | | | 571 | |
| Non-U.S. | 1,225 | | | 1,807 | | | 630 | |
| Total | 2,415 | | | 3,259 | | | 1,201 | |
| | | | | |
Identified Items (1) | | | | | |
| United States | — | | | 498 | | | — | |
| Non-U.S. | (40) | | | 136 | | | (228) | |
| Total | (40) | | | 634 | | | (228) | |
| | | | | |
Earnings (loss) excluding Identified Items (1) (Non-GAAP) | | | | | |
| United States | 1,190 | | | 954 | | | 571 | |
| Non-U.S. | 1,265 | | | 1,672 | | | 858 | |
| Total | 2,455 | | | 2,625 | | | 1,429 | |
| | | | | |
(1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. | | | | | |
| Due to rounding, numbers presented may not add up precisely to the totals indicated. | | | | | |
|
|
| | | | | | | | | | | | | | |
| 2022 Specialty Products Earnings Factor Analysis | | | | |
| (millions of dollars) | | | | |
Margins– Margins decreased earnings by $220 million driven by higher feed costs and energy prices.
Volume/Mix – Higher volumes increased earnings by $20 million on robust demand.
Other – All other items increased earnings by $30 million primarily as a result of positive year-end inventory effects, offset by increased expenses from higher maintenance and inflation, and unfavorable foreign exchange impacts.
Identified Items(1) – 2021 $634 million gain resulted from the Santoprene divestment; 2022 $(40) million loss from impairments.
(1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | |
| 2021 Specialty Products Earnings Factor Analysis | | | | |
| (millions of dollars) | | | | |
Margins– Stronger margins, particularly for basestocks, increased earnings by $680 million.
Volume/Mix – Higher volumes increased earnings by $300 million.
Other – All other items increased earnings by $220 million primarily as a result of lower expenses.
Identified Items (1) – 2020 $(228) million loss was driven by impairments; 2021 $634 million gain came from the Santoprene divestment.
(1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items.
Specialty Products Operational Results
| | | | | | | | | | | | | | | | | | | | |
| (thousands of metric tons) | | 2022 | | 2021 | | 2020 |
Specialty Products sales (2) | | | | | | |
| United States | | 2,049 | | | 1,943 | | | 1,897 | |
| Non-U.S. | | 5,762 | | | 5,723 | | | 5,340 | |
| Worldwide | | 7,810 | | | 7,666 | | | 7,237 | |
| | | | | | |
(2) Data reported net of purchases/sales contracts with the same counterparty. |
| Due to rounding, numbers presented may not add up precisely to the totals indicated. | | | | | | |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Corporate and Financing is comprised of corporate activities that support the Corporation’s operating segments and ExxonMobil’s Low Carbon Solutions business. Corporate activities include general administrative support functions, financing and insurance activities. Low Carbon Solutions activities will be included in Corporate and Financing until the business is established with a material level of assets and customer contracts.
Corporate and Financing Financial Results
| | | | | | | | | | | | | | | | | |
| (millions of dollars) | 2022 | | 2021 | | 2020 |
| Earnings (loss) (U.S. GAAP) | (1,663) | | | (2,636) | | | (3,296) | |
Identified Items (1) | 302 | | | (64) | | | (361) | |
Earnings (loss) excluding Identified Items (1) (Non-GAAP) | (1,965) | | | (2,572) | | | (2,935) | |
| | | | | |
(1) Refer to Frequently Used Terms for definition of Identified Items and earnings (loss) excluding Identified Items. |
| | | | | |
| 2022 | Corporate and Financing expenses were $1,663 million in 2022 compared to $2,636 million in 2021, with the decrease mainly due to lower pension-related expenses, favorable one-time tax impacts, and lower financing costs. |
| 2021 | Corporate and Financing expenses were $2,636 million in 2021 compared to $3,296 million in 2020, with the decrease mainly due to the absence of prior year severance costs and lower financing costs. |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
| | | | | | | | | | | | | | | | | |
| Sources and Uses of Cash | | |
| (millions of dollars) | 2022 | | 2021 | | 2020 |
| Net cash provided by/(used in) | | | | | |
| Operating activities | 76,797 | | | 48,129 | | | 14,668 | |
| Investing activities | (14,742) | | | (10,235) | | | (18,459) | |
| Financing activities | (39,114) | | | (35,423) | | | 5,285 | |
| Effect of exchange rate changes | (78) | | | (33) | | | (219) | |
| Increase/(decrease) in cash and cash equivalents | 22,863 | | | 2,438 | | | 1,275 | |
| | | | | |
| Total cash and cash equivalents (December 31) | 29,665 | | | 6,802 | | | 4,364 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Total cash and cash equivalents were $4.4$29.7 billion at the end of 2020,2022, up $1.3$22.9 billion from the prior year. The major sources of funds in 2020 were the adjustment for the noncash provision of $46.0 billion for depreciation and depletion, a net debt increase of $20.1 billion, proceeds from asset sales of $1.0 billion, and other investing activities of $2.7 billion. The major uses of funds included a net loss including noncontrolling interests of $23.3 billion, spending for additions to property, plant and equipment of $17.3 billion, dividends to shareholders of $14.9 billion, and additional investments and advances of $4.9 billion.
Total cash and cash equivalents were $3.1 billion at the end of 2019, up $47 million from the prior year. The major sources of funds in 20192022 were net income including noncontrolling interests of $14.8$57.6 billion, the adjustment for the noncash provision of $19.0$24.0 billion for depreciation and depletion, a net debt increase of $8.7 billion, and proceeds from asset sales of $3.7$5.2 billion, and other investing activities of $1.5 billion. The major uses of funds included spending for additions to property, plant and equipment of $24.4 billion,$18.4 billion; dividends to shareholders of $14.7 billion,$14.9 billion; the purchase of ExxonMobil stock of $15.2 billion; a debt reduction of $7.2 billion; and additional investments and advances of $3.9$3.1 billion.
Total cash and cash equivalents were $6.8 billion at the end of 2021, up $2.4 billion from the prior year. The major sources of funds in 2021 were net income including noncontrolling interests of $23.6 billion, the adjustment for the noncash provision of $20.6 billion for depreciation and depletion, contributions from operational working capital of $4.2 billion, proceeds from asset sales of $3.2 billion, and other investing activities of $1.5 billion. The major uses of funds included a debt reduction of $19.7 billion; spending for additions to property, plant and equipment of $12.1 billion; dividends to shareholders of $14.9 billion; and additional investments and advances of $2.8 billion.
The Corporation has access to significant capacity of long-term and short-term liquidity. Commercial paper continuesInternally generated funds are expected to providecover the majority of financial requirements, supplemented by long-term and short-term liquidity, and is reflected in “Notes and loans payable” on the Consolidated Balance Sheet with changes in outstanding commercial paper between periods included in the Consolidated Statement of Cash Flows. The Corporation took steps to strengthen its liquidity in 2020, including issuing $23.2 billion of long-term debt and implementing significant capital and operating cost reductions. The Corporation ended the year with $68 billion in gross debt and intends to reduce debt over time.debt. On December 31, 2020,2022, the Corporation had unusedundrawn short-term committed lines of credit of $11.3$0.3 billion and no unusedundrawn long-term lines of credit.credit of $1.2 billion.
To support cash flows in future periods, the Corporation will need to continually find or acquire and develop new fields, and continue to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production. After a period of production at plateau rates, it is the nature of oil and gas fields to eventually to produce at declining rates for the remainder of their economic life. Decline rates can vary widely by individual field due to a number of factors, including, but not limited to, the type of reservoir, fluid properties, recovery mechanisms, work activity, and age of the field. In particular, the Corporation’s key tight-oil plays have higher initial decline rates which tend to moderate over time. Furthermore, the Corporation’s net interest in production for individual fields can vary with price and the impact of fiscal and commercial terms.
The Corporation has long been successful at mitigating the effects of natural field decline through disciplined investments in quality opportunities and project execution. The Corporation anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups; operational outages; reservoir performance; 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; and changes in the amount and timing of investments that may vary depending on the oil and gas price environment.environment; and international trade patterns and relations. The Corporation’s cash flows are also highly dependent on crude oil and natural gas prices. Please refer to Item 1A. Risk Factors for a more complete discussion of risks.
The Corporation’s financial strength enables it to make large, long-term capital expenditures. Capital and exploration expenditures in 20202022 were $21.4$22.7 billion, reflecting the Corporation’s continued active investment program. The Corporation is prioritizing opportunitiesplans to hold 2021 capital spendinginvest in athe range of $16$23 billion to $19 billion.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Actual spending could vary depending on the progress of individual projects and property acquisitions. The Corporation has a large and diverse portfolio of development projects and exploration opportunities, which helps mitigate the overall political and technical risks of the Corporation’s Upstream segment and associated cash flow. Further, due to its financial strength and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Corporation’s liquidity or ability to generate sufficient cash flows for operations and its fixed commitments.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Corporation, as part of its ongoing asset management program, continues to evaluate its mix of assets for potential upgrade. Because of the ongoing nature of this program, dispositions will continue to be made from time to time which will result in either gains or losses. In light of the current low commodity price environment, and depending on the extent and pace of recovery, the Corporation's planned divestment program could be adversely affected by fewer financially suitable buyers. This could result in a slowing of the pace of divestments, certain assets being sold at a price below current book value, or impairment charges if the likelihood of divesting certain assets increases. Additionally, the Corporation continues to evaluate opportunities to enhance its business portfolio through acquisitions of assets or companies, and enters into such transactions from time to time. Key criteria for evaluating acquisitions include strategic fit, potential for future growth and attractive current valuations. Acquisitions may be made with cash, shares of the Corporation’s common stock, or both.
ExxonMobil closely monitors the potential impactsimpact of Brexit and Interbank Offered Rate (IBOR) reforms,reform, including LIBOR, under a number of scenarios and has taken steps to mitigate theirthe potential impact. Accordingly, ExxonMobil does not believe these events representthis event represents a material risk to the Corporation’s consolidated results of operations or financial condition.
Cash Flow from Operating Activities
20202022
Cash provided by operating activities totaled $14.7$76.8 billion in 2020, $15.02022, $28.7 billion lowerhigher than 2019. Net income (loss) including noncontrolling interests was a loss of $23.3 billion, a decrease of $38.0 billion. The noncash provision for depreciation and depletion was $46.0 billion, up $27.0 billion from the prior year, mainly due to asset impairments. The noncash provision for deferred income tax benefits was $8.9 billion and also included impacts from asset impairments. The adjustment for the net loss on asset sales was $4 million, a decrease of $1.7 billion. The adjustment for dividends received less than equity in current earnings of equity companies was an increase of $1.0 billion, compared to a reduction of $0.9 billion in 2019. Changes in operational working capital, excluding cash and debt, decreased cash in 2020 by $1.7 billion.
2019
Cash provided by operating activities totaled $29.7 billion in 2019, $6.3 billion lower than 2018.2021. The major source of funds was net income including noncontrolling interests of $14.8$57.6 billion, a decreasean increase of $6.6$34.0 billion. The noncash provision for depreciation and depletion was $19.0$24.0 billion, up $0.3$3.4 billion from the prior year. The adjustment for the net gain on asset sales was $1.7$1.0 billion, a decrease of $0.3$0.2 billion. The adjustment for dividends received less than equity in current earnings of equity companies was a reduction of $0.9$2.4 billion, compared to a reduction of $1.7$0.7 billion in 2018.2021. Changes in operational working capital, excluding cash and debt, decreased cash in 2022 by $0.2 billion.
2021
Cash provided by operating activities totaled $48.1 billion in 2021, $33.5 billion higher than 2020. The major source of funds was net income including noncontrolling interests of $23.6 billion, an increase of $46.8 billion. The noncash provision for depreciation and depletion was $20.6 billion, down $25.4 billion from the prior year. The adjustment for the net gain on asset sales was $1.2 billion, an increase of $1.2 billion. The adjustment for dividends received less than equity in current earnings of equity companies was a reduction of $0.7 billion, compared to a reduction of $1.0 billion in 2020. Changes in operational working capital, excluding cash and debt, increased cash in 20192021 by $0.9$4.2 billion.
Cash Flow from Investing Activities
20202022
Cash used in investing activities netted to $18.5$14.7 billion in 2020, $4.62022, $4.5 billion lowerhigher than 2019.2021. Spending for property, plant and equipment of $17.3$18.4 billion decreased $7.1increased $6.3 billion from 2019.2021. Proceeds associated with sales of subsidiaries, property, plant and equipment, andfrom asset sales and returns of investments of $1.0$5.2 billion compared to $3.7$3.2 billion in 2019.2021. Additional investments and advances were $1.0$0.3 billion higher in 2020,2022, while proceeds from other investing activities including collection of advances increased by $1.2 billion.were $1.5 billion during the year.
20192021
Cash used in investing activities netted to $23.1$10.2 billion in 2019, $6.62021, $8.2 billion higherlower than 2018.2020. Spending for property, plant and equipment of $24.4$12.1 billion increased $4.8decreased $5.2 billion from 2018.2020. Proceeds associated with sales of subsidiaries, property, plant and equipment, andfrom asset sales and returns of investments of $3.7$3.2 billion compared to $4.1$1.0 billion in 2018.2020. Additional investments and advances were $1.9$2.0 billion higherlower in 2019,2021, while proceeds from other investing activities including collection of advances increaseddecreased by $0.5$1.2 billion.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Cash Flow from Financing Activities
20202022
Cash flow fromused in financing activities was $5.3$39.1 billion in 2020, $11.92022, $3.7 billion higher than 2019.2021. Dividend payments on common shares increased to $3.48$3.55 per share from $3.43$3.49 per share and totaled $14.9 billion. During 2020,2022, the Corporation issued $23.2 billion of long-term debt. Totalutilized cash to reduce debt increased $20.7 billion to $67.6 billion at year-end.by $7.2 billion.
ExxonMobil share of equity decreased $34.5increased $26.5 billion to $157.2$195.0 billion. The reductionaddition to equity for lossesearnings was $22.4 billion and the reduction$55.7 billion. This was offset by reductions for distributionsdividends to ExxonMobil shareholders wasof $14.9 billion, all in the form of dividends.billion. Foreign exchange translation effects of $1.8$3.1 billion for the weakerstronger U.S. dollar reduced equity, and a $1.0$3.6 billion change in the funded status of the postretirement benefits reserves increased equity.
During 2020,2022, Exxon Mobil Corporation acquired 8restarted its share repurchase program for up to $50 billion in shares through 2024, including the purchase of 162 million shares at a cost of its$15 billion in 2022.
2021
Cash flow from financing activities was $35.4 billion in 2021, $40.7 billion higher than 2020. Dividend payments on common stockshares increased to $3.49 per share from $3.48 per share and totaled $14.9 billion. During 2021, the Corporation utilized cash to reduce debt by $19.7 billion.
ExxonMobil share of equity increased $11.4 billion to $168.6 billion. The addition to equity for earnings was $23.0 billion. This was offset by reductions for distributions to ExxonMobil shareholders of $14.9 billion, all in the form of dividends. Foreign exchange translation effects of $0.9 billion for the treasury. Purchases were madestronger U.S. dollar reduced equity, and a $3.8 billion change in the funded status of the postretirement benefits reserves increased equity.
During 2021, Exxon Mobil Corporation suspended its share repurchase program used to offset shares or units settled in shares issued in conjunction with the company’s benefit plans and programs. Shares outstanding decreased from 4,234 million to 4,233 million at the end of 2020.
2019
Cash used in financing activities was $6.6 billion in 2019, $12.8 billion lower than 2018. Dividend payments on common shares increased to $3.43 per share from $3.23 per share and totaled $14.7 billion. During the third quarter of 2019, the Corporation issued $7.0 billion of long-term debt. Total debt increased $9.1 billion to $46.9 billion at year-end.
ExxonMobil share of equity decreased $0.1 billion to $191.7 billion. The addition to equity for earnings was $14.3 billion. This was offset by reductions for distributions to ExxonMobil shareholders of $14.7 billion, all in the form of dividends. Foreign exchange translation effects of $1.4 billion for the weaker U.S. currency increased equity, while a $1.4 billion change in the funded status of the postretirement benefits reserves reduced equity.
During 2019, Exxon Mobil Corporation acquired 8 million shares of its common stock for the treasury. Purchases were made to offset shares or units settled in shares issued in conjunction with the company’s benefit plans and programs. Shares outstanding decreased from 4,237 million to 4,234 million at the end of 2019.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSContractual Obligations
Commitments
Set forth below is information aboutIn addition, the outstanding commitments of the Corporation’s consolidated subsidiaries at December 31, 2020. The table combines data from the Consolidated Balance Sheet and from individual notes to the Consolidated Financial Statements.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period |
| Commitments | Note Reference Number | | 2021 | | 2022- 2023 | | 2024- 2025 | | 2026 and Beyond | | Total |
| | (millions of dollars) |
Long-term debt excluding finance lease obligations (1) | 6, 14 | | 2,828 | | | 7,364 | | | 8,640 | | | 29,263 | | | 48,095 | |
Asset retirement obligations (2) | 9 | | 689 | | | 1,203 | | | 1,005 | | | 8,350 | | | 11,247 | |
Pension and other postretirement obligations (3) | 17 | | 1,860 | | | 1,576 | | | 1,530 | | | 16,495 | | | 21,461 | |
Lease commitments (4) | 11 | | | | | | | | | | |
| Operating and finance leases - commenced | | | 1,558 | | | 2,163 | | | 1,358 | | | 2,004 | | | 7,083 | |
| Operating and finance leases - not yet commenced | | | 192 | | | 1,081 | | | 495 | | | 2,786 | | | 4,554 | |
Take-or-pay and unconditional purchase obligations (5) | | | 4,155 | | | 7,246 | | | 5,626 | | | 16,932 | | | 33,959 | |
Firm capital commitments (6) | | | 6,027 | | | 4,469 | | | 1,689 | | | 599 | | | 12,784 | |
This table excludesCorporation also enters into commodity purchase obligations (volumetric commitments but no fixed or minimum price) which are resold shortly after purchase, either in an active, highly liquid market or under long-term, unconditional sales contracts with similar pricing terms. Examples include long-term, noncancelable LNG and natural gas purchase commitments and commitments to purchase refinery products at market prices. Inclusion of suchThese commitments wouldare not be meaningful in assessing liquidity and cash flow, because thesethe purchases will be offset in the same periods by cash received from the related sales transactions. The table also excludes unrecognized tax benefits totaling $8.8 billion as of December 31, 2020, because the Corporation is unable to make reasonably reliable estimates of the timing of cash settlements with the respective taxing authorities. Further details on the unrecognized tax benefits can be found in “Note 19: Income and Other Taxes”.
Notes:
(1)The amount due in 2021 is included in Notes and loans payable of $20,458 million. The amounts due 2022 and beyond are included in Long-term debt of $47,182 million.
(2)Asset retirement obligations are primarily upstream asset removal costs at the end of field life.
(3)The amount by which the benefit obligations exceeded the fair value of fund assets for U.S. and non-U.S. pension and other postretirement plans at year-end. The payments by period include expected contributions to funded pension plans in 2021 and estimated benefit payments for unfunded plans in all years.
(4)Commitments for operating and finance leases cover drilling equipment, tankers and other assets.
(5)Take-or-pay obligations are noncancelable, long-term commitments for goods and services. Unconditional purchase obligations are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services. TheThese obligations mainly pertain to pipeline, manufacturing supply and terminal agreements.
(6)Firm capital commitments represent legally binding payment The total obligation at year-end 2022 for take-or-pay and unconditional purchase obligations to third parties where agreements specifying all significant terms have been executed for the constructionwas $38.2 billion. Cash payments expected in 2023 and purchase of fixed assets2024 are $3.8 billion and other permanent investments. In certain cases where the Corporation executes contracts requiring commitments to a work scope, those commitments have been included to the extent that the amounts and timing of payments can be reliably estimated. Firm capital commitments, shown on an undiscounted basis, totaled $12.8$3.5 billion, including $5.3 billion in the U.S.
Firm capital commitments for the non-U.S. Upstream of $5.9 billion were primarily associated with projects in Guyana, Angola, Malaysia, United Kingdom, Canada, Australia, Brazil and United Arab Emirates. The Corporation expects to fund the majority of these commitments with internally generated funds, supplemented by short-term and long-term debt as required.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
respectively.
Guarantees
The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2020,2022 for guarantees relating to notes, loans and performance under contracts (Note 16). Where guarantees for environmental remediation and other similar matters do not include a stated cap, the amounts reflect management’s estimate of the maximum potential exposure. These guaranteesWhere it is not possible to make a reasonable estimation of the maximum potential amount of future payments, future performance is expected to be either immaterial or have only a remote chance of occurrence. Guarantees are not reasonably likely to have a material effect on the Corporation’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financial Strength
On December 31, 2020,2022, the Corporation had total unused short-term committed lines of credit of $11.3$0.3 billion (Note 6) and nototal unused long-term committed lines of credit of $1.2 billion (Note 14). The table below shows the Corporation’s consolidated debt to capital ratios.
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| Debt to capital (percent) | 29.2 | | 19.1 | | 16.0 |
| Net debt to capital (percent) | 27.8 | | 18.1 | | 14.9 |
| | | | | | | | | | | | | | | | | |
| (percent) | 2022 | | 2021 | | 2020 |
| Debt to capital | 16.9 | | 21.4 | | 29.2 |
| Net debt to capital | 5.4 | | 18.9 | | 27.8 |
Management views the Corporation’s financial strength to be a competitive advantage of strategic importance. The Corporation’s financial position gives it the opportunity to access the world’s capital markets in the fullacross a range of market conditions, and enables the Corporation to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.
IndustryStronger industry conditions in 2020 led2021 and 2022 enabled the Corporation to lower realized prices forstrengthen the Corporation’s products which resulted in substantially lower earningsbalance sheet and operating cash flow in comparisonreturn debt to 2019.pre-pandemic levels. The Corporation took steps to strengthen its liquidityreduced debt by $19.9 billion in 2020, including issuing $232021 and an additional $6.5 billion of long-term debt and implementing significant capital and operating cost reductions. The Corporation endedin 2022, ending the year with $68$41.2 billion in gross debt and intends to reduce debt over time.total debt.
Litigation and Other Contingencies
As discussed in Note 16, a variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a material adverse effect upon the Corporation’s operations, financial condition, or financial statements taken as a whole. There are no events or uncertainties beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition. Refer to Note 16 for additional information on legal proceedings and other contingencies.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CAPITAL AND EXPLORATION EXPENDITURES
Capital and exploration expenditures (Capex) representsrepresent the combined total of additions at cost to property, plant and equipment, and exploration expenses on a before-tax basis from the Consolidated Statement of Income. ExxonMobil’s Capex includes its share of similar costs for equity companies. Capex excludes assets acquired in nonmonetary exchanges, the value of ExxonMobil shares used to acquire assets, and depreciation on the cost of exploration support equipment and facilities recorded to property, plant and equipment when acquired. While ExxonMobil’s management is responsible for all investments and elements of net income, particular focus is placed on managing the controllable aspects of this group of expenditures.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 |
| | U.S. | | Non-U.S. | | Total | | U.S. | | Non-U.S. | | Total |
| | (millions of dollars) |
Upstream (1) | 6,817 | | | 7,614 | | | 14,431 | | | 11,653 | | | 11,832 | | | 23,485 | |
| Downstream | 2,344 | | | 1,877 | | | 4,221 | | | 2,353 | | | 2,018 | | | 4,371 | |
| Chemical | 2,002 | | | 714 | | | 2,716 | | | 2,547 | | | 718 | | | 3,265 | |
| Other | 6 | | | — | | | 6 | | | 27 | | | — | | | 27 | |
| Total | 11,169 | | | 10,205 | | | 21,374 | | | 16,580 | | | 14,568 | | | 31,148 | |
(1) Exploration expenses included.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (millions of dollars) | 2022 | | 2021 |
| U.S. | | Non-U.S. | | Total | | U.S. | | Non-U.S. | | Total |
| Upstream (including exploration expenses) | 6,968 | | | 10,034 | | | 17,002 | | | 4,018 | | | 8,236 | | | 12,254 | |
| Energy Products | 1,351 | | | 1,059 | | | 2,410 | | | 982 | | | 1,005 | | | 1,987 | |
| Chemical Products | 1,123 | | | 1,842 | | | 2,965 | | | 1,200 | | | 825 | | | 2,025 | |
| Specialty Products | 46 | | | 222 | | | 268 | | | 185 | | | 141 | | | 326 | |
| Other | 59 | | | — | | | 59 | | | 3 | | | — | | | 3 | |
| Total | 9,547 | | | 13,157 | | | 22,704 | | | 6,388 | | | 10,207 | | | 16,595 | |
Capex in 20202022 was $21.4$22.7 billion, as the Corporation continued to pursue opportunities to find and produce new supplies of oil and natural gas to meet global demand for energy. The Corporation is prioritizing opportunitiesplans to hold 2021 capital spendinginvest in athe range of $16$23 billion to $19 billion.$25 billion in 2023. Included in the 2023 capital spend range is $11.6 billion of firm capital commitments. An additional $11.4 billion of firm capital commitments have been made for years 2024 and beyond. Actual spending could vary depending on the progress of individual projects and property acquisitions.
Upstream spending of $14.4$17.0 billion in 20202022 was downup 39 percent from 20192021, reflecting higher spend in response to market conditions. Investments in 2020 included the U.S. Permian Basin and key developmentadvantaged projects in Guyana. Development projects typically take several years from the time of recording proved undeveloped reserves to the start of production and can exceed five years for large and complex projects. The percentage of proved developed reserves was 6763 percent of total proved reserves at year-end 2020,2022, and has been over 60 percent for the last ten years.
Capital investments in the DownstreamEnergy Products totaled $4.2$2.4 billion in 2020, a decrease2022, an increase of $0.2$0.4 billion from 2019,2021, reflecting lowerhigher global project spending.spending, including the refinery expansion in Beaumont, Texas. Chemical Products capital expenditures of $2.7$3.0 billion increased $0.9 billion, representing increased spend on key growth projects such as the China chemical complex. Specialty Products capital expenditures of $0.3 billion decreased $0.5 billion, representing reduced spend on growth projects.
TAXES
| | | 2020 | | 2019 | | 2018 | |
| | (millions of dollars) | |
| (millions of dollars) | | (millions of dollars) | 2022 | | 2021 | | 2020 |
| Income taxes | Income taxes | (5,632) | | | 5,282 | | | 9,532 | | Income taxes | 20,176 | | | 7,636 | | | (5,632) | |
| Effective income tax rate | Effective income tax rate | 17 | % | | 34 | % | | 37 | % | Effective income tax rate | 33% | | 31% | | 17% |
| Total other taxes and duties | Total other taxes and duties | 28,425 | | | 33,186 | | | 35,230 | | Total other taxes and duties | 31,455 | | | 32,955 | | | 28,425 | |
| Total | Total | 22,793 | | | 38,468 | | | 44,762 | | Total | 51,631 | | | 40,591 | | | 22,793 | |
20202022
Total taxes on the Corporation’s income statement were $22.8$51.6 billion in 2020, a decrease2022, an increase of $15.7$11.0 billion from 2019.2021. Income tax expense, both current and deferred, was a benefit of $5.6$20.2 billion compared to $5.3$7.6 billion expense in 2019.2021. The relative benefiteffective tax rate, which is calculated based on consolidated company income taxes and ExxonMobil’s share of equity company income taxes, was 33 percent compared to 31 percent in the prior year driven by asset impairments recordedimpacts from additional European taxes on the energy sector. Total other taxes and duties of $31.5 billion in 2022 decreased $1.5 billion.
2021
Total taxes on the Corporation’s income statement were $40.6 billion in 2021, an increase of $17.8 billion from 2020. Income tax expense, both current and deferred, was $7.6 billion compared to a $5.6 billion benefit in 2020. The effective tax rate, which is calculated based on consolidated company income taxes and ExxonMobil’s share of equity company income taxes, was 1731 percent compared to 3417 percent in the prior year due primarily to a change in mix of results in jurisdictions with varying tax rates. Total other taxes and duties of $28.4$33.0 billion in 2020 decreased $4.82021 increased $4.5 billion.
2019
Total taxes on the Corporation’s income statement were $38.5 billion in 2019, a decrease of $6.3 billion from 2018. Income tax expense, both current and deferred, was $5.3 billion compared to $9.5 billion in 2018. The effective tax rate, which is calculated based on consolidated company income taxes and ExxonMobil’s share of equity company income taxes, was 34 percent compared to 37 percent in the prior year due primarily to the impact of the divestment of non-operated upstream assets in Norway. Total other taxes and duties of $33.2 billion in 2019 decreased $2.0 billion.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ENVIRONMENTAL MATTERS
Environmental Expenditures
| | | 2020 | | 2019 | |
| | (millions of dollars) | |
| (millions of dollars) | | (millions of dollars) | 2022 | | 2021 |
| Capital expenditures | Capital expenditures | 1,087 | | | 1,276 | | Capital expenditures | 1,864 | | | 1,202 | |
| Other expenditures | Other expenditures | 3,389 | | | 3,969 | | Other expenditures | 3,835 | | | 3,361 | |
| Total | Total | 4,476 | | | 5,245 | | Total | 5,699 | | | 4,563 | |
Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, water and ground. These include a significant investment in refining infrastructure and technology to manufacture clean fuels, as well as projects to monitor and reduce nitrogen oxide, sulfur oxideair, water, and greenhouse gaswaste emissions, and expenditures for asset retirement obligations. Using definitions and guidelines established by the American Petroleum Institute, ExxonMobil’s 20202022 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $4.5$5.7 billion, of which $3.4$3.8 billion were included in expenses with the remainder in capital expenditures. The total cost for such activities isAs the Corporation progresses its emission-reduction plans, worldwide environmental expenditures are expected to increase to approximately $4.9$7.3 billion in 2021 and 2022. Capital2023, with capital expenditures are expected to account for approximately 2546 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.
Environmental Liabilities
The Corporation accrues environmental liabilities when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. ExxonMobil has accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency has identified ExxonMobil as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could mitigate ExxonMobil’s actual joint and several liability exposure. At present, no individual site is expected to have losses material to ExxonMobil’s operations or financial condition. Consolidated company provisions made in 20202022 for environmental liabilities were $263$185 million ($290146 million in 2019)2021), and the balance sheet reflects liabilities of $902$730 million as of December 31, 2020,2022, and $835$807 million as of December 31, 2019.2021.
MARKET RISKS INFLATION AND OTHER UNCERTAINTIES
| | | | | | | | | | | | | | | | | |
Worldwide Average Realizations (1) | 2020 | | 2019 | | 2018 |
| Crude oil and NGL ($ per barrel) | 35.41 | | | 56.32 | | | 62.79 | |
| Natural gas ($ per thousand cubic feet) | 2.01 | | | 3.05 | | | 3.87 | |
(1) Consolidated subsidiaries.
| | | | | | | | | | | | | | | | | |
Worldwide Average Realizations (1) | 2022 | | 2021 | | 2020 |
| Crude oil and NGL ($ per barrel) | 87.25 | | | 61.89 | | | 35.41 | |
| Natural gas ($ per thousand cubic feet) | 7.48 | | | 4.33 | | | 2.01 | |
| | | | | |
(1) Consolidated subsidiaries. |
Crude oil, natural gas, petroleum product, and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings from Upstream, Downstream and Chemical operations have varied. Invaried across the Upstream,Corporation's operating segments. For the year 2023, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $475$500 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives. Similarly, a $0.10 per thousand cubic feet change in the worldwide average gas realization would have approximately a $165$140 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, results of trading activities, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide broad indicators of changes in the earnings experienced in any particular period.
In the very competitive downstreampetroleum and chemical environments,petrochemical environment, earnings are primarily determined by margin capture rather than absolute price levels of products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the Corporation’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the Corporation’s financial strength as a competitive advantage.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Instead, where such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery/refinery and chemical complexes. Additionally, intersegment sales are at market-based prices. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity, and transportation capabilities. Refer to Note 18 for additional information on intersegment revenue.
Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to global economic conditions, political events, decisions by OPEC and other major government resource owners and other factors, industry economics over the long term will continue to be driven by market supply and demand. Accordingly, theThe Corporation evaluates the viability of its major investments over a range of prices.prices, including estimated greenhouse gas emission costs even in jurisdictions without a current greenhouse gas pricing policy.
The Corporation has an active asset management program in which underperformingnonstrategic assets are either improved to acceptable levels or considered for divestment. The asset management program includes a disciplined, regular review to ensure that assets are contributing to the Corporation’s strategic objectives.
Risk Management
The Corporation’s size, strong capital structure, geographic diversity, and the complementary nature of the Upstream, Downstream and Chemical businessesits business segments reduce the Corporation’s enterprise-wide risk from changes in commodity prices, currency rates, and interest rates. In addition, the Corporation uses commodity-based contracts, including derivatives, to manage commodity price risk and for trading purposes.to generate returns from trading. The Corporation’s commodity derivatives are not accounted for under hedge accounting. At times, the Corporation also enters into currency and interest rate derivatives, none of which are material to the Corporation’s financial position as of December 31, 20202022 and 2019,2021, or results of operations for the years ended 2020, 20192022, 2021, and 2018.2020. Credit risk associated with the Corporation’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of and financial limits placed on derivative counterparties. No material market or credit risks to the Corporation’s financial position, results of operations or liquidity exist as a result of the derivatives described in Note 13. The Corporation maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity.
The Corporation is exposed to changes in interest rates, primarily on its short-term debt and the portion of long-term debt that carries floating interest rates. The impact of a 100-basis-point change in interest rates affecting the Corporation’s debt would not be material to earnings or cash flow. The Corporation has access to significant capacity of long-term and short-term liquidity. Internally generated funds are generally expected to cover financial requirements, supplemented by long-term and short-term debt as required. Commercial paper is used to balance short-term liquidity requirements. Some joint-venture partners are dependent on the credit markets, and their funding ability may impact the development pace of joint-venture projects.
The Corporation conducts business in many foreign currencies and is subject to exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. Fluctuations in exchange rates are often offsetting and the impacts on ExxonMobil’s geographically and functionally diverse operations are varied. The Corporation makes limited use of currency exchange contracts to mitigate the impact of changes in currency values, and exposures related to the Corporation’s use of these contracts are not material.
Inflation and Other Uncertainties
The general rate of inflation in many major countries of operation has remained moderate over the past few years, and the associated impact on non-energy costs has generally been mitigated by cost reductions from efficiency and productivity improvements. Prices for services and materials continue to evolve in response to constant changes in commodity markets and industry activities, impacting operating and capital costs. However, the global COVID-19 pandemic since early 2020 has brought unprecedented uncertainties to near-term economic outlooks. The Corporation continues to monitor market trends and works to minimize costs in all commodity price environments through its economies of scale in global procurement and its efficient project management practices.
RESTRUCTURING ACTIVITIES
During 2020, ExxonMobil conducted an extensive global review of staffing levels and subsequently commenced targeted workforce reductions within a number of countries to improve efficiency and reduce costs. The programs, which are expected to be substantially complete by the end of 2021, include both voluntary and involuntary employee separations and reductions in contractors.
In 2020 the Corporation recorded before-tax charges of $450 million ($349 million after tax), consisting primarily of employee separation costs, associated with announced workforce reduction programs in Europe, North America, and Australia. These costs are captured in “Selling, general and administrative expenses” on the Statement of Income and reported in the Corporate and financing segment. Before-tax cash outflows in 2020 associated with these activities were $47 million. The Corporation estimates additional charges of up to $200 million in 2021 related to planned workforce reduction programs with cash outflows ranging between $400 million and $600 million. Before-tax workforce reduction savings, including employees and contractors, are estimated to range between $1 billion and $2 billion per year after program completion when compared to 2019 levels.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CRITICAL ACCOUNTING ESTIMATES
The Corporation’s accounting and financial reporting fairly reflect its integrated business model involving exploration for, and production of, crude oil and natural gas andgas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals, and a wide variety of specialty products.products; and pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen, and lower-emission fuels. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. The Corporation’s accounting policies are summarized in Note 1.
Oil and Natural Gas Reserves
The estimation of proved oil and natural gas reserve volumes is an ongoing process based on rigorous technical evaluations, commercial and market assessments, and detailed analysis of well information such as flow rates and reservoir pressure declines, development and production costs, amongand other factors. The estimation of proved reserves is controlled by the Corporation through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Global Reserves and Resources Group which has significant technical experience, culminating in reviews with and approval by senior management. Notably, the Corporation does not use specific quantitative reserve targets to determine compensation. Key features of the reserve estimation process are covered in Disclosure of Reserves in Item 2.
Oil and natural gas reserves include both proved and unproved reserves.
•Proved oil and natural gas reserves are determined in accordance with Securities and Exchange Commission (SEC) requirements. Proved reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic and operating conditions and government regulations. Proved reserves are determined using the average of first-of-month oil and natural gas prices during the reporting year.
Proved reserves can be further subdivided into developed and undeveloped reserves. Proved developed reserves include amounts which are expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include amounts expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion. Proved undeveloped reserves are recognized only if a development plan has been adopted indicating that the reserves are scheduled to be drilled within five years, unless specific circumstances support a longer period of time.
The percentage of proved developed reserves was 67 percent of total proved reserves at year-end 2020 (including both consolidated and equity company reserves), an increase from 66 percent in 2019, and has been over 60 percent for the last ten years. Although the Corporation is reasonably certain that proved reserves will be produced,produced. However, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals, government policy, consumer preferences, and significant changes in oil and natural gas price levels.
•Unproved reserves are quantities of oil and natural gas with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that, together with proved reserves, are as likely as not to be recovered.
Revisions in previously estimated volumes of proved reserves for existing fields can occur due to the evaluation or re-evaluation of (1) already available geologic, reservoir, or production data, (2) new geologic, reservoir, or production data, or (3) changes in the average of first-of-month oil and natural gas prices and / and/or costs that are used in the estimation of reserves. Revisions can also result from significant changes in development strategy or production equipment and facility capacity.
Unit-of-Production Depreciation
Oil and natural gas reserve volumes are used as the basis to calculate unit-of-production depreciation rates for most upstream assets. Depreciation is calculated by taking the ratio of asset cost to total proved reserves or proved developed reserves applied to actual production. The volumes produced and asset cost are known, while proved reserves are based on estimates that are subject to some variability.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative method is used. The straight-line method may beis used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the Corporation uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life.
To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Impairment
The Corporation tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. AmongThe Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of ASC 360 and ASC 932, and relies, in part, on the Corporation’s planning and budgeting cycle.
Because the lifespans of the vast majority of the Corporation’s major assets are measured in decades, the future cash flows of these assets are predominantly based on long-term oil and natural gas commodity prices and industry margins, development costs, and production costs. Significant reductions in the Corporation’s view of oil or natural gas commodity prices or margin ranges, especially the longer-term prices and margins, and changes in the development plans, including decisions to defer, reduce, or eliminate planned capital spending, can be an indicator of potential impairment. Other events or changes in circumstances, which could indicate that the carrying valueincluding indicators outlined in ASC 360, can be indicators of an asset or asset group may not be recoverable are the following:
•a significant decrease in the market price of a long-lived asset;
•a significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a significant decrease in current and projected reserve volumes;
•a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator;
•an accumulation of project costs significantly in excess of the amount originally expected;
•a current-period operating loss combined with a history and forecast of operating or cash flow losses; and
•a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
Asset valuation analyses, profitability reviews and other periodic control processes assist the Corporation in assessing whether events or changes in circumstances indicate the carrying amounts of any of its assets may not be recoverable.potential impairment as well.
In general, the Corporation does not view temporarily low prices or margins as an indication of impairment. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments, and technology and efficiency advancements. OPEC investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities, alternative energy sources, and levels of prosperity. Because the lifespans of the vast majority of the Corporation’s major assets are measured in decades, the value of these assets is predominantly based on long-term views of future commodity prices and development and production costs. During the lifespan of theseits major assets, the Corporation expects that oil and gas prices and industry margins will experience significant volatility, and consequentlyvolatility. Consequently, these assets will experience periods of higher earnings and periods of lower earnings, or even losses.
In assessing whether events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the Corporation considers recent periods of operating losses in the context of its longer-term view of prices. While near-term prices are subject to wide fluctuations, longer-term price views are more stable and meaningful for purposes of assessing future cash flows.
When the industry experiences a prolonged and deep reduction in commodity prices, the market supply and demand conditions may result in changes to the Corporation’s price or margin assumptions it uses for its capital investment decisions. To the extent those changes result in a significant reduction to its oil price, natural gas price or margin ranges, the Corporation may consider that situation, in conjunction with other events or changes in circumstances such as a history of operating losses, an indicator of potential impairment for certain assets.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSmargins.
In the Upstream, the standardized measure of discounted cash flows included in the Supplemental Information on OilOutlook for Energy and Gas Exploration and Production Activities is required to use prices based on the average of first-of-month prices. These prices represent discrete points in time and could be higher or lower than the Corporation’s price assumptions which are used for impairment assessments. Cash Flow Assessment. The Corporation believes the standardized measure does not provide a reliable estimate of the expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its oil and gas reserves and therefore does not consider it relevant in determining whether events or changes in circumstances indicate the need for an impairment assessment.
The Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of ASC 360 and ASC 932, and relies in part on the Corporation’sannual planning and budgeting cycle. process, known as the Corporate Plan, is the mechanism by which resources (capital, operating expenses, and people) are allocated across the Corporation. The foundation for the assumptions supporting the Corporate Plan is the Outlook for Energy (Outlook), which contains the Corporation’s demand and supply projections based on its assessment of current trends in technology, government policies, consumer preferences, geopolitics, economic development, and other factors. Reflective of the existing global policy environment, the Outlook does not attempt to project the degree of necessary future policy and technology advancement and deployment for the world, or the Corporation, to meet net zero by 2050. As future policies and technology advancements emerge, they will be incorporated into the Outlook, and the Corporation’s business plans will be updated accordingly.
If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on the Corporation’s assumptions which are developed in the annual planningCorporate Plan, which is reviewed and budgeting process,approved by the Board of Directors, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the Corporation’s assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, development and operating costs including greenhouse gas emission prices, and foreign currency exchange rates. Notably, when assessing future cash flows, the Corporation includes the estimated costs in support of reaching its 2030 greenhouse gas emission-reduction plans, including its goal of net-zero greenhouse gas emissions (Scope 1 and 2) from unconventional operated assets in the Permian Basin. Volumes are based on projected field and facility production profiles, throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities. Cash flow estimatesExxonMobil considers a range of scenarios - including remote scenarios - to help inform perspective of the future and enhance strategic thinking over time. While third-party scenarios, such as the International Energy Agency's Net Zero Emissions by 2050, may be used for these purposes, they are not used as a basis for developing future cash flows for impairment testing excludeassessments. As part of the effectsCorporate Plan, the Company considers estimated greenhouse gas emission costs, even for jurisdictions without a current greenhouse gas pricing policy.
Fair Value of derivative instruments.
Impaired Assets. An asset group is impaired if its estimated undiscounted cash flows are less than the asset’sasset group’s carrying value. Impairments are measured by the amount by whichexcess of the carrying value exceedsover fair value. The assessment of fair value requires the use of Level 3 inputs and assumptions that areis based upon the views of a likely market participant. The principal parameters used to establish fair value include estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, throughput and product sales volumes, commodity prices which are consistent with the average of third-party industry experts and government agencies, refining and chemical margins, drilling and development costs, operating costs, and discount rates ranging from 6 percent to 8 percent which are reflective of the characteristics of the asset group.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Impairment Estimates. Unproved properties are assessed periodically to determine whether they have been impaired. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the Corporation's future development plans, the estimated economic chance of success, and the length of time that the Corporation expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.
In 2020,Long-lived assets that are held for sale are evaluated for possible impairment by comparing the Corporation identified a numbercarrying value of situations wherethe asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the assets are considered impaired and adjusted to the lower value. Judgment is required to determine if assets are held for sale and to determine the fair value less cost to sell.
Investments accounted for by the equity method are assessed for possible impairment when events or changes in circumstances indicatedindicate that the carrying value of certain long-lived assetsan investment may not be recoverable. Those situations primarilyExamples of key indicators include a history of operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If the decline in value of the investment is other than temporary, the carrying value of the investment is written down to fair value. In the absence of market prices for the investment, discounted cash flows are used to assess fair value, which requires significant judgment.
Recent Impairments. In early 2022, in response to Russia’s military action in Ukraine, the Corporation announced that it planned to discontinue operations on the Sakhalin-1 project (“Sakhalin”) and develop steps to exit the venture. The Corporation’s first quarter results included after-tax charges of $3.0 billion representing the impairment of its Upstream operations related to Sakhalin. (Refer to Note 2 for further information on Russia.) Other after-tax impairment charges of $1.6 billion and $0.3 billion were recognized in Upstream and Energy Products, respectively.
In 2021, largely as a result of changes to Upstream development plans, the Corporation recognized after-tax impairment charges of approximately $1 billion. In 2020, as part of the Corporation's annual review and approval of the Corporation'sits business and strategic plan. As part of the planning process, the Corporation assessed its full portfolioplan, a decision was made to prioritize assets with the highest future value potential within its broad range of available opportunities in order to optimize resources within current levels of debt and operating cash flow, as well as identify potential asset divestment candidates. This effort included a re-assessment of dry gas assets, primarily in North America, which previously had been included in the Corporation’s future development plans. Under the plan as approved, the Corporation no longer plans to develop a significant portion of itsthe dry gas portfolio including a portion of its resources in the Appalachian, Rocky Mountains, Oklahoma, Texas, Louisiana, and Arkansas regions of the U.S. as well as resources in WesternUnited States, Canada, and Argentina. The decision not to developimpairment of these assets resulted in non-cash, after-tax charges of $18.4 billion in Upstream to reduce the carrying value of those assets to fair value.Upstream. Other after-tax impairment charges in 2020 include $0.5of $1.8 billion in Upstreamacross the year related mainly to impairments of property, plant, and $0.3 billion in Downstream. As a result of these impairments, the Corporation expects lower 2021 depreciationequipment, goodwill, and depletion charges in Upstream for most of these asset groups. However, largely due to the impact of lower 2020 proved reserves resulting from low prices, higher unit-of-production rates on certain assets in 2021 are expected to offset the effect of lower depreciation and depletion charges related to 2020 impairments. For further discussion on proved reserves, see Summary of Oil and Gas Reserves in the Disclosure of Reserves section in Item 2.equity method investments.
Factors which could put further assets at risk of impairment in the future include reductions in the Corporation’s price or margin outlooks, changes in the allocation of capital or development plans, reduced long-term demand for the Corporation's products, and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural gas price or margin increases. However, due to the inherent difficulty in predicting future commodity prices or margins, and the relationship between industry prices and costs, it is not practicable to reasonably estimate the existence or range of any potential future impairment charges related to the Corporation’s long-lived assets.
For discussion offurther information regarding impairments in goodwill, equity method investments, property, plant, and equity company impairments, see Noteequipment, and suspended wells, refer to Notes 3, 7, 9, and Note 7 to the financial statements,10, respectively.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Asset Retirement Obligations
The Corporation incursis subject to retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation;obligation, technical assessments of the assets;assets, estimated amounts and timing of settlements;settlements, discount rates;rates, and inflation rates. Asset retirement obligations are disclosed inSee Note 9 to the financial statements.for further information regarding asset retirement obligations.
Suspended Exploratory Well Costs
The Corporation continues capitalization of exploratory well costs when the wellit has found a sufficient quantity of reserves to justify its completion as a producing well and the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Assessing whether the Corporation is making sufficient progress on a project requires careful consideration of the facts and circumstances. The facts and circumstances that support continued capitalization of suspended wells at year-end are disclosed in Note 10 to the financial statements.10.
Consolidations
The Consolidated Financial Statements include the accounts of subsidiaries the Corporation controls. They also include the Corporation’s share of the undivided interest in certain upstream assets, liabilities, revenues and expenses. Amounts representing the Corporation’s interest in entities that it does not control, but over which it exercises significant influence, are accounted for using the equity method of accounting.
Investments in companies that are partially owned by the Corporation are integral to the Corporation’s operations. In some cases they serve to balance worldwide risks, and in others they provide the only available means of entry into a particular market or area of interest. The other parties, who also have an equity interest in these companies, are either independent third parties or host governments that share in the business results according to their ownership. The Corporation does not invest in these companies in order to remove liabilities from its balance sheet. In fact, the Corporation has long been on record supporting an alternative accounting method that would require each investor to consolidate its share of all assets and liabilities in these partially-owned companies rather than only its interest in net equity. This method of accounting for investments in partially-owned companies is not permitted by U.S. GAAP except where the investments are in the direct ownership of a share of upstream assets and liabilities. However, for purposes of calculating return on average capital employed, which is not covered by U.S. GAAP standards, the Corporation includes its share of debt of these partially-owned companies in the determination of average capital employed. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Pension Benefits
The Corporation and its affiliates sponsor about 8075 defined benefit (pension) plans in over 40 countries. The Pension and Other Postretirement Benefits footnote (Note 17) provides details on pension obligations, fund assets, and pension expense.
Some of these plans (primarily non-U.S.) provide pension benefits that are paid directly by their sponsoring affiliates out of corporate cash flow rather than a separate pension fund because applicable tax rules and regulatory practices do not encourage advance funding. Book reserves are established for these plans. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets.
For funded plans, including those in the U.S., pension obligations are financed in advance through segregated assets or insurance arrangements. These plans are managed in compliance with the requirements of governmental authorities and meet or exceed required funding levels as measured by relevant actuarial and government standards at the mandated measurement dates. In determining liabilities and required contributions, these standards often require approaches and assumptions that differ from those used for accounting purposes.
The Corporation will continue to make contributions to these funded plans as necessary. All defined-benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.
Pension accounting requires explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the discount rate for the benefit obligations, and the long-term rate for future salary increases. Pension assumptions are reviewed annually by outside actuaries and senior management. These assumptions are adjusted as appropriate to reflect changes in market rates and outlook. The long-term expected earnings rate on U.S. pension plan assets in 20202022 was 5.34.6 percent. The 10-year and 20-year actual returns on U.S. pension plan assets were 94 percent and 7 percent, respectively. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class. A worldwide reduction of 0.5 percent in the long-term rate of return on assets would increase annual pension expense by approximately $210$140 million before tax.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Differences between actual returns on fund assets and the long-term expected return are not recognized in pension expense in the year that the difference occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected remaining service life of employees.
Litigation and Tax Contingencies
A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending lawsuits. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. For contingencies where an unfavorable outcome is reasonably possible and significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The status of significant claims is summarized in Note 16.
The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable, and the amount can be reasonably estimated. These accrued liabilities are not reduced by amounts that may be recovered under insurance or claims against third parties, but undiscounted receivables from insurers or other third parties may be accrued separately. The Corporation revises such accruals in light of new information. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of our litigation contingency disclosures, “significant” includes material matters as well as other items which management believes should be disclosed.
Management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past. Payments have not had a material adverse effect on our operations or financial condition. In the Corporation’s experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement.
Tax Contingencies
The Corporation is subject to income taxation in many jurisdictions around the world. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict.
The benefits of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. A reserveSignificant management judgment is establishedrequired in the accounting for the difference between a position taken or expected to be taken in an income tax returncontingencies and tax disputes because the amount recognized in the financial statements.outcomes are often difficult to predict. The Corporation’s unrecognized tax benefits and a description of open tax years are summarized in Note 19.
Foreign Currency Translation
The method of translating the foreign currency financial statements of the Corporation’s international subsidiaries into U.S. dollars is prescribed by U.S. GAAP. Under these principles, it is necessary to select the functional currency of these subsidiaries. The functional currency is the currency of the primary economic environment in which the subsidiary operates. Management selects the functional currency after evaluating this economic environment.
Factors considered by management when determining the functional currency for a subsidiary include the currency used for cash flows related to individual assets and liabilities; the responsiveness of sales prices to changes in exchange rates; the history of inflation in the country; whether sales are into local markets or exported; the currency used to acquire raw materials, labor, services and supplies; sources of financing; and significance of intercompany transactions.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management, including the Corporation’s Chief Executive Officer, PrincipalChief 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, 2020.2022.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2020,2022, as stated in their report included in the Financial Section of this report.
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| | |
Darren W. Woods
Chief Executive Officer | Andrew P. Swiger
Kathryn A. Mikells Senior Vice President
(Principal Chief Financial Officer)Officer | David S. Rosenthal
Len M. Fox Vice President and Controller
(Principal Accounting Officer) |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Exxon Mobil Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheet of Exxon Mobil Corporation and its subsidiaries (the “Corporation”) as of December 31, 20202022 and 2019,2021, and the related consolidated statements of income, of comprehensive income, of changes in equity and of cash flows for each of the three years in the period ended December 31, 2020,2022, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Corporation's internal control over financial reporting as of December 31, 2020,2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Corporation as of December 31, 20202022 and 2019,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20202022 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020,2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Corporation's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on the Corporation’s consolidated financial statements and on the Corporation's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Critical Audit Matters
The critical audit mattersmatter communicated below are mattersis a matter arising from the current period audit of the consolidated financial statements that werewas communicated or required to be communicated to the audit committee and that (i) relaterelates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit mattersmatter below, providing a separate opinion on the critical audit mattersmatter or on the accounts or disclosures to which they relate.it relates.
The Impact of Proved Oil and Natural Gas Reserves on Upstream Property, Plant and Equipment, Net
As described in Notes 1, 9 and 18 to the consolidated financial statements, the Corporation’sCorporation's consolidated upstream property, plant and equipment (PP&E), net balance was $167.5$144.1 billion as of December 31, 2020,2022, and the related depreciation and depletion expense for the year ended December 31, 20202022 was $41.4$19.8 billion. Management uses the successful efforts method to account for its exploration and production activities. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. As disclosed by management, proved oil and natural gas reserve volumes are used as the basis to calculate unit-of-production depreciation rates for most upstream assets. The estimation of proved oil and natural gas reserve volumes is an ongoing process based on technical evaluations, commercial and market assessments, and detailed analysis of well information such as flow rates and reservoir pressure declines, development and production costs, among other factors. As further disclosed by management, reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Global Reserves and Resources Group (together “management’s specialists”"management's specialists").
The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural gas reserves on upstream PP&E, net is a critical audit matter are (i) the significant judgment by management, including the use of management’smanagement's specialists, when developing the estimates of proved oil and natural gas reserve volumes, as the reserve volumes are based on engineering assumptions and methods, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods and assumptions used by management and its specialists in developing the estimates of proved oil and natural gas reserve volumes and the assumptions applied to the data related to future development costs and production costs, as applicable.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's estimates of proved oil and natural gas reserve volumes. The work of management's specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserve volumes. As a basis for using this work, the specialists' qualifications were understood and the Company'sCorporation's relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of the specialists' findings. These procedures also included, among others, testing the completeness and accuracy of the data related to future development costs and production costs. Additionally, these procedures included evaluating whether the assumptions applied to the data related to future development costs and production costs were reasonable considering the past performance of the Company.Corporation.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Impairment Assessment of Certain Upstream Property, Plant and Equipment, Net
As described in Notes 1, 9, and 18 to the consolidated financial statements, the Corporation’s consolidated upstream property, plant and equipment (PP&E), net balance was $167.5 billion as of December 31, 2020, and related impairment expense for the year ended December 31, 2020 was $25.3 billion. If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, management estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which identifiable cash flows are largely independent of cash flows of other groups of assets. These evaluations make use of management’s assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, volumes, development and operating costs, and foreign currency exchange rates. An asset group is impaired if its estimated undiscounted cash flows are less than the asset’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities.
The principal considerations for our determination that performing procedures relating to the impairment assessment of certain upstream PP&E, net is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of future undiscounted cash flows and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to future crude oil and natural gas commodity prices, production volumes, and development costs, as applicable.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s upstream PP&E, net impairment assessment. These procedures also included, among others (i) testing management’s process for assessing the recoverability of carrying amounts of upstream PP&E, net; (ii) evaluating the appropriateness of the undiscounted cash flow models; (iii) testing the completeness and accuracy of underlying data used in the models; and (iv) evaluating the reasonableness of significant assumptions used by management related to future crude oil and natural gas commodity prices, production volumes, and development costs. Evaluating the reasonableness of management’s assumptions related to future crude oil and natural gas commodity prices involved comparing the assumption against observable market data. Evaluating future development costs involved evaluating the reasonableness of the assumptions as compared to the past performance of the Company. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserve volumes as stated in the Critical Audit Matter titled “Impact of Proved Oil and Natural Gas Reserves on Upstream Property, Plant and Equipment, Net” and the reasonableness of the future production volumes. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ findings.
/s/ PricewaterhouseCoopers LLP
Dallas, Texas
February 24, 202122, 2023
We have served as the Corporation’s auditor since 1934.
CONSOLIDATED STATEMENT OF INCOME
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| | Note
Reference
Number | | 2020 | | 2019 | | 2018 |
| | | | (millions of dollars) |
| Revenues and other income | | | | | | | |
| Sales and other operating revenue | | | 178,574 | | | 255,583 | | | 279,332 | |
| Income from equity affiliates | 7 | | 1,732 | | | 5,441 | | | 7,355 | |
| Other income | | | 1,196 | | | 3,914 | | | 3,525 | |
| Total revenues and other income | | | 181,502 | | | 264,938 | | | 290,212 | |
| Costs and other deductions | | | | | | | |
| Crude oil and product purchases | | | 94,007 | | | 143,801 | | | 156,172 | |
| Production and manufacturing expenses | | | 30,431 | | | 36,826 | | | 36,682 | |
| Selling, general and administrative expenses | | | 10,168 | | | 11,398 | | | 11,480 | |
| Depreciation and depletion (includes impairments) | 3, 9 | | 46,009 | | | 18,998 | | | 18,745 | |
| Exploration expenses, including dry holes | | | 1,285 | | | 1,269 | | | 1,466 | |
| Non-service pension and postretirement benefit expense | 17 | | 1,205 | | | 1,235 | | | 1,285 | |
| Interest expense | | | 1,158 | | | 830 | | | 766 | |
| Other taxes and duties | 19 | | 26,122 | | | 30,525 | | | 32,663 | |
| Total costs and other deductions | | | 210,385 | | | 244,882 | | | 259,259 | |
| Income (Loss) before income taxes | | | (28,883) | | | 20,056 | | | 30,953 | |
| Income tax expense (benefit) | 19 | | (5,632) | | | 5,282 | | | 9,532 | |
| Net income (loss) including noncontrolling interests | | | (23,251) | | | 14,774 | | | 21,421 | |
| Net income (loss) attributable to noncontrolling interests | | | (811) | | | 434 | | | 581 | |
| Net income (loss) attributable to ExxonMobil | | | (22,440) | | | 14,340 | | | 20,840 | |
| | | | | | | |
Earnings (Loss) per common share (dollars) | 12 | | (5.25) | | | 3.36 | | | 4.88 | |
| | | | | | | |
Earnings (Loss) per common share - assuming dilution (dollars) | 12 | | (5.25) | | | 3.36 | | | 4.88 | |
The information in the Notes to Consolidated Financial Statements is an integral part of these statements. | | | | | | | | | | | | | | | | | | | | | | | |
(millions of dollars) | Note
Reference
Number | | 2022 | | 2021 | | 2020 |
| Revenues and other income | | | | | | | |
| Sales and other operating revenue | 18 | | 398,675 | | | 276,692 | | | 178,574 | |
| Income from equity affiliates | 7 | | 11,463 | | | 6,657 | | | 1,732 | |
| Other income | | | 3,542 | | | 2,291 | | | 1,196 | |
| Total revenues and other income | | | 413,680 | | | 285,640 | | | 181,502 | |
| Costs and other deductions | | | | | | | |
| Crude oil and product purchases | | | 228,959 | | | 155,164 | | | 94,007 | |
| Production and manufacturing expenses | | | 42,609 | | | 36,035 | | | 30,431 | |
| Selling, general and administrative expenses | | | 10,095 | | | 9,574 | | | 10,168 | |
| Depreciation and depletion (includes impairments) | 2, 9 | | 24,040 | | | 20,607 | | | 46,009 | |
| Exploration expenses, including dry holes | | | 1,025 | | | 1,054 | | | 1,285 | |
| Non-service pension and postretirement benefit expense | 17 | | 482 | | | 786 | | | 1,205 | |
| Interest expense | | | 798 | | | 947 | | | 1,158 | |
| Other taxes and duties | 19 | | 27,919 | | | 30,239 | | | 26,122 | |
| Total costs and other deductions | | | 335,927 | | | 254,406 | | | 210,385 | |
| Income (loss) before income taxes | | | 77,753 | | | 31,234 | | | (28,883) | |
| Income tax expense (benefit) | 19 | | 20,176 | | | 7,636 | | | (5,632) | |
| Net income (loss) including noncontrolling interests | | | 57,577 | | | 23,598 | | | (23,251) | |
| Net income (loss) attributable to noncontrolling interests | | | 1,837 | | | 558 | | | (811) | |
| Net income (loss) attributable to ExxonMobil | | | 55,740 | | | 23,040 | | | (22,440) | |
| | | | | | | |
Earnings (loss) per common share (dollars) | 12 | | 13.26 | | | 5.39 | | | (5.25) | |
| | | | | | | |
Earnings (loss) per common share - assuming dilution (dollars) | 12 | | 13.26 | | | 5.39 | | | (5.25) | |
| | | | | | | |
| The information in the Notes to Consolidated Financial Statements is an integral part of these statements. |
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
| | (millions of dollars) | | (millions of dollars) | 2022 | | 2021 | | 2020 |
| Net income (loss) including noncontrolling interests | | Net income (loss) including noncontrolling interests | 57,577 | | | 23,598 | | | (23,251) | |
| | | 2020 | | 2019 | | 2018 | | | |
| | (millions of dollars) | |
| Net income (loss) including noncontrolling interests | (23,251) | | | 14,774 | | | 21,421 | | |
| Other comprehensive income (loss) (net of income taxes) | Other comprehensive income (loss) (net of income taxes) | | Other comprehensive income (loss) (net of income taxes) | | |
| Foreign exchange translation adjustment | Foreign exchange translation adjustment | 1,916 | | | 1,735 | | | (5,077) | | Foreign exchange translation adjustment | (3,482) | | | (872) | | | 1,916 | |
| Adjustment for foreign exchange translation (gain)/loss included in net income | Adjustment for foreign exchange translation (gain)/loss included in net income | 14 | | | 0 | | | 196 | | Adjustment for foreign exchange translation (gain)/loss included in net income | — | | | (2) | | | 14 | |
| Postretirement benefits reserves adjustment (excluding amortization) | Postretirement benefits reserves adjustment (excluding amortization) | 30 | | | (2,092) | | | 280 | | Postretirement benefits reserves adjustment (excluding amortization) | 3,395 | | | 3,118 | | | 30 | |
| Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs | Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs | 896 | | | 582 | | | 931 | | Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs | 403 | | | 925 | | | 896 | |
| Total other comprehensive income (loss) | Total other comprehensive income (loss) | 2,856 | | | 225 | | | (3,670) | | Total other comprehensive income (loss) | 316 | | | 3,169 | | | 2,856 | |
| Comprehensive income (loss) including noncontrolling interests | Comprehensive income (loss) including noncontrolling interests | (20,395) | | | 14,999 | | | 17,751 | | Comprehensive income (loss) including noncontrolling interests | 57,893 | | | 26,767 | | | (20,395) | |
| Comprehensive income (loss) attributable to noncontrolling interests | Comprehensive income (loss) attributable to noncontrolling interests | (743) | | | 588 | | | 174 | | Comprehensive income (loss) attributable to noncontrolling interests | 1,659 | | | 786 | | | (743) | |
| Comprehensive income (loss) attributable to ExxonMobil | Comprehensive income (loss) attributable to ExxonMobil | (19,652) | | | 14,411 | | | 17,577 | | Comprehensive income (loss) attributable to ExxonMobil | 56,234 | | | 25,981 | | | (19,652) | |
| | The information in the Notes to Consolidated Financial Statements is an integral part of these statements. | | The information in the Notes to Consolidated Financial Statements is an integral part of these statements. |
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
CONSOLIDATED BALANCE SHEET
| | (millions of dollars) | | (millions of dollars) | Note
Reference
Number | | December 31, 2022 | | December 31, 2021 |
| | | Note
Reference
Number | | December 31, 2020 | | December 31, 2019 | | | |
| | | | (millions of dollars) | |
| Assets | | | | | | |
| ASSETS | | ASSETS | | | | | |
| Current assets | Current assets | | | | | | Current assets | | | | | |
| Cash and cash equivalents | Cash and cash equivalents | | | 4,364 | | | 3,089 | | Cash and cash equivalents | | | 29,640 | | | 6,802 | |
| Notes and accounts receivable - net | 6 | | 20,581 | | | 26,966 | | |
| Cash and cash equivalents – restricted | | Cash and cash equivalents – restricted | | 25 | | | — | |
| Notes and accounts receivable – net | | Notes and accounts receivable – net | 6 | | 41,749 | | | 32,383 | |
| Inventories | Inventories | | | Inventories | | | | |
| Crude oil, products and merchandise | Crude oil, products and merchandise | 3 | | 14,169 | | | 14,010 | | Crude oil, products and merchandise | 3 | | 20,434 | | | 14,519 | |
| Materials and supplies | Materials and supplies | | | 4,681 | | | 4,518 | | Materials and supplies | | | 4,001 | | | 4,261 | |
| Other current assets | Other current assets | | | 1,098 | | | 1,469 | | Other current assets | | | 1,782 | | | 1,189 | |
| Total current assets | Total current assets | | | 44,893 | | | 50,052 | | Total current assets | | | 97,631 | | | 59,154 | |
| Investments, advances and long-term receivables | Investments, advances and long-term receivables | 8 | | 43,515 | | | 43,164 | | Investments, advances and long-term receivables | 8 | | 49,793 | | | 45,195 | |
| Property, plant and equipment, at cost, less accumulated depreciation and depletion | Property, plant and equipment, at cost, less accumulated depreciation and depletion | 9 | | 227,553 | | | 253,018 | | Property, plant and equipment, at cost, less accumulated depreciation and depletion | 9 | | 204,692 | | | 216,552 | |
| Other assets, including intangibles - net | | | 16,789 | | | 16,363 | | |
| Total assets | | | 332,750 | | | 362,597 | | |
| Other assets, including intangibles – net | | Other assets, including intangibles – net | | | 16,951 | | | 18,022 | |
| Total Assets | | Total Assets | | | 369,067 | | | 338,923 | |
| | Liabilities | | | |
| LIABILITIES | | LIABILITIES | | | | |
| Current liabilities | Current liabilities | | | Current liabilities | | | | |
| Notes and loans payable | Notes and loans payable | 6 | | 20,458 | | | 20,578 | | Notes and loans payable | 6 | | 634 | | | 4,276 | |
| Accounts payable and accrued liabilities | Accounts payable and accrued liabilities | 6 | | 35,221 | | | 41,831 | | Accounts payable and accrued liabilities | 6 | | 63,197 | | | 50,766 | |
| Income taxes payable | Income taxes payable | | | 684 | | | 1,580 | | Income taxes payable | | | 5,214 | | | 1,601 | |
| Total current liabilities | Total current liabilities | | | 56,363 | | | 63,989 | | Total current liabilities | | | 69,045 | | | 56,643 | |
| Long-term debt | Long-term debt | 14 | | 47,182 | | | 26,342 | | Long-term debt | 14 | | 40,559 | | | 43,428 | |
| Postretirement benefits reserves | Postretirement benefits reserves | 17 | | 22,415 | | | 22,304 | | Postretirement benefits reserves | 17 | | 10,045 | | | 18,430 | |
| Deferred income tax liabilities | Deferred income tax liabilities | 19 | | 18,165 | | | 25,620 | | Deferred income tax liabilities | 19 | | 22,874 | | | 20,165 | |
| Long-term obligations to equity companies | Long-term obligations to equity companies | | | 3,253 | | | 3,988 | | Long-term obligations to equity companies | | | 2,338 | | | 2,857 | |
| Other long-term obligations | Other long-term obligations | | | 21,242 | | | 21,416 | | Other long-term obligations | | | 21,733 | | | 21,717 | |
| Total liabilities | | | 168,620 | | | 163,659 | | |
| Total Liabilities | | Total Liabilities | | | 166,594 | | | 163,240 | |
| | Commitments and contingencies | Commitments and contingencies | 16 | | 0 | | 0 | Commitments and contingencies | 16 | | | |
| | Equity | | | |
| EQUITY | | EQUITY | | | | |
Common stock without par value (9,000 million shares authorized, 8,019 million shares issued) | Common stock without par value (9,000 million shares authorized, 8,019 million shares issued) | | | 15,688 | | | 15,637 | | Common stock without par value (9,000 million shares authorized, 8,019 million shares issued) | | | 15,752 | | | 15,746 | |
| Earnings reinvested | Earnings reinvested | | | 383,943 | | | 421,341 | | Earnings reinvested | | | 432,860 | | | 392,059 | |
| Accumulated other comprehensive income | Accumulated other comprehensive income | | | (16,705) | | | (19,493) | | Accumulated other comprehensive income | | | (13,270) | | | (13,764) | |
Common stock held in treasury (3,786 million shares in 2020 and 3,785 million shares in 2019) | | | (225,776) | | | (225,835) | | |
Common stock held in treasury (3,937 million shares in 2022 and 3,780 million shares in 2021) | | Common stock held in treasury (3,937 million shares in 2022 and 3,780 million shares in 2021) | | | (240,293) | | | (225,464) | |
| ExxonMobil share of equity | ExxonMobil share of equity | | | 157,150 | | | 191,650 | | ExxonMobil share of equity | | | 195,049 | | | 168,577 | |
| Noncontrolling interests | Noncontrolling interests | | | 6,980 | | | 7,288 | | Noncontrolling interests | | | 7,424 | | | 7,106 | |
| Total equity | | | 164,130 | | | 198,938 | | |
| Total liabilities and equity | | | 332,750 | | | 362,597 | | |
| Total Equity | | Total Equity | | | 202,473 | | | 175,683 | |
| Total Liabilities and Equity | | Total Liabilities and Equity | | | 369,067 | | | 338,923 | |
| | The information in the Notes to Consolidated Financial Statements is an integral part of these statements. | | The information in the Notes to Consolidated Financial Statements is an integral part of these statements. |
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
| | (millions of dollars) | | (millions of dollars) | Note Reference Number | | 2022 | | 2021 | | 2020 |
| | | | Note Reference Number | | 2020 | | 2019 | | 2018 | | | | | | |
| | | | | (millions of dollars) | |
| Cash flows from operating activities | | | | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES | | CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | |
| Net income (loss) including noncontrolling interests | Net income (loss) including noncontrolling interests | | | (23,251) | | | 14,774 | | | 21,421 | | Net income (loss) including noncontrolling interests | | | 57,577 | | | 23,598 | | | (23,251) | |
| Adjustments for noncash transactions | Adjustments for noncash transactions | | | Adjustments for noncash transactions | | | | |
| Depreciation and depletion (includes impairments) | Depreciation and depletion (includes impairments) | 3, 9 | | 46,009 | | | 18,998 | | | 18,745 | | Depreciation and depletion (includes impairments) | 2, 9 | | 24,040 | | | 20,607 | | | 46,009 | |
| Deferred income tax charges/(credits) | Deferred income tax charges/(credits) | 19 | | (8,856) | | | (944) | | | (60) | | Deferred income tax charges/(credits) | 19 | | 3,758 | | | 303 | | | (8,856) | |
Postretirement benefits expense in excess of/(less than) net payments | Postretirement benefits expense in excess of/(less than) net payments | | | 498 | | | 109 | | | 1,070 | | Postretirement benefits expense in excess of/(less than) net payments | | | (2,981) | | | 754 | | | 498 | |
Other long-term obligation provisions in excess of/(less than) payments | Other long-term obligation provisions in excess of/(less than) payments | | | (1,269) | | | (3,038) | | | (68) | | Other long-term obligation provisions in excess of/(less than) payments | | | (1,932) | | | 50 | | | (1,269) | |
Dividends received greater than/(less than) equity in current earnings of equity companies | Dividends received greater than/(less than) equity in current earnings of equity companies | | | 979 | | | (936) | | | (1,684) | | Dividends received greater than/(less than) equity in current earnings of equity companies | | | (2,446) | | | (668) | | | 979 | |
| Changes in operational working capital, excluding cash and debt | Changes in operational working capital, excluding cash and debt | | Changes in operational working capital, excluding cash and debt | | | |
| Reduction/(increase) | - Notes and accounts receivable | | | 5,384 | | | (2,640) | | | (545) | | |
| | - Inventories | | | (315) | | | 72 | | | (3,107) | | |
| | - Other current assets | | | 420 | | | (234) | | | (25) | | |
| Increase/(reduction) | - Accounts and other payables | | | (7,142) | | | 3,725 | | | 2,321 | | |
Notes and accounts receivable reduction/(increase) | | Notes and accounts receivable reduction/(increase) | | (11,019) | | | (12,098) | | | 5,384 | |
Inventories reduction/(increase) | | Inventories reduction/(increase) | | | (6,947) | | | (489) | | | (315) | |
Other current assets reduction/(increase) | | Other current assets reduction/(increase) | | | (688) | | | (71) | | | 420 | |
Accounts and other payables increase/(reduction) | | Accounts and other payables increase/(reduction) | | | 18,460 | | | 16,820 | | | (7,142) | |
| Net (gain)/loss on asset sales | Net (gain)/loss on asset sales | 5 | | 4 | | | (1,710) | | | (1,993) | | Net (gain)/loss on asset sales | 5 | | (1,034) | | | (1,207) | | | 4 | |
| All other items - net | All other items - net | | | 2,207 | | | 1,540 | | | (61) | | All other items - net | | | 9 | | | 530 | | | 2,207 | |
| Net cash provided by operating activities | Net cash provided by operating activities | | | 14,668 | | | 29,716 | | | 36,014 | | Net cash provided by operating activities | | | 76,797 | | | 48,129 | | | 14,668 | |
| Cash flows from investing activities | | | | |
| | CASH FLOWS FROM INVESTING ACTIVITIES | | CASH FLOWS FROM INVESTING ACTIVITIES | | | | |
| Additions to property, plant and equipment | Additions to property, plant and equipment | | | (17,282) | | | (24,361) | | | (19,574) | | Additions to property, plant and equipment | | | (18,407) | | | (12,076) | | | (17,282) | |
Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments | | | 999 | | | 3,692 | | | 4,123 | | |
| Proceeds from asset sales and returns of investments | | Proceeds from asset sales and returns of investments | | | 5,247 | | | 3,176 | | | 999 | |
| Additional investments and advances | Additional investments and advances | | | (4,857) | | | (3,905) | | | (1,981) | | Additional investments and advances | | | (3,090) | | | (2,817) | | | (4,857) | |
| Other investing activities including collection of advances | Other investing activities including collection of advances | | | 2,681 | | | 1,490 | | | 986 | | Other investing activities including collection of advances | | | 1,508 | | | 1,482 | | | 2,681 | |
| Net cash used in investing activities | Net cash used in investing activities | | | (18,459) | | | (23,084) | | | (16,446) | | Net cash used in investing activities | | | (14,742) | | | (10,235) | | | (18,459) | |
| Cash flows from financing activities | | | | |
| | CASH FLOWS FROM FINANCING ACTIVITIES | | CASH FLOWS FROM FINANCING ACTIVITIES | | | | |
| Additions to long-term debt | Additions to long-term debt | | | 23,186 | | | 7,052 | | | 46 | | Additions to long-term debt | | | 637 | | | 46 | | | 23,186 | |
| Reductions in long-term debt | Reductions in long-term debt | | | (8) | | | (1) | | | 0 | | Reductions in long-term debt | | | (5) | | | (8) | | | (8) | |
| | Reductions in short-term debt | | | (1,703) | | | (4,043) | | | (4,752) | | |
Additions to short-term debt (1) | | Additions to short-term debt (1) | | | 198 | | | 12,687 | | | 35,396 | |
Reductions in short-term debt (1) | | Reductions in short-term debt (1) | | | (8,075) | | | (29,396) | | | (28,742) | |
Additions/(reductions) in commercial paper, and debt with three months or less maturity | Additions/(reductions) in commercial paper, and debt with three months or less maturity | 5 | | (1,334) | | | 5,654 | | | (219) | | Additions/(reductions) in commercial paper, and debt with three months or less maturity | | 25 | | | (2,983) | | | (9,691) | |
| Contingent consideration payments | Contingent consideration payments | | (21) | | | 0 | | | 0 | | Contingent consideration payments | | (58) | | | (30) | | | (21) | |
| Cash dividends to ExxonMobil shareholders | Cash dividends to ExxonMobil shareholders | | | (14,865) | | | (14,652) | | | (13,798) | | Cash dividends to ExxonMobil shareholders | | | (14,939) | | | (14,924) | | | (14,865) | |
| Cash dividends to noncontrolling interests | Cash dividends to noncontrolling interests | | | (188) | | | (192) | | | (243) | | Cash dividends to noncontrolling interests | | | (267) | | | (224) | | | (188) | |
| Changes in noncontrolling interests | Changes in noncontrolling interests | | | 623 | | | 158 | | | 146 | | Changes in noncontrolling interests | | | (1,475) | | | (436) | | | 623 | |
| Common stock acquired | Common stock acquired | | | (405) | | | (594) | | | (626) | | Common stock acquired | | | (15,155) | | | (155) | | | (405) | |
| Net cash provided by (used in) financing activities | Net cash provided by (used in) financing activities | | | 5,285 | | | (6,618) | | | (19,446) | | Net cash provided by (used in) financing activities | | | (39,114) | | | (35,423) | | | 5,285 | |
| | Effects of exchange rate changes on cash | Effects of exchange rate changes on cash | | | (219) | | | 33 | | | (257) | | Effects of exchange rate changes on cash | | | (78) | | | (33) | | | (219) | |
| Increase/(decrease) in cash and cash equivalents | Increase/(decrease) in cash and cash equivalents | | | 1,275 | | | 47 | | | (135) | | Increase/(decrease) in cash and cash equivalents | | | 22,863 | | | 2,438 | | | 1,275 | |
| Cash and cash equivalents at beginning of year | Cash and cash equivalents at beginning of year | | | 3,089 | | | 3,042 | | | 3,177 | | Cash and cash equivalents at beginning of year | | | 6,802 | | | 4,364 | | | 3,089 | |
| Cash and cash equivalents at end of year | Cash and cash equivalents at end of year | | | 4,364 | | | 3,089 | | | 3,042 | | Cash and cash equivalents at end of year | | | 29,665 | | | 6,802 | | | 4,364 | |
| (1) Includes commercial paper with a maturity greater than three months. | | (1) Includes commercial paper with a maturity greater than three months. |
| | The information in the Notes to Consolidated Financial Statements is an integral part of these statements. | | The information in the Notes to Consolidated Financial Statements is an integral part of these statements. |
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
| | | | ExxonMobil Share of Equity | | | | | | ExxonMobil Share of Equity | |
| | | Common
Stock | | Earnings
Reinvested | | Accumulated Other Comprehensive Income | | Common
Stock Held in
Treasury | | ExxonMobil
Share of
Equity | | Non-controlling Interests | | Total
Equity | | | |
(millions of dollars) | | (millions of dollars) | Common
Stock | Earnings
Reinvested | Accumulated Other Comprehensive Income | Common
Stock Held in
Treasury | ExxonMobil
Share of
Equity | Non-controlling Interests | Total
Equity |
| | | (millions of dollars) | | | | |
| Balance as of December 31, 2017 | 14,656 | | | 414,540 | | | (16,262) | | | (225,246) | | | 187,688 | | | 6,812 | | | 194,500 | | |
| Balance as of December 31, 2019 | | Balance as of December 31, 2019 | 15,637 | | 421,341 | | (19,493) | | (225,835) | | 191,650 | | 7,288 | | 198,938 | |
| Amortization of stock-based awards | Amortization of stock-based awards | 758 | | | — | | | — | | | — | | | 758 | | | — | | | 758 | | Amortization of stock-based awards | 696 | | — | | — | | — | | 696 | | — | | 696 | |
| Other | Other | (156) | | | — | | | — | | | — | | | (156) | | | 436 | | | 280 | | Other | (645) | | — | | — | | — | | (645) | | 692 | | 47 | |
| Net income (loss) for the year | Net income (loss) for the year | — | | | 20,840 | | | — | | | — | | | 20,840 | | | 581 | | | 21,421 | | Net income (loss) for the year | — | | (22,440) | | — | | — | | (22,440) | | (811) | | (23,251) | |
| Dividends - common shares | Dividends - common shares | — | | | (13,798) | | | — | | | — | | | (13,798) | | | (243) | | | (14,041) | | Dividends - common shares | — | | (14,865) | | — | | — | | (14,865) | | (188) | | (15,053) | |
| Cumulative effect of accounting change | Cumulative effect of accounting change | — | | | 71 | | | (39) | | | — | | | 32 | | | 15 | | | 47 | | Cumulative effect of accounting change | — | | (93) | | — | | — | | (93) | | (1) | | (94) | |
| Other comprehensive income | Other comprehensive income | — | | | — | | | (3,263) | | | — | | | (3,263) | | | (407) | | | (3,670) | | Other comprehensive income | — | | — | | 2,788 | | — | | 2,788 | | 68 | | 2,856 | |
| Acquisitions, at cost | Acquisitions, at cost | — | | | — | | | — | | | (626) | | | (626) | | | (460) | | | (1,086) | | Acquisitions, at cost | — | | — | | — | | (405) | | (405) | | (68) | | (473) | |
| | Dispositions | Dispositions | — | | | — | | | — | | | 319 | | | 319 | | | — | | | 319 | | Dispositions | — | | — | | — | | 464 | | 464 | | — | | 464 | |
| Balance as of December 31, 2018 | 15,258 | | | 421,653 | | | (19,564) | | | (225,553) | | | 191,794 | | | 6,734 | | | 198,528 | | |
| Balance as of December 31, 2020 | | Balance as of December 31, 2020 | 15,688 | | 383,943 | | (16,705) | | (225,776) | | 157,150 | | 6,980 | | 164,130 | |
| Amortization of stock-based awards | Amortization of stock-based awards | 697 | | | — | | | — | | | — | | | 697 | | | — | | | 697 | | Amortization of stock-based awards | 534 | | — | | — | | — | | 534 | | — | | 534 | |
| Other | Other | (318) | | | — | | | — | | | — | | | (318) | | | 489 | | | 171 | | Other | (476) | | — | | — | | — | | (476) | | 115 | | (361) | |
| Net income (loss) for the year | Net income (loss) for the year | — | | | 14,340 | | | — | | | — | | | 14,340 | | | 434 | | | 14,774 | | Net income (loss) for the year | — | | 23,040 | | — | | — | | 23,040 | | 558 | | 23,598 | |
| Dividends - common shares | Dividends - common shares | — | | | (14,652) | | | — | | | — | | | (14,652) | | | (192) | | | (14,844) | | Dividends - common shares | — | | (14,924) | | — | | — | | (14,924) | | (224) | | (15,148) | |
| | Other comprehensive income | Other comprehensive income | — | | | — | | | 71 | | | — | | | 71 | | | 154 | | | 225 | | Other comprehensive income | — | | — | | 2,941 | | — | | 2,941 | | 228 | | 3,169 | |
| Acquisitions, at cost | Acquisitions, at cost | — | | | — | | | — | | | (594) | | | (594) | | | (331) | | | (925) | | Acquisitions, at cost | — | | — | | — | | (155) | | (155) | | (551) | | (706) | |
| Dispositions | Dispositions | — | | | — | | | — | | | 312 | | | 312 | | | — | | | 312 | | Dispositions | — | | — | | — | | 467 | | 467 | | — | | 467 | |
| Balance as of December 31, 2019 | 15,637 | | | 421,341 | | | (19,493) | | | (225,835) | | | 191,650 | | | 7,288 | | | 198,938 | | |
| Balance as of December 31, 2021 | | Balance as of December 31, 2021 | 15,746 | | 392,059 | | (13,764) | | (225,464) | | 168,577 | | 7,106 | | 175,683 | |
| Amortization of stock-based awards | Amortization of stock-based awards | 696 | | | — | | | — | | | — | | | 696 | | | — | | | 696 | | Amortization of stock-based awards | 481 | | — | | — | | — | | 481 | | — | | 481 | |
| Other | Other | (645) | | | — | | | — | | | — | | | (645) | | | 692 | | | 47 | | Other | (475) | | — | | — | | — | | (475) | | 405 | | (70) | |
| Net income (loss) for the year | Net income (loss) for the year | — | | | (22,440) | | | — | | | — | | | (22,440) | | | (811) | | | (23,251) | | Net income (loss) for the year | — | | 55,740 | | — | | — | | 55,740 | | 1,837 | | 57,577 | |
| Dividends - common shares | Dividends - common shares | — | | | (14,865) | | | — | | | — | | | (14,865) | | | (188) | | | (15,053) | | Dividends - common shares | — | | (14,939) | | — | | — | | (14,939) | | (267) | | (15,206) | |
| Cumulative effect of accounting change | — | | | (93) | | | 0 | | | — | | | (93) | | | (1) | | | (94) | | |
| | Other comprehensive income | Other comprehensive income | — | | | — | | | 2,788 | | | — | | | 2,788 | | | 68 | | | 2,856 | | Other comprehensive income | — | | — | | 494 | | — | | 494 | | (178) | | 316 | |
| Acquisitions, at cost | Acquisitions, at cost | — | | | — | | | — | | | (405) | | | (405) | | | (68) | | | (473) | | Acquisitions, at cost | — | | — | | — | | (15,295) | | (15,295) | | (1,479) | | (16,774) | |
| Dispositions | Dispositions | — | | | — | | | — | | | 464 | | | 464 | | | — | | | 464 | | Dispositions | — | | — | | — | | 466 | | 466 | | — | | 466 | |
| Balance as of December 31, 2020 | 15,688 | | | 383,943 | | | (16,705) | | | (225,776) | | | 157,150 | | | 6,980 | | | 164,130 | | |
| Balance as of December 31, 2022 | | Balance as of December 31, 2022 | 15,752 | | 432,860 | | (13,270) | | (240,293) | | 195,049 | | 7,424 | | 202,473 | |
| | Common Stock Share Activity | Issued | | Held in
Treasury | | Outstanding | |
Common Stock Share Activity (millions of shares) | | Common Stock Share Activity (millions of shares) | Issued | Held in
Treasury | Outstanding |
| | | (millions of shares) | |
| Balance as of December 31, 2017 | 8,019 | | | (3,780) | | | 4,239 | | |
| Balance as of December 31, 2019 | | Balance as of December 31, 2019 | 8,019 | | (3,785) | | 4,234 | |
| Acquisitions | Acquisitions | — | | | (8) | | | (8) | | Acquisitions | — | | (8) | | (8) | |
| | Dispositions | Dispositions | — | | | 6 | | | 6 | | Dispositions | — | | 7 | | 7 | |
| Balance as of December 31, 2018 | 8,019 | | | (3,782) | | | 4,237 | | |
| Balance as of December 31, 2020 | | Balance as of December 31, 2020 | 8,019 | | (3,786) | | 4,233 | |
| Acquisitions | Acquisitions | — | | | (8) | | | (8) | | Acquisitions | — | | (2) | | (2) | |
| Dispositions | Dispositions | — | | | 5 | | | 5 | | Dispositions | — | | 8 | | 8 | |
| Balance as of December 31, 2019 | 8,019 | | | (3,785) | | | 4,234 | | |
| Balance as of December 31, 2021 | | Balance as of December 31, 2021 | 8,019 | | (3,780) | | 4,239 | |
| Acquisitions | Acquisitions | — | | | (8) | | | (8) | | Acquisitions | — | | (165) | | (165) | |
| Dispositions | Dispositions | — | | | 7 | | | 7 | | Dispositions | — | | 8 | | 8 | |
| Balance as of December 31, 2020 | 8,019 | | | (3,786) | | | 4,233 | | |
| Balance as of December 31, 2022 | | Balance as of December 31, 2022 | 8,019 | | (3,937) | | 4,082 | |
| | The information in the Notes to Consolidated Financial Statements is an integral part of these statements. | | The information in the Notes to Consolidated Financial Statements is an integral part of these statements. |
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Exxon Mobil Corporation.
The Corporation’s principal business involves exploration for, and production of, crude oil and natural gas andgas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a wide variety of specialty products.products; and pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen and lower-emission fuels.
The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Prior years’ data hashave been reclassified in certain cases to conform to the 20202022 presentation basis.
1. Summary of Accounting Policies
Principles of Consolidation and Accounting for InvestmentsEnvironmental Liabilities
The Corporation accrues environmental liabilities when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. ExxonMobil has accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency has identified ExxonMobil as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could mitigate ExxonMobil’s actual joint and several liability exposure. At present, no individual site is expected to have losses material to ExxonMobil’s operations or financial condition. Consolidated Financial Statements includecompany provisions made in 2022 for environmental liabilities were $185 million ($146 million in 2021), and the accountsbalance sheet reflects liabilities of subsidiaries$730 million as of December 31, 2022, and $807 million as of December 31, 2021.
MARKET RISKS
| | | | | | | | | | | | | | | | | |
Worldwide Average Realizations (1) | 2022 | | 2021 | | 2020 |
| Crude oil and NGL ($ per barrel) | 87.25 | | | 61.89 | | | 35.41 | |
| Natural gas ($ per thousand cubic feet) | 7.48 | | | 4.33 | | | 2.01 | |
| | | | | |
(1) Consolidated subsidiaries. |
Crude oil, natural gas, petroleum product, and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings have varied across the Corporation's operating segments. For the year 2023, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $500 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives. Similarly, a $0.10 per thousand cubic feet change in the worldwide average gas realization would have approximately a $140 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, results of trading activities, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide broad indicators of changes in the earnings experienced in any particular period.
In the very competitive petroleum and petrochemical environment, earnings are primarily determined by margin capture rather than absolute price levels of products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather.
The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the Corporation’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the Corporation’s financial strength as a competitive advantage.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Instead, where such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery and chemical complexes. Additionally, intersegment sales are at market-based prices. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity, and transportation capabilities. Refer to Note 18 for additional information on intersegment revenue.
Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to global economic conditions, political events, decisions by OPEC and other major government resource owners and other factors, industry economics over the long term will continue to be driven by market supply and demand. The Corporation evaluates investments over a range of prices, including estimated greenhouse gas emission costs even in jurisdictions without a current greenhouse gas pricing policy.
The Corporation has an active asset management program in which nonstrategic assets are considered for divestment. The asset management program includes a disciplined, regular review to ensure that assets are contributing to the Corporation’s strategic objectives.
Risk Management
The Corporation’s size, strong capital structure, geographic diversity, and the complementary nature of its business segments reduce the Corporation’s enterprise-wide risk from changes in commodity prices, currency rates, and interest rates. In addition, the Corporation controls. Theyuses commodity-based contracts, including derivatives, to manage commodity price risk and to generate returns from trading. The Corporation’s commodity derivatives are not accounted for under hedge accounting. At times, the Corporation also includeenters into currency and interest rate derivatives, none of which are material to the Corporation’s sharefinancial position as of December 31, 2022 and 2021, or results of operations for the years ended 2022, 2021, and 2020. Credit risk associated with the Corporation’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of and financial limits placed on derivative counterparties. No material market or credit risks to the Corporation’s financial position, results of operations or liquidity exist as a result of the undividedderivatives described in Note 13. The Corporation maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity.
The Corporation is exposed to changes in interest rates, primarily on its short-term debt and the portion of long-term debt that carries floating interest rates. The impact of a 100-basis-point change in certain upstreaminterest rates affecting the Corporation’s debt would not be material to earnings or cash flow. The Corporation has access to significant capacity of long-term and short-term liquidity. Internally generated funds are generally expected to cover financial requirements, supplemented by long-term and short-term debt as required. Commercial paper is used to balance short-term liquidity requirements. Some joint-venture partners are dependent on the credit markets, and their funding ability may impact the development pace of joint-venture projects.
The Corporation conducts business in many foreign currencies and is subject to exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. Fluctuations in exchange rates are often offsetting and the impacts on ExxonMobil’s geographically and functionally diverse operations are varied. The Corporation makes limited use of currency exchange contracts to mitigate the impact of changes in currency values, and exposures related to the Corporation’s use of these contracts are not material.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CRITICAL ACCOUNTING ESTIMATES
The Corporation’s accounting and financial reporting fairly reflect its integrated business model involving exploration for, and production of, crude oil and natural gas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals, and a wide variety of specialty products; and pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen, and lower-emission fuels. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Amounts representingexpenses and the Corporation’s interest in entities that it does not control, but over which it exercises significant influence, are included in “Investments, advancesdisclosure of contingent assets and long-term receivables”.liabilities. The Corporation’s share of the net income of these companies is includedaccounting policies are summarized in the Consolidated Statement of Income caption “Income from equity affiliates”.Note 1.
Majority ownership is normally the indicator of control that is the basis on which subsidiaries are consolidated. However, certain factors may indicate that a majority-owned investment is not controlledOil and therefore should be accounted for using the equity method of accounting. These factors occur where the minority shareholders are granted by law or by contract substantive participating rights. These include the right to approve operating policies, expense budgets, financing and investment plans, and management compensation and succession plans.
Evidence of loss in value that might indicate impairment of investments in companies accounted for on the equity method is assessed to determine if such evidence represents a loss in value that is other than temporary. Examples of key indicators include a history of operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If evidence of an other than temporary loss in fair value below carrying amount is determined, an impairment is recognized. In the absence of market prices for the investment, discounted cash flows are used to assess fair value.
Investments in equity securities other than consolidated subsidiaries and equity method investments are measured at fair value with changes in fair value recognized in net income. The Corporation uses the modified approach for equity securities that do not have a readily determinable fair value. This modified approach measures investments at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions in a similar investment of the same issuer.Natural Gas Reserves
The Corporation’s shareestimation of the cumulative foreign exchange translation adjustment for equity method investments is reported in “Accumulated other comprehensive income”.
Revenue Recognition
The Corporation generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases (e.g., natural gas), products may be sold under long-term agreements, with periodic price adjustments to reflect market conditions. Revenue is recognized at the amount the Corporation expects to receive when the customer has taken control, which is typically when title transfers and the customer has assumed the risks and rewards of ownership. The prices of certain sales are based on price indices that are sometimes not available until the next period. In such cases, estimated realizations are accrued when the sale is recognized, and are finalized when the price is available. Such adjustments to revenue from performance obligations satisfied in previous periods are not significant. Payment for revenue transactions is typically due within 30 days. Future volume delivery obligations that are unsatisfied at the end of the period are expected to be fulfilled through ordinary production or purchases. These performance obligations are based on market prices at the time of the transaction and are fully constrained due to market price volatility.
Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and recorded as exchanges measured at the book value of the item sold.
“Sales and other operating revenue” and “Notes and accounts receivable” primarily arise from contracts with customers. Long-term receivables are primarily from non-customers. Contract assets are mainly from marketing assistance programs and are not significant. Contract liabilities are mainly customer prepayments and accruals of expected volume discounts and are not significant.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income and Other Taxes
The Corporation excludes from the Consolidated Statement of Income certain sales and value-added taxes imposed on and concurrent with revenue-producing transactions with customers and collected on behalf of governmental authorities. Similar taxes, for which the Corporation is not considered to be an agent for the government, are reported on a gross basis (included in both “Sales and other operating revenue” and “Other taxes and duties”).
The Corporation accounts for U.S. tax on global intangible low-taxed income as an income tax expense in the period in which it is incurred.
Derivative Instruments
The Corporation may use derivative instruments for trading purposes and to offset exposures associated with commodity prices, foreign currency exchange rates and interest rates that arise from existing assets, liabilities, firm commitments and forecasted transactions. All derivative instruments, except those designated as normal purchase and normal sale, are recorded at fair value. Derivative assets and liabilities with the same counterparty are netted if the right of offset exists and certain other criteria are met. Collateral payables or receivables are netted against derivative assets and derivative liabilities, respectively.
Recognition and classification of the gain or loss that results from adjusting a derivative to fair value depends on the purpose for the derivative. All gains and losses from derivative instruments for which the Corporation does not apply hedge accounting are immediately recognized in earnings. The Corporation may designate derivatives as fair value or cash flow hedges. For fair value hedges, the gain or loss from derivative instruments and the offsetting gain or loss from the hedged item are recognized in earnings. For cash flow hedges, the gain or loss from the derivative instrument is initially reported as a component of other comprehensive income and subsequently reclassified into earnings in the period that the forecasted transaction affects earnings.
Fair Value
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.
Inventories
Crude oil, products and merchandise inventories are carried at the lower of current market value or cost (generally determined under the last-in, first-out method – LIFO). Inventory costs include expenditures and other charges (including depreciation) directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less.
Property, Plant and Equipment
Cost Basis. The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. Exploratory well costs are carried as an asset when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Development costs, including costs of productive wells and development dry holes, are capitalized.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration.
Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and natural gas reserve volumes. Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using the unit-of-production ratesvolumes is an ongoing process based on the amountrigorous technical evaluations, commercial and market assessments, and detailed analysis of well information such as flow rates and reservoir pressure declines, development and production costs, and other factors. The estimation of proved developed reserves is controlled by the Corporation through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Global Reserves and Resources Group which has significant technical experience, culminating in reviews with and approval by senior management. Notably, the Corporation does not use specific quantitative reserve targets to determine compensation. Key features of oilthe reserve estimation process are covered in Disclosure of Reserves in Item 2.
Oil and natural gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method,reserves include both proved and unproved reserves.
•Proved oil and natural gas reserves are determined in accordance with Securities and Exchange Commission (SEC) requirements. Proved reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic and operating conditions and government regulations. Proved reserves are determined using the average of first-of-month oil and natural gas prices during the reporting year.
Proved reserves can be further subdivided into developed and undeveloped reserves. Proved developed reserves include amounts which are expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include amounts expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion. Proved undeveloped reserves are recognized only if a development plan has been adopted indicating that the reserves are scheduled to be drilled within five years, unless specific circumstances support a longer period of time.
The Corporation is reasonably certain that proved reserves will be produced. However, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals, government policy, consumer preferences, and significant changes in oil and natural gas price levels.
•Unproved reserves are quantities of oil and natural gas with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that, together with proved reserves, are as likely as not to be recovered.
Revisions in previously estimated volumes of proved reserves for existing fields can occur due to the evaluation or re-evaluation of (1) already available geologic, reservoir, or production data, (2) new geologic, reservoir, or production data, or (3) changes in the average of first-of-month oil and natural gas prices and/or costs that are used in the estimation of reserves. Revisions can also result from significant changes in development strategy or production equipment and facility capacity.
Unit-of-Production Depreciation
Oil and natural gas reserve volumes are consideredused as the basis to calculate unit-of-production depreciation rates for most upstream assets. Depreciation is calculated by taking the ratio of asset cost to total proved reserves or proved developed reserves applied to actual production. The volumes produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valveand asset cost are known, while proved reserves are based on the lease or field storage tank. estimates that are subject to some variability.
In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative method is used. The straight-line method is used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the Corporation uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes.
Investments in refinery, chemical process, and lubes basestock manufacturing equipment are generally depreciated on a straight-line basis over a 25-year life. Service station buildings and fixed improvements generally are depreciated over a 20-year life. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Impairment Assessment.
The Corporation tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. AmongThe Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of ASC 360 and ASC 932, and relies, in part, on the Corporation’s planning and budgeting cycle.
Because the lifespans of the vast majority of the Corporation’s major assets are measured in decades, the future cash flows of these assets are predominantly based on long-term oil and natural gas commodity prices and industry margins, development costs, and production costs. Significant reductions in the Corporation’s view of oil or natural gas commodity prices or margin ranges, especially the longer-term prices and margins, and changes in the development plans, including decisions to defer, reduce, or eliminate planned capital spending, can be an indicator of potential impairment. Other events or changes in circumstances, which could indicate that the carrying valueincluding indicators outlined in ASC 360, can be indicators of an asset or asset group may not be recoverable are the following:
•a significant decrease in the market price of a long-lived asset;
•a significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a significant decrease in current and projected reserve volumes;
•a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator;
•an accumulation of project costs significantly in excess of the amount originally expected;
•a current-period operating loss combined with a history and forecast of operating or cash flow losses; and
•a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
Asset valuation analysis, profitability reviews and other periodic control processes assist the Corporation in assessing whether events or changes in circumstances indicate the carrying amounts of any of its assets may not be recoverable.potential impairment as well.
In general, the Corporation does not view temporarily low prices or margins as an indication of impairment. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments, and technology and efficiency advancements. OPEC investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities, alternative energy sources, and levels of prosperity. Because the lifespans of the vast majority of the Corporation’s major assets are measured in decades, the value of these assets is predominantly based on long-term views of future commodity prices and development and production costs. During the lifespan of theseits major assets, the Corporation expects that oil and gas prices and industry margins will experience significant volatility, and consequentlyvolatility. Consequently, these assets will experience periods of higher earnings and periods of lower earnings, or even losses.
In assessing whether events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the Corporation considers recent periods of operating losses in the context of its longer-term view of prices. While near-term prices are subject to wide fluctuations, longer-term price views are more stable and meaningfulmargins.
Outlook for purposes of assessing future cash flows.
When the industry experiences a prolongedEnergy and deep reduction in commodity prices, the market supply and demand conditions may result in changes to the Corporation’s price or margin assumptions it uses for its capital investment decisions. To the extent those changes result in a significant reduction to its oil price, natural gas price or margin ranges, the Corporation may consider that situation, in conjunction with other events or changes in circumstances such as a history of operating losses, an indicator of potential impairment for certain assets.
In the Upstream, the standardized measure of discounted cash flows included in the Supplemental Information on Oil and Gas Exploration and Production Activities is required to use prices based on the average of first-of-month prices. These prices represent discrete points in time and could be higher or lower than the Corporation’s price assumptions which are used for impairment assessments. Cash Flow Assessment. The Corporation believes the standardized measure does not provide a reliable estimate of the expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its oil and gas reserves and therefore does not consider it relevant in determining whether events or changes in circumstances indicate the need for an impairment assessment.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of ASC 360 and ASC 932, and relies in part on the Corporation’sannual planning and budgeting cycle. process, known as the Corporate Plan, is the mechanism by which resources (capital, operating expenses, and people) are allocated across the Corporation. The foundation for the assumptions supporting the Corporate Plan is the Outlook for Energy (Outlook), which contains the Corporation’s demand and supply projections based on its assessment of current trends in technology, government policies, consumer preferences, geopolitics, economic development, and other factors. Reflective of the existing global policy environment, the Outlook does not attempt to project the degree of necessary future policy and technology advancement and deployment for the world, or the Corporation, to meet net zero by 2050. As future policies and technology advancements emerge, they will be incorporated into the Outlook, and the Corporation’s business plans will be updated accordingly.
If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on the Corporation’s assumptions which are developed in the annual planningCorporate Plan, which is reviewed and budgeting process,approved by the Board of Directors, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the Corporation’s assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, development and operating costs including greenhouse gas emission prices, and foreign currency exchange rates. Notably, when assessing future cash flows, the Corporation includes the estimated costs in support of reaching its 2030 greenhouse gas emission-reduction plans, including its goal of net-zero greenhouse gas emissions (Scope 1 and 2) from unconventional operated assets in the Permian Basin. Volumes are based on projected field and facility production profiles, throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities. Cash flow estimatesExxonMobil considers a range of scenarios - including remote scenarios - to help inform perspective of the future and enhance strategic thinking over time. While third-party scenarios, such as the International Energy Agency's Net Zero Emissions by 2050, may be used for these purposes, they are not used as a basis for developing future cash flows for impairment testing excludeassessments. As part of the effectsCorporate Plan, the Company considers estimated greenhouse gas emission costs, even for jurisdictions without a current greenhouse gas pricing policy.
Fair Value of derivative instruments.
Impaired Assets. An asset group is impaired if its estimated undiscounted cash flows are less than the asset’sasset group’s carrying value. Impairments are measured by the amount by whichexcess of the carrying value exceedsover fair value. FairThe assessment of fair value is based onupon the views of a likely market participant. The principal parameters used to establish fair value include estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, throughput and product sales volumes, commodity prices if an active market exists forwhich are consistent with the average of third-party industry experts and government agencies, refining and chemical margins, drilling and development costs, operating costs, and discount rates which are reflective of the characteristics of the asset group, or discounted cash flows using a discount rate commensurate with the risk.group.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Impairment Estimates. Unproved properties are assessed periodically to determine whether they have been impaired. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the Corporation's future development plans, the estimated economic chance of success, and the length of time that the Corporation expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.
Other. Gains on salesLong-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of provedthe asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the assets are considered impaired and unproved properties are only recognized when thereadjusted to the lower value. Judgment is neither uncertainty about the recovery of costs applicablerequired to any interest retained nor any substantial obligation for future performance by the Corporation. Losses on properties sold are recognized when incurred or when the propertiesdetermine if assets are held for sale and to determine the fair value less cost to sell.
Investments accounted for by the equity method are assessed for possible impairment when events or changes in circumstances indicate that the carrying value of an investment may not be recoverable. Examples of key indicators include a history of operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If the decline in value of the propertiesinvestment is lessother than temporary, the carrying value of the investment is written down to fair value. In the absence of market prices for the investment, discounted cash flows are used to assess fair value, which requires significant judgment.
Recent Impairments. In early 2022, in response to Russia’s military action in Ukraine, the Corporation announced that it planned to discontinue operations on the Sakhalin-1 project (“Sakhalin”) and develop steps to exit the venture. The Corporation’s first quarter results included after-tax charges of $3.0 billion representing the impairment of its Upstream operations related to Sakhalin. (Refer to Note 2 for further information on Russia.) Other after-tax impairment charges of $1.6 billion and $0.3 billion were recognized in Upstream and Energy Products, respectively.
Interest costs incurredIn 2021, largely as a result of changes to finance expenditures duringUpstream development plans, the construction phaseCorporation recognized after-tax impairment charges of multiyear projects are capitalizedapproximately $1 billion. In 2020, as part of the historical costCorporation's annual review and approval of acquiring the constructed assets. The project construction phase commences with the developmentits business and strategic plan, a decision was made to no longer develop a significant portion of the detailed engineering designdry gas portfolio in the United States, Canada, and ends whenArgentina. The impairment of these assets resulted in after-tax charges of $18.4 billion in Upstream. Other after-tax impairment charges of $1.8 billion across the constructedyear related mainly to impairments of property, plant, and equipment, goodwill, and equity method investments.
Factors which could put further assets are readyat risk of impairment in the future include reductions in the Corporation’s price or margin outlooks, changes in the allocation of capital or development plans, reduced long-term demand for their intended use. Capitalized interestthe Corporation's products, and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural gas price or margin increases. However, due to the inherent difficulty in predicting future commodity prices or margins, and the relationship between industry prices and costs, are includedit is not practicable to reasonably estimate the existence or range of any potential future impairment charges related to the Corporation’s long-lived assets.
For further information regarding impairments in goodwill, equity method investments, property, plant, and equipment, and suspended wells, refer to Notes 3, 7, 9, and 10, respectively.
Asset Retirement Obligations
The Corporation is subject to retirement obligations for certain assets. The fair values of these obligations are depreciatedrecorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, discount rates, and inflation rates. See Note 9 for further information regarding asset retirement obligations.
Suspended Exploratory Well Costs
The Corporation continues capitalization of exploratory well costs when it has found a sufficient quantity of reserves to justify completion as a producing well and the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Assessing whether the Corporation is making sufficient progress on a project requires careful consideration of the facts and circumstances. The facts and circumstances that support continued capitalization of suspended wells at year-end are disclosed in Note 10.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Pension Benefits
The Corporation and its affiliates sponsor 75 defined benefit (pension) plans in 40 countries. The Pension and Other Postretirement Benefits footnote (Note 17) provides details on pension obligations, fund assets, and pension expense.
Some of these plans (primarily non-U.S.) provide pension benefits that are paid directly by their sponsoring affiliates out of corporate cash flow rather than a separate pension fund because applicable tax rules and regulatory practices do not encourage advance funding. Book reserves are established for these plans. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets.
For funded plans, including those in the U.S., pension obligations are financed in advance through segregated assets or insurance arrangements. These plans are managed in compliance with the requirements of governmental authorities and meet or exceed required funding levels as measured by relevant actuarial and government standards at the mandated measurement dates. In determining liabilities and required contributions, these standards often require approaches and assumptions that differ from those used for accounting purposes.
The Corporation will continue to make contributions to these funded plans as necessary. All defined-benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.
Pension accounting requires explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the discount rate for the benefit obligations, and the long-term rate for future salary increases. Pension assumptions are reviewed annually by outside actuaries and senior management. These assumptions are adjusted as appropriate to reflect changes in market rates and outlook. The long-term expected earnings rate on U.S. pension plan assets in 2022 was 4.6 percent. The 10-year and 20-year actual returns on U.S. pension plan assets were 4 percent and 7 percent, respectively. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class. A worldwide reduction of 0.5 percent in the long-term rate of return on assets would increase annual pension expense by approximately $140 million before tax.
Differences between actual returns on fund assets and the long-term expected return are not recognized in pension expense in the year that the difference occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected remaining service life of employees.
Litigation and Tax Contingencies
A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending lawsuits. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. For contingencies where an unfavorable outcome is reasonably possible and significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The status of significant claims is summarized in Note 16.
Management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past. Payments have not had a material adverse effect on our operations or financial condition. In the Corporation’s experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement.
The Corporation is subject to income taxation in many jurisdictions around the world. The benefits of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict. The Corporation’s unrecognized tax benefits and a description of open tax years are summarized in Note 19.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management, including the Corporation’s Chief Executive Officer, Chief Financial Officer, and Principal Accounting Officer, is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 2022.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2022, as stated in their report included in the Financial Section of this report.
| | | | | | | | |
| | |
Darren W. Woods Chief Executive Officer | Kathryn A. Mikells Senior Vice President and Chief Financial Officer | Len M. Fox Vice President and Controller (Principal Accounting Officer) |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Exxon Mobil Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheet of Exxon Mobil Corporation and its subsidiaries (the “Corporation”) as of December 31, 2022 and 2021, and the related consolidated statements of income, of comprehensive income, of changes in equity and of cash flows for each of the three years in the period ended December 31, 2022, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Corporation's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Corporation as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Corporation's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on the Corporation’s consolidated financial statements and on the Corporation's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Oil and Natural Gas Reserves on Upstream Property, Plant and Equipment, Net
As described in Notes 1, 9 and 18 to the consolidated financial statements, the Corporation's consolidated upstream property, plant and equipment (PP&E), net balance was $144.1 billion as of December 31, 2022, and the related depreciation and depletion expense for the year ended December 31, 2022 was $19.8 billion. Management uses the successful efforts method to account for its exploration and production activities. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. As disclosed by management, proved oil and natural gas reserve volumes are used as the basis to calculate unit-of-production depreciation rates for most upstream assets. The estimation of proved oil and natural gas reserve volumes is an ongoing process based on technical evaluations, commercial and market assessments, and detailed analysis of well information such as flow rates and reservoir pressure declines, development and production costs, among other factors. As further disclosed by management, reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Global Reserves and Resources Group (together "management's specialists").
The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural gas reserves on upstream PP&E, net is a critical audit matter are (i) the significant judgment by management, including the use of management's specialists, when developing the estimates of proved oil and natural gas reserve volumes, as the reserve volumes are based on engineering assumptions and methods, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods and assumptions used by management and its specialists in developing the estimates of proved oil and natural gas reserve volumes and the assumptions applied to the data related to future development costs, as applicable.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's estimates of proved oil and natural gas reserve volumes. The work of management's specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserve volumes. As a basis for using this work, the specialists' qualifications were understood and the Corporation's relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of the specialists' findings. These procedures also included, among others, testing the completeness and accuracy of the data related to future development costs. Additionally, these procedures included evaluating whether the assumptions applied to the data related to future development costs were reasonable considering the past performance of the Corporation.
/s/ PricewaterhouseCoopers LLP
Dallas, Texas
February 22, 2023
We have served as the Corporation’s auditor since 1934.
CONSOLIDATED STATEMENT OF INCOME
| | | | | | | | | | | | | | | | | | | | | | | |
(millions of dollars) | Note
Reference
Number | | 2022 | | 2021 | | 2020 |
| Revenues and other income | | | | | | | |
| Sales and other operating revenue | 18 | | 398,675 | | | 276,692 | | | 178,574 | |
| Income from equity affiliates | 7 | | 11,463 | | | 6,657 | | | 1,732 | |
| Other income | | | 3,542 | | | 2,291 | | | 1,196 | |
| Total revenues and other income | | | 413,680 | | | 285,640 | | | 181,502 | |
| Costs and other deductions | | | | | | | |
| Crude oil and product purchases | | | 228,959 | | | 155,164 | | | 94,007 | |
| Production and manufacturing expenses | | | 42,609 | | | 36,035 | | | 30,431 | |
| Selling, general and administrative expenses | | | 10,095 | | | 9,574 | | | 10,168 | |
| Depreciation and depletion (includes impairments) | 2, 9 | | 24,040 | | | 20,607 | | | 46,009 | |
| Exploration expenses, including dry holes | | | 1,025 | | | 1,054 | | | 1,285 | |
| Non-service pension and postretirement benefit expense | 17 | | 482 | | | 786 | | | 1,205 | |
| Interest expense | | | 798 | | | 947 | | | 1,158 | |
| Other taxes and duties | 19 | | 27,919 | | | 30,239 | | | 26,122 | |
| Total costs and other deductions | | | 335,927 | | | 254,406 | | | 210,385 | |
| Income (loss) before income taxes | | | 77,753 | | | 31,234 | | | (28,883) | |
| Income tax expense (benefit) | 19 | | 20,176 | | | 7,636 | | | (5,632) | |
| Net income (loss) including noncontrolling interests | | | 57,577 | | | 23,598 | | | (23,251) | |
| Net income (loss) attributable to noncontrolling interests | | | 1,837 | | | 558 | | | (811) | |
| Net income (loss) attributable to ExxonMobil | | | 55,740 | | | 23,040 | | | (22,440) | |
| | | | | | | |
Earnings (loss) per common share (dollars) | 12 | | 13.26 | | | 5.39 | | | (5.25) | |
| | | | | | | |
Earnings (loss) per common share - assuming dilution (dollars) | 12 | | 13.26 | | | 5.39 | | | (5.25) | |
| | | | | | | |
| The information in the Notes to Consolidated Financial Statements is an integral part of these statements. |
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
| | | | | | | | | | | | | | | | | |
| (millions of dollars) | 2022 | | 2021 | | 2020 |
| Net income (loss) including noncontrolling interests | 57,577 | | | 23,598 | | | (23,251) | |
| | | | | |
| Other comprehensive income (loss) (net of income taxes) | | | | | |
| Foreign exchange translation adjustment | (3,482) | | | (872) | | | 1,916 | |
| Adjustment for foreign exchange translation (gain)/loss included in net income | — | | | (2) | | | 14 | |
| Postretirement benefits reserves adjustment (excluding amortization) | 3,395 | | | 3,118 | | | 30 | |
| Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs | 403 | | | 925 | | | 896 | |
| Total other comprehensive income (loss) | 316 | | | 3,169 | | | 2,856 | |
| Comprehensive income (loss) including noncontrolling interests | 57,893 | | | 26,767 | | | (20,395) | |
| Comprehensive income (loss) attributable to noncontrolling interests | 1,659 | | | 786 | | | (743) | |
| Comprehensive income (loss) attributable to ExxonMobil | 56,234 | | | 25,981 | | | (19,652) | |
| | | | | |
| The information in the Notes to Consolidated Financial Statements is an integral part of these statements. |
CONSOLIDATED BALANCE SHEET
| | | | | | | | | | | | | | | | | |
| (millions of dollars) | Note
Reference
Number | | December 31, 2022 | | December 31, 2021 |
| | | | | |
| ASSETS | | | | | |
| Current assets | | | | | |
| Cash and cash equivalents | | | 29,640 | | | 6,802 | |
| Cash and cash equivalents – restricted | | | 25 | | | — | |
| Notes and accounts receivable – net | 6 | | 41,749 | | | 32,383 | |
| Inventories | | | | | |
| Crude oil, products and merchandise | 3 | | 20,434 | | | 14,519 | |
| Materials and supplies | | | 4,001 | | | 4,261 | |
| Other current assets | | | 1,782 | | | 1,189 | |
| Total current assets | | | 97,631 | | | 59,154 | |
| Investments, advances and long-term receivables | 8 | | 49,793 | | | 45,195 | |
| Property, plant and equipment, at cost, less accumulated depreciation and depletion | 9 | | 204,692 | | | 216,552 | |
| Other assets, including intangibles – net | | | 16,951 | | | 18,022 | |
| Total Assets | | | 369,067 | | | 338,923 | |
| | | | | |
| LIABILITIES | | | | | |
| Current liabilities | | | | | |
| Notes and loans payable | 6 | | 634 | | | 4,276 | |
| Accounts payable and accrued liabilities | 6 | | 63,197 | | | 50,766 | |
| Income taxes payable | | | 5,214 | | | 1,601 | |
| Total current liabilities | | | 69,045 | | | 56,643 | |
| Long-term debt | 14 | | 40,559 | | | 43,428 | |
| Postretirement benefits reserves | 17 | | 10,045 | | | 18,430 | |
| Deferred income tax liabilities | 19 | | 22,874 | | | 20,165 | |
| Long-term obligations to equity companies | | | 2,338 | | | 2,857 | |
| Other long-term obligations | | | 21,733 | | | 21,717 | |
| Total Liabilities | | | 166,594 | | | 163,240 | |
| | | | | |
| Commitments and contingencies | 16 | | | | |
| | | | | |
| EQUITY | | | | | |
Common stock without par value (9,000 million shares authorized, 8,019 million shares issued) | | | 15,752 | | | 15,746 | |
| Earnings reinvested | | | 432,860 | | | 392,059 | |
| Accumulated other comprehensive income | | | (13,270) | | | (13,764) | |
Common stock held in treasury (3,937 million shares in 2022 and 3,780 million shares in 2021) | | | (240,293) | | | (225,464) | |
| ExxonMobil share of equity | | | 195,049 | | | 168,577 | |
| Noncontrolling interests | | | 7,424 | | | 7,106 | |
| Total Equity | | | 202,473 | | | 175,683 | |
| Total Liabilities and Equity | | | 369,067 | | | 338,923 | |
| | | | | |
| The information in the Notes to Consolidated Financial Statements is an integral part of these statements. |
CONSOLIDATED STATEMENT OF CASH FLOWS
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| (millions of dollars) | Note Reference Number | | 2022 | | 2021 | | 2020 |
| | | | | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | |
| Net income (loss) including noncontrolling interests | | | 57,577 | | | 23,598 | | | (23,251) | |
| Adjustments for noncash transactions | | | | | | | |
| Depreciation and depletion (includes impairments) | 2, 9 | | 24,040 | | | 20,607 | | | 46,009 | |
| Deferred income tax charges/(credits) | 19 | | 3,758 | | | 303 | | | (8,856) | |
| Postretirement benefits expense in excess of/(less than) net payments | | | (2,981) | | | 754 | | | 498 | |
| Other long-term obligation provisions in excess of/(less than) payments | | | (1,932) | | | 50 | | | (1,269) | |
| Dividends received greater than/(less than) equity in current earnings of equity companies | | | (2,446) | | | (668) | | | 979 | |
| Changes in operational working capital, excluding cash and debt | | | | | | | |
Notes and accounts receivable reduction/(increase) | | | (11,019) | | | (12,098) | | | 5,384 | |
Inventories reduction/(increase) | | | (6,947) | | | (489) | | | (315) | |
Other current assets reduction/(increase) | | | (688) | | | (71) | | | 420 | |
Accounts and other payables increase/(reduction) | | | 18,460 | | | 16,820 | | | (7,142) | |
| Net (gain)/loss on asset sales | 5 | | (1,034) | | | (1,207) | | | 4 | |
| All other items - net | | | 9 | | | 530 | | | 2,207 | |
| Net cash provided by operating activities | | | 76,797 | | | 48,129 | | | 14,668 | |
| | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | |
| Additions to property, plant and equipment | | | (18,407) | | | (12,076) | | | (17,282) | |
| Proceeds from asset sales and returns of investments | | | 5,247 | | | 3,176 | | | 999 | |
| Additional investments and advances | | | (3,090) | | | (2,817) | | | (4,857) | |
| Other investing activities including collection of advances | | | 1,508 | | | 1,482 | | | 2,681 | |
| Net cash used in investing activities | | | (14,742) | | | (10,235) | | | (18,459) | |
| | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | |
| Additions to long-term debt | | | 637 | | | 46 | | | 23,186 | |
| Reductions in long-term debt | | | (5) | | | (8) | | | (8) | |
Additions to short-term debt (1) | | | 198 | | | 12,687 | | | 35,396 | |
Reductions in short-term debt (1) | | | (8,075) | | | (29,396) | | | (28,742) | |
| Additions/(reductions) in commercial paper, and debt with three months or less maturity | | | 25 | | | (2,983) | | | (9,691) | |
| Contingent consideration payments | | | (58) | | | (30) | | | (21) | |
| Cash dividends to ExxonMobil shareholders | | | (14,939) | | | (14,924) | | | (14,865) | |
| Cash dividends to noncontrolling interests | | | (267) | | | (224) | | | (188) | |
| Changes in noncontrolling interests | | | (1,475) | | | (436) | | | 623 | |
| Common stock acquired | | | (15,155) | | | (155) | | | (405) | |
| Net cash provided by (used in) financing activities | | | (39,114) | | | (35,423) | | | 5,285 | |
| | | | | | | | |
| Effects of exchange rate changes on cash | | | (78) | | | (33) | | | (219) | |
| Increase/(decrease) in cash and cash equivalents | | | 22,863 | | | 2,438 | | | 1,275 | |
| Cash and cash equivalents at beginning of year | | | 6,802 | | | 4,364 | | | 3,089 | |
| Cash and cash equivalents at end of year | | | 29,665 | | | 6,802 | | | 4,364 | |
| | | | | | | | |
(1) Includes commercial paper with a maturity greater than three months. |
| | | | | | | | |
| The information in the Notes to Consolidated Financial Statements is an integral part of these statements. |
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
| | | | | | | | | | | | | | | | | | | | | | | |
| | ExxonMobil Share of Equity | | |
| | | | | | | |
(millions of dollars) | Common
Stock | Earnings
Reinvested | Accumulated Other Comprehensive Income | Common
Stock Held in
Treasury | ExxonMobil
Share of
Equity | Non-controlling Interests | Total
Equity |
| | | | | | | | |
| Balance as of December 31, 2019 | 15,637 | | 421,341 | | (19,493) | | (225,835) | | 191,650 | | 7,288 | | 198,938 | |
| Amortization of stock-based awards | 696 | | — | | — | | — | | 696 | | — | | 696 | |
| Other | (645) | | — | | — | | — | | (645) | | 692 | | 47 | |
| Net income (loss) for the year | — | | (22,440) | | — | | — | | (22,440) | | (811) | | (23,251) | |
| Dividends - common shares | — | | (14,865) | | — | | — | | (14,865) | | (188) | | (15,053) | |
| Cumulative effect of accounting change | — | | (93) | | — | | — | | (93) | | (1) | | (94) | |
| Other comprehensive income | — | | — | | 2,788 | | — | | 2,788 | | 68 | | 2,856 | |
| Acquisitions, at cost | — | | — | | — | | (405) | | (405) | | (68) | | (473) | |
| | | | | | | |
| Dispositions | — | | — | | — | | 464 | | 464 | | — | | 464 | |
| Balance as of December 31, 2020 | 15,688 | | 383,943 | | (16,705) | | (225,776) | | 157,150 | | 6,980 | | 164,130 | |
| Amortization of stock-based awards | 534 | | — | | — | | — | | 534 | | — | | 534 | |
| Other | (476) | | — | | — | | — | | (476) | | 115 | | (361) | |
| Net income (loss) for the year | — | | 23,040 | | — | | — | | 23,040 | | 558 | | 23,598 | |
| Dividends - common shares | — | | (14,924) | | — | | — | | (14,924) | | (224) | | (15,148) | |
| | | | | | | |
| Other comprehensive income | — | | — | | 2,941 | | — | | 2,941 | | 228 | | 3,169 | |
| Acquisitions, at cost | — | | — | | — | | (155) | | (155) | | (551) | | (706) | |
| Dispositions | — | | — | | — | | 467 | | 467 | | — | | 467 | |
| Balance as of December 31, 2021 | 15,746 | | 392,059 | | (13,764) | | (225,464) | | 168,577 | | 7,106 | | 175,683 | |
| Amortization of stock-based awards | 481 | | — | | — | | — | | 481 | | — | | 481 | |
| Other | (475) | | — | | — | | — | | (475) | | 405 | | (70) | |
| Net income (loss) for the year | — | | 55,740 | | — | | — | | 55,740 | | 1,837 | | 57,577 | |
| Dividends - common shares | — | | (14,939) | | — | | — | | (14,939) | | (267) | | (15,206) | |
| | | | | | | |
| Other comprehensive income | — | | — | | 494 | | — | | 494 | | (178) | | 316 | |
| Acquisitions, at cost | — | | — | | — | | (15,295) | | (15,295) | | (1,479) | | (16,774) | |
| Dispositions | — | | — | | — | | 466 | | 466 | | — | | 466 | |
| Balance as of December 31, 2022 | 15,752 | | 432,860 | | (13,270) | | (240,293) | | 195,049 | | 7,424 | | 202,473 | |
| | | | | | | | | | | |
Common Stock Share Activity (millions of shares) | Issued | Held in
Treasury | Outstanding |
| | | |
| Balance as of December 31, 2019 | 8,019 | | (3,785) | | 4,234 | |
| Acquisitions | — | | (8) | | (8) | |
| | | |
| Dispositions | — | | 7 | | 7 | |
| Balance as of December 31, 2020 | 8,019 | | (3,786) | | 4,233 | |
| Acquisitions | — | | (2) | | (2) | |
| Dispositions | — | | 8 | | 8 | |
| Balance as of December 31, 2021 | 8,019 | | (3,780) | | 4,239 | |
| Acquisitions | — | | (165) | | (165) | |
| Dispositions | — | | 8 | | 8 | |
| Balance as of December 31, 2022 | 8,019 | | (3,937) | | 4,082 | |
| | | |
| The information in the Notes to Consolidated Financial Statements is an integral part of these statements. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Exxon Mobil Corporation.
The Corporation’s principal business involves exploration for, and production of, crude oil and natural gas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a wide variety of specialty products; and pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen and lower-emission fuels.
The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Prior years’ data have been reclassified in certain cases to conform to the 2022 presentation basis.
1. Summary of Accounting Policies
Environmental Liabilities
Liabilities forThe Corporation accrues environmental costs are recordedliabilities when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. ExxonMobil has accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency has identified ExxonMobil as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could mitigate ExxonMobil’s actual joint and several liability exposure. At present, no individual site is expected to have losses material to ExxonMobil’s operations or financial condition. Consolidated company provisions made in 2022 for environmental liabilities were $185 million ($146 million in 2021), and the balance sheet reflects liabilities of $730 million as of December 31, 2022, and $807 million as of December 31, 2021.
MARKET RISKS
| | | | | | | | | | | | | | | | | |
Worldwide Average Realizations (1) | 2022 | | 2021 | | 2020 |
| Crude oil and NGL ($ per barrel) | 87.25 | | | 61.89 | | | 35.41 | |
| Natural gas ($ per thousand cubic feet) | 7.48 | | | 4.33 | | | 2.01 | |
| | | | | |
(1) Consolidated subsidiaries. |
Crude oil, natural gas, petroleum product, and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings have varied across the Corporation's operating segments. For the year 2023, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $500 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives. Similarly, a $0.10 per thousand cubic feet change in the worldwide average gas realization would have approximately a $140 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, results of trading activities, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide broad indicators of changes in the earnings experienced in any particular period.
In the very competitive petroleum and petrochemical environment, earnings are primarily determined by margin capture rather than absolute price levels of products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These liabilitiesprices in turn depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather.
The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the Corporation’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the Corporation’s financial strength as a competitive advantage.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In general, segment results are not reduceddependent on the ability to sell and/or purchase products to/from other segments. Instead, where such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery and chemical complexes. Additionally, intersegment sales are at market-based prices. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity, and transportation capabilities. Refer to Note 18 for additional information on intersegment revenue.
Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to global economic conditions, political events, decisions by possible recoveries from third parties,OPEC and projected cash expenditures are not discounted.
Foreign Currency Translationother major government resource owners and other factors, industry economics over the long term will continue to be driven by market supply and demand. The Corporation evaluates investments over a range of prices, including estimated greenhouse gas emission costs even in jurisdictions without a current greenhouse gas pricing policy.
The Corporation selectshas an active asset management program in which nonstrategic assets are considered for divestment. The asset management program includes a disciplined, regular review to ensure that assets are contributing to the functional reportingCorporation’s strategic objectives.
Risk Management
The Corporation’s size, strong capital structure, geographic diversity, and the complementary nature of its business segments reduce the Corporation’s enterprise-wide risk from changes in commodity prices, currency rates, and interest rates. In addition, the Corporation uses commodity-based contracts, including derivatives, to manage commodity price risk and to generate returns from trading. The Corporation’s commodity derivatives are not accounted for its international subsidiaries basedunder hedge accounting. At times, the Corporation also enters into currency and interest rate derivatives, none of which are material to the Corporation’s financial position as of December 31, 2022 and 2021, or results of operations for the years ended 2022, 2021, and 2020. Credit risk associated with the Corporation’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of and financial limits placed on derivative counterparties. No material market or credit risks to the currencyCorporation’s financial position, results of operations or liquidity exist as a result of the primary economic environmentderivatives described in which each subsidiary operates.
DownstreamNote 13. The Corporation maintains a system of controls that includes the authorization, reporting and Chemical operations primarily use the local currency. However, the U.S. dollar is used in countries with a historymonitoring of high inflation (primarily in Latin America) and Singapore, which predominantly sells into the U.S. dollar export market. Upstream operations which are relatively self-contained and integrated within a particular country, such as Canada, the United Kingdom and continental Europe, use the local currency. Some Upstream operations, primarily in Asia and Africa, use the U.S. dollar because they predominantly sell crude and natural gas production into U.S. dollar-denominated markets.
For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. Accounting Changes
Effective January 1, 2020, the Corporation adopted the Financial Accounting Standards Board’s update, Financial Instruments – Credit Losses (Topic 326), as amended. The standard requires a valuation allowance for credit losses be recognized for certain financial assets that reflects the current expected credit loss over the asset’s contractual life. The valuation allowance considers the risk of loss, even if remote, and considers past events, current conditions and reasonable and supportable forecasts. The standard requires this expected loss methodology for trade receivables, certain other financial assets and off-balance sheet credit exposures. The cumulative effect adjustment related to the adoption of this standard reduced ExxonMobil's share of equity by $93 million.derivative activity.
The Corporation is exposed to changes in interest rates, primarily on its short-term debt and the portion of long-term debt that carries floating interest rates. The impact of a 100-basis-point change in interest rates affecting the Corporation’s debt would not be material to earnings or cash flow. The Corporation has access to significant capacity of long-term and short-term liquidity. Internally generated funds are generally expected to cover financial requirements, supplemented by long-term and short-term debt as required. Commercial paper is used to balance short-term liquidity requirements. Some joint-venture partners are dependent on the credit losses primarily throughmarkets, and their funding ability may impact the development pace of joint-venture projects.
The Corporation conducts business in many foreign currencies and is subject to exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. Fluctuations in exchange rates are often offsetting and the impacts on ExxonMobil’s geographically and functionally diverse operations are varied. The Corporation makes limited use of petroleum products,currency exchange contracts to mitigate the impact of changes in currency values, and exposures related to the Corporation’s use of these contracts are not material.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CRITICAL ACCOUNTING ESTIMATES
The Corporation’s accounting and financial reporting fairly reflect its integrated business model involving exploration for, and production of, crude oil and natural gas; manufacture, trade, transport and sale of crude oil, natural gas, liquidspetroleum 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. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. The Corporation’s accounting policies are summarized in Note 1.
Oil and Natural Gas Reserves
The estimation of proved oil and natural gas reserve volumes is an ongoing process based on rigorous technical evaluations, commercial and market assessments, and detailed analysis of well information such as well as loansflow rates and reservoir pressure declines, development and production costs, and other factors. The estimation of proved reserves is controlled by the Corporation through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Global Reserves and Resources Group which has significant technical experience, culminating in reviews with and approval by senior management. Notably, the Corporation does not use specific quantitative reserve targets to equity companies and joint venture receivables. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or the Corporation’s assessmentdetermine compensation. Key features of the counterparty’s credit worthiness, contract terms, countryreserve estimation process are covered in Disclosure of operation,Reserves in Item 2.
Oil and other risks. The Corporationnatural gas reserves include both proved and unproved reserves.
•Proved oil and natural gas reserves are determined in accordance with Securities and Exchange Commission (SEC) requirements. Proved reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can require prepaymentbe estimated with reasonable certainty to be economically producible under existing economic and operating conditions and government regulations. Proved reserves are determined using the average of first-of-month oil and natural gas prices during the reporting year.
Proved reserves can be further subdivided into developed and undeveloped reserves. Proved developed reserves include amounts which are expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include amounts expected to be recovered from new wells on undrilled proved acreage or collateralfrom existing wells where a relatively major expenditure is required for completion. Proved undeveloped reserves are recognized only if a development plan has been adopted indicating that the reserves are scheduled to mitigate certain credit risks.be drilled within five years, unless specific circumstances support a longer period of time.
The Corporation groups financial assets into portfoliosis reasonably certain that share similar risk characteristicsproved reserves will be produced. However, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals, government policy, consumer preferences, and significant changes in oil and natural gas price levels.
•Unproved reserves are quantities of oil and natural gas with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that, together with proved reserves, are as likely as not to be recovered.
Revisions in previously estimated volumes of proved reserves for purposesexisting fields can occur due to the evaluation or re-evaluation of determining the allowance for credit losses and assesses if a significant change(1) already available geologic, reservoir, or production data, (2) new geologic, reservoir, or production data, or (3) changes in the riskaverage of credit loss has occurred. Amongfirst-of-month oil and natural gas prices and/or costs that are used in the quantitativeestimation of reserves. Revisions can also result from significant changes in development strategy or production equipment and qualitative factors consideredfacility capacity.
Unit-of-Production Depreciation
Oil and natural gas reserve volumes are historical financial data, current conditions, industryused as the basis to calculate unit-of-production depreciation rates for most upstream assets. Depreciation is calculated by taking the ratio of asset cost to total proved reserves or proved developed reserves applied to actual production. The volumes produced and country risk, current credit ratingsasset cost are known, while proved reserves are based on estimates that are subject to some variability.
In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative method is used. The straight-line method is used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural gas have a shorter life than the qualityreserves, and as such, the Corporation uses straight-line depreciation to ensure the asset is fully depreciated by the end of third-party guarantees secured fromits useful life.
To the counterparty. Financialextent that proved reserves for a property are substantially de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets are written offwill be depreciated using a unit-of-production method based on reserves determined at the most recent SEC price which results in whole, or in part, when practical recovery efforts have been exhausteda more meaningful quantity of proved reserves, appropriately adjusted for production and no reasonable expectation of recovery exists. Subsequent recoveries of amounts previously written off are recognized in earnings. The Corporation manages receivable portfolios using past due balances as a key credit quality indicator.technical changes.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Impairment
The Corporation recognizes a credit allowancetests assets or groups of assets for off-balance sheet credit exposures as a liabilityrecoverability on the balance sheet, separate from the allowance for credit losses related to recognized financial assets. Among these exposures are unfunded loans to equity companies and financial guarantees that cannot be cancelled unilaterally by the Corporation.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Allowance for Current Expected Credit Losses |
| | Notes and Accounts Receivable | | Advances and Long-Term Receivables | | Liabilities for Off- Balance Sheet Assets | | |
| | Trade | | Other | | | | Total |
| | (millions of dollars) |
| Balance at December 31, 2019 | 34 | | | 56 | | | 413 | | | 0 | | | 503 | |
| Cumulative effect of accounting change | 52 | | | 6 | | | 39 | | | 12 | | | 109 | |
| Current period provision | 9 | | | 15 | | | (9) | | | (1) | | | 14 | |
| Write-offs charged against the allowance | (2) | | | (3) | | | 0 | | | — | | | (5) | |
| Other | 2 | | | (3) | | | 3 | | | 0 | | | 2 | |
| Balance at December 31, 2020 | 95 | | | 71 | | | 446 | | | 11 | | | 623 | |
| | | | | | | | | |
| Balance at December 31, 2020 | | | | | | | | | |
| Financial Assets subject to credit losses standard - net | 16,250 | | | 1,962 | | | 9,447 | | | | | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. Miscellaneous Financial Information
Research and development expenses totaled $1,016 million in 2020, $1,214 million in 2019, and $1,116 million in 2018.
Net income included before-tax aggregate foreign exchange transaction losses of $24 million, $104 million and $138 million in 2020, 2019 and 2018, respectively.
In 2020, 2019, and 2018, net income included gains of $41 million, $523 million, and $107 million, respectively, attributable to the combined effects of LIFO inventory accumulations and drawdowns. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by $5.4 billion and $9.7 billion at December 31, 2020, and 2019, respectively.
Crude oil, products and merchandise as of year-end 2020 and 2019 consist of the following:
| | | | | | | | | | | |
| | Dec 31,
2020 | | Dec 31,
2019 |
| | (millions of dollars) |
| Crude oil | 5,354 | | | 5,111 | |
| Petroleum products | 5,138 | | | 5,281 | |
| Chemical products | 3,023 | | | 3,240 | |
| Gas/other | 654 | | | 378 | |
| Total | 14,169 | | | 14,010 | |
Mainly as a result of declines in prices for crude oil, natural gas and petroleum products in 2020 and a significant decline in its market capitalization at the end of the first quarter, the Corporation recognized before-tax goodwill impairment charges of $611 million in Upstream, Downstream, and Chemical reporting units. Fair value of the goodwill reporting units primarily reflected market-based estimates of historical EBITDA multiples at the end of the first quarter. Charges related to goodwill impairments are included in “Depreciation and depletion” on the Statement of Income.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. Other Comprehensive Income Information
| | | | | | | | | | | | | | | | | |
ExxonMobil Share of Accumulated Other
Comprehensive Income | Cumulative Foreign Exchange Translation Adjustment | | Postretirement Benefits Reserves Adjustment | | Total |
| | (millions of dollars) |
| Balance as of December 31, 2017 | (9,482) | | | (6,780) | | | (16,262) | |
| Current period change excluding amounts reclassified from accumulated other comprehensive income | (4,595) | | | 201 | | | (4,394) | |
| Amounts reclassified from accumulated other comprehensive income | 196 | | | 896 | | | 1,092 | |
| Total change in accumulated other comprehensive income | (4,399) | | | 1,097 | | | (3,302) | |
| Balance as of December 31, 2018 | (13,881) | | | (5,683) | | | (19,564) | |
| | | | | |
| Current period change excluding amounts reclassified from accumulated other comprehensive income | 1,435 | | | (1,927) | | | (492) | |
| Amounts reclassified from accumulated other comprehensive income | 0 | | | 563 | | | 563 | |
| Total change in accumulated other comprehensive income | 1,435 | | | (1,364) | | | 71 | |
| Balance as of December 31, 2019 | (12,446) | | | (7,047) | | | (19,493) | |
| | | | | |
| Current period change excluding amounts reclassified from accumulated other comprehensive income (1) | 1,818 | | | 95 | | | 1,913 | |
| Amounts reclassified from accumulated other comprehensive income | 14 | | | 861 | | | 875 | |
| Total change in accumulated other comprehensive income | 1,832 | | | 956 | | | 2,788 | |
| Balance as of December 31, 2020 | (10,614) | | | (6,091) | | | (16,705) | |
(1) Cumulative Foreign Exchange Translation Adjustment includes net investment hedge gain/(loss) of $(355) million, net of taxes.
| | | | | | | | | | | | | | | | | |
Amounts Reclassified Out of Accumulated Other
Comprehensive Income - Before-tax Income/(Expense) | 2020 | | 2019 | | 2018 |
| | (millions of dollars) |
Foreign exchange translation gain/(loss) included in net income (Statement of Income line: Other income) | (14) | | | 0 | | | (196) | |
Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs (Statement of Income line: Non-service pension and postretirement benefit expense) | (1,158) | | | (751) | | | (1,208) | |
| | | | | | | | | | | | | | | | | |
Income Tax (Expense)/Credit For
Components of Other Comprehensive Income | 2020 | | 2019 | | 2018 |
| | (millions of dollars) |
| Foreign exchange translation adjustment | 118 | | | 88 | | | 32 | |
| Postretirement benefits reserves adjustment (excluding amortization) | 109 | | | 719 | | | (193) | |
| Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs | (262) | | | (169) | | | (277) | |
| Total | (35) | | | 638 | | | (438) | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. Cash Flow Information
The Consolidated Statement of Cash Flows provides information aboutan ongoing basis whenever events or changes in cash and cash equivalents. Highly liquid investments with maturities of three months or less when acquired are classified as cash equivalents.
For 2020,circumstances indicate that the “Depreciation and depletion” and “Deferred income tax charges/(credits)” on the Consolidated Statement of Cash Flows includes impacts from asset impairments, primarily in Upstream.
For 2019, the “Net (gain)/loss on asset sales” on the Consolidated Statement of Cash Flows includes before-taxcarrying amounts from the sale of non-operated upstream assets in Norway and upstream asset transactions in the U.S. The Norway assets were sold for $4.5 billion, resulting in a gain of $3.7 billion and cash proceeds of $3.1 billion in 2019. For 2018, the number includes before-tax amounts from the sale of service stations in Germany, the divestment of the Augusta refinery in Italy, and the sale of an undeveloped upstream property in Australia. These net gains are reported in “Other income” on the Consolidated Statement of Income.
In 2020, the “Additions/(reductions) in commercial paper, and debt with three months or less maturity” on the Consolidated Statement of Cash Flows includes a net $8.4 billion addition of commercial paper with maturity over three months. The gross amount issued was $35.4 billion, while the gross amount repaid was $27.0 billion. In 2019, the number includes a net $4.6 billion addition of commercial paper with maturity over three months. The gross amount issued was $18.9 billion, while the gross amount repaid was $14.3 billion. In 2018, the number includes a net $275 million addition of commercial paper with maturity over three months. The gross amount issued was $4.0 billion, while the gross amount repaid was $3.8 billion.
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| | (millions of dollars) |
| Income taxes paid | 2,428 | | | 7,018 | | | 9,294 | |
| Cash interest paid | | | | | |
| Included in cash flows from operating activities | 786 | | | 560 | | | 303 | |
| Capitalized, included in cash flows from investing activities | 665 | | | 731 | | | 652 | |
| Total cash interest paid | 1,451 | | | 1,291 | | | 955 | |
6. Additional Working Capital Information
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec 31,
2020 | | Dec 31,
2019 |
| | | (millions of dollars) |
| Notes and accounts receivable | | | | |
| Trade, less reserves of $96 million and $34 million | | 16,339 | | | 21,100 | |
| Other, less reserves of $378 million and $371 million | | 4,242 | | | 5,866 | |
| Total | | 20,581 | | | 26,966 | |
| Notes and loans payable | | | | |
| Bank loans | | 222 | | | 316 | |
| Commercial paper | | 17,306 | | | 18,561 | |
| Long-term debt due within one year | | 2,930 | | | 1,701 | |
| Total | | 20,458 | | | 20,578 | |
| Accounts payable and accrued liabilities | | | | |
| Trade payables | | 17,499 | | | 24,694 | |
| Payables to equity companies | | 6,476 | | | 6,825 | |
| Accrued taxes other than income taxes | | 3,408 | | | 3,301 | |
| Other | | 7,838 | | | 7,011 | |
| Total | | 35,221 | | | 41,831 | |
The Corporation has short-term committed lines of credit of $11.3 billion which were unused as of December 31, 2020. These lines are available for general corporate purposes.
The weighted-average interest rate on short-term borrowings outstanding was 0.2 percent and 1.7 percent at December 31, 2020, and 2019, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. Equity Company Information
The summarized financial information below includes amounts related to certain less-than-majority-owned companies and majority-owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see Note 1). These companies are primarily engaged in oil and gas exploration and production, and natural gas marketing in North America; natural gas exploration, production and distribution in Europe; liquefied natural gas (LNG) operations and transportation of crude oil in Africa; and exploration, production, LNG operations, and the manufacture and sale of petroleum and petrochemical products in Asia and the Middle East. Also included are several refining, petrochemical manufacturing and marketing ventures.
The share of total equity company revenues from sales to ExxonMobil consolidated companies was 11 percent, 13 percent and 14 percent in the years 2020, 2019 and 2018, respectively.
The Corporation’s ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships. Differences between the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned to the extent practicable to specific assets and liabilities based on the company’s analysis of the factors giving rise to the difference. The amortization of this difference, as appropriate, is included in “Income from equity affiliates” on the Consolidated Statement of Income.
Impairments related to U.S. upstream equity investments of $600 million are included in “Income from equity affiliates” on the Consolidated Statement of Income.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
Equity Company
Financial Summary | Total | | ExxonMobil
Share | | Total | | ExxonMobil Share | | Total | | ExxonMobil
Share |
| | (millions of dollars) |
| Total revenues | 69,954 | | | 21,282 | | | 102,365 | | | 31,240 | | | 112,938 | | | 34,539 | |
| Income before income taxes | 12,743 | | | 2,830 | | | 29,424 | | | 7,927 | | | 37,203 | | | 10,482 | |
| Income taxes | 4,333 | | | 870 | | | 9,725 | | | 2,500 | | | 11,568 | | | 3,151 | |
| Income from equity affiliates | 8,410 | | | 1,960 | | | 19,699 | | | 5,427 | | | 25,635 | | | 7,331 | |
| | | | | | | | | | | |
| Current assets | 33,419 | | | 11,969 | | | 36,035 | | | 12,661 | | | 38,670 | | | 13,394 | |
| Long-term assets | 150,358 | | | 41,457 | | | 143,321 | | | 40,001 | | | 128,830 | | | 35,970 | |
| Total assets | 183,777 | | | 53,426 | | | 179,356 | | | 52,662 | | | 167,500 | | | 49,364 | |
| Current liabilities | 18,827 | | | 5,245 | | | 24,583 | | | 6,939 | | | 27,324 | | | 7,606 | |
| Long-term liabilities | 66,053 | | | 19,927 | | | 61,022 | | | 18,158 | | | 56,913 | | | 17,109 | |
| Net assets | 98,897 | | | 28,254 | | | 93,751 | | | 27,565 | | | 83,263 | | | 24,649 | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A list of significant equity companies as of December 31, 2020, together with the Corporation’s percentage ownership interest, is detailed below:
| | | | | |
| Percentage Ownership Interest |
Upstream | |
Aera Energy LLC | 48 |
Barzan Gas Company Limited | 7 |
BEB Erdgas und Erdoel GmbH & Co. KG | 50 |
Cameroon Oil Transportation Company S.A. | 41 |
Caspian Pipeline Consortium - Kazakhstan | 8 |
CORAL FLNG, S.A. | 25 |
Cross Timbers Energy, LLC | 50 |
Golden Pass LNG Terminal LLC | 30 |
Golden Pass Pipeline LLC | 30 |
Marine Well Containment Company LLC | 10 |
Mozambique Rovuma Venture, S.p.A. | 36 |
Nederlandse Aardolie Maatschappij B.V. | 50 |
Papua New Guinea Liquefied Natural Gas Global Company LDC | 33 |
Permian Highway Pipeline LLC | 20 |
Qatar Liquefied Gas Company Limited | 10 |
Qatar Liquefied Gas Company Limited (2) | 24 |
Ras Laffan Liquefied Natural Gas Company Limited | 25 |
Ras Laffan Liquefied Natural Gas Company Limited (II) | 31 |
Ras Laffan Liquefied Natural Gas Company Limited (3) | 30 |
South Hook LNG Terminal Company Limited | 24 |
Tengizchevroil, LLP | 25 |
Terminale GNL Adriatico S.r.l. | 71 |
| |
Downstream | |
Alberta Products Pipe Line Ltd. | 45 |
Fujian Refining & Petrochemical Co. Ltd. | 25 |
Permian Express Partners LLC | 12 |
Saudi Aramco Mobil Refinery Company Ltd. | 50 |
| |
Chemical | |
Al-Jubail Petrochemical Company | 50 |
Gulf Coast Growth Ventures LLC | 50 |
Saudi Yanbu Petrochemical Co. | 50 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. Investments, Advances and Long-Term Receivables
| | | | | | | | | | | |
| | Dec 31, 2020 | | Dec 31, 2019 |
| | (millions of dollars) |
| Equity method company investments and advances | | | |
| Investments | 29,772 | | | 29,291 | |
| Advances, net of allowances of $31 million in 2020 | 8,812 | | | 8,542 | |
| Total equity method company investments and advances | 38,584 | | | 37,833 | |
| Equity securities carried at fair value and other investments at adjusted cost basis | 143 | | | 190 | |
| Long-term receivables and miscellaneous, net of reserves of $6,115 million and $5,643 million | 4,788 | | | 5,141 | |
| Total | 43,515 | | | 43,164 | |
9. Property, Plant and Equipment and Asset Retirement Obligations
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2020 | | December 31, 2019 |
| Property, Plant and Equipment | Cost | | Net | | Cost | | Net |
| | (millions of dollars) |
| Upstream | 386,614 | | | 167,472 | | | 376,041 | | | 196,767 | |
| Downstream | 57,922 | | | 27,716 | | | 52,527 | | | 24,506 | |
| Chemical | 42,868 | | | 21,924 | | | 40,788 | | | 21,260 | |
| Other | 17,918 | | | 10,441 | | | 17,346 | | | 10,485 | |
| Total | 505,322 | | | 227,553 | | | 486,702 | | | 253,018 | |
may not be recoverable. The Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of ASC 360 and ASC 932, and relies, in part, on the Corporation’s planning and budgeting cycle. In 2020,
Because the Corporation identified a numberlifespans of situations wherethe vast majority of the Corporation’s major assets are measured in decades, the future cash flows of these assets are predominantly based on long-term oil and natural gas commodity prices and industry margins, development costs, and production costs. Significant reductions in the Corporation’s view of oil or natural gas commodity prices or margin ranges, especially the longer-term prices and margins, and changes in the development plans, including decisions to defer, reduce, or eliminate planned capital spending, can be an indicator of potential impairment. Other events or changes in circumstances, indicatedincluding indicators outlined in ASC 360, can be indicators of potential impairment as well.
In general, the Corporation does not view temporarily low prices or margins as an indication of impairment. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments, and technology and efficiency advancements. OPEC investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities, alternative energy sources, and levels of prosperity. During the lifespan of its major assets, the Corporation expects that oil and gas prices and industry margins will experience significant volatility. Consequently, these assets will experience periods of higher earnings and periods of lower earnings, or even losses. In assessing whether events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the Corporation considers recent periods of operating losses in the context of its longer-term view of prices and margins.
Outlook for Energy and Cash Flow Assessment. The annual planning and budgeting process, known as the Corporate Plan, is the mechanism by which resources (capital, operating expenses, and people) are allocated across the Corporation. The foundation for the assumptions supporting the Corporate Plan is the Outlook for Energy (Outlook), which contains the Corporation’s demand and supply projections based on its assessment of current trends in technology, government policies, consumer preferences, geopolitics, economic development, and other factors. Reflective of the existing global policy environment, the Outlook does not attempt to project the degree of necessary future policy and technology advancement and deployment for the world, or the Corporation, to meet net zero by 2050. As future policies and technology advancements emerge, they will be incorporated into the Outlook, and the Corporation’s business plans will be updated accordingly.
If events or changes in circumstances indicate that the carrying value of certain long-lived assetsan asset may not be recoverable. Those situations primarily related torecoverable, the annual review and approvalCorporation estimates the future undiscounted cash flows of the Corporation's businessaffected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on the assumptions developed in the Corporate Plan, which is reviewed and approved by the Board of Directors, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the Corporation’s assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, development and operating costs including greenhouse gas emission prices, and foreign currency exchange rates. Notably, when assessing future cash flows, the Corporation includes the estimated costs in support of reaching its 2030 greenhouse gas emission-reduction plans, including its goal of net-zero greenhouse gas emissions (Scope 1 and 2) from unconventional operated assets in the Permian Basin. Volumes are based on projected field and facility production profiles, throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities. ExxonMobil considers a range of scenarios - including remote scenarios - to help inform perspective of the future and enhance strategic plan.thinking over time. While third-party scenarios, such as the International Energy Agency's Net Zero Emissions by 2050, may be used for these purposes, they are not used as a basis for developing future cash flows for impairment assessments. As part of the planning process,Corporate Plan, the Corporation assessedCompany considers estimated greenhouse gas emission costs, even for jurisdictions without a current greenhouse gas pricing policy.
Fair Value of Impaired Assets. An asset group is impaired if its full portfolio to prioritize assets withestimated undiscounted cash flows are less than the highest future value potential within its broad rangeasset group’s carrying value. Impairments are measured by the excess of available opportunities in order to optimize resources within current levels of debt and operating cash flow, as well as identify potential asset divestment candidates. This effort included a re-assessment of dry gas assets, primarily in North America, which previously had been included in the Corporation’s future development plans. Under the plan as approved, the Corporation no longer plans to develop a significant portion of its dry gas portfolio, including a portion of its resources in the Appalachian, Rocky Mountains, Oklahoma, Texas, Louisiana, and Arkansas regions of the U.S., as well as resources in Western Canada and Argentina. The decision not to develop these assets resulted in non-cash, before-tax charges of $24.4 billion in Upstream to reduce the carrying value of those assets toover fair value. Other before-tax impairment charges in 2020 included $0.9 billion in Upstream, $0.5 billion in Downstream, and $0.1 billion in Chemical. Impairment charges are primarily recognized in the lines “Depreciation and depletion” and “Exploration expenses, including dry holes” on the Consolidated Statement of Income.
The assessment of fair value requires the use of Level 3 inputs and assumptions that areis based upon the views of a likely market participant. The principal parameters used to establish fair value include estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, throughput and product sales volumes, commodity prices which wereare consistent with the average of third-party industry experts and government agencies, refining and chemical margins, drilling and development costs, operating costs, and discount rates ranging from 6 percent to 8 percent which are reflective of the characteristics of the asset group.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Impairment Estimates. Unproved properties are assessed periodically to determine whether they have been impaired. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the Corporation's future development plans, the estimated economic chance of success, and the length of time that the Corporation expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.
Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the assets are considered impaired and adjusted to the lower value. Judgment is required to determine if assets are held for sale and to determine the fair value less cost to sell.
Investments accounted for by the equity method are assessed for possible impairment when events or changes in circumstances indicate that the carrying value of an investment may not be recoverable. Examples of key indicators include a history of operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If the decline in value of the investment is other than temporary, the carrying value of the investment is written down to fair value. In the absence of market prices for the investment, discounted cash flows are used to assess fair value, which requires significant judgment.
Recent Impairments. In early 2022, in response to Russia’s military action in Ukraine, the Corporation announced that it planned to discontinue operations on the Sakhalin-1 project (“Sakhalin”) and develop steps to exit the venture. The Corporation’s first quarter results included after-tax charges of $3.0 billion representing the impairment of its Upstream operations related to Sakhalin. (Refer to Note 2 for further information on Russia.) Other after-tax impairment charges of $1.6 billion and $0.3 billion were recognized in Upstream and Energy Products, respectively.
In 2021, largely as a result of changes to Upstream development plans, the Corporation recognized after-tax impairment charges of approximately $1 billion. In 2020, as part of the Corporation's annual review and approval of its business and strategic plan, a decision was made to no longer develop a significant portion of the dry gas portfolio in the United States, Canada, and Argentina. The impairment of these assets resulted in after-tax charges of $18.4 billion in Upstream. Other after-tax impairment charges of $1.8 billion across the year related mainly to impairments of property, plant, and equipment, goodwill, and equity method investments.
Factors which could put further assets at risk of impairment in the future include reductions in the Corporation’s price or margin outlooks, changes in the allocation of capital or development plans, reduced long-term demand for the Corporation's products, and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural gas price or margin increases. However, due to the inherent difficulty in predicting future commodity prices or margins, and the relationship between industry prices and costs, it is not practicable to reasonably estimate the existence or range of any potential future impairment charges related to the Corporation’s long-lived assets. In 2019
For further information regarding impairments in goodwill, equity method investments, property, plant, and 2018, the before-tax impairment charges were $0.1 billionequipment, and $0.7 billion,suspended wells, refer to Notes 3, 7, 9, and 10, respectively.
Accumulated depreciation and depletion totaled $277,769 million at the end of 2020 and $233,684 million at the end of 2019. Interest capitalized in 2020, 2019 and 2018 was $665 million, $731 million and $652 million, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Asset Retirement Obligations
The Corporation is subject to retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, discount rates, and inflation rates. See Note 9 for further information regarding asset retirement obligations.
Suspended Exploratory Well Costs
The Corporation continues capitalization of exploratory well costs when it has found a sufficient quantity of reserves to justify completion as a producing well and the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Assessing whether the Corporation is making sufficient progress on a project requires careful consideration of the facts and circumstances. The facts and circumstances that support continued capitalization of suspended wells at year-end are disclosed in Note 10.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Pension Benefits
The Corporation and its affiliates sponsor 75 defined benefit (pension) plans in 40 countries. The Pension and Other Postretirement Benefits footnote (Note 17) provides details on pension obligations, fund assets, and pension expense.
Some of these plans (primarily non-U.S.) provide pension benefits that are paid directly by their sponsoring affiliates out of corporate cash flow rather than a separate pension fund because applicable tax rules and regulatory practices do not encourage advance funding. Book reserves are established for these plans. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets.
For funded plans, including those in the U.S., pension obligations are financed in advance through segregated assets or insurance arrangements. These plans are managed in compliance with the requirements of governmental authorities and meet or exceed required funding levels as measured by relevant actuarial and government standards at the mandated measurement dates. In determining liabilities and required contributions, these standards often require approaches and assumptions that differ from those used for accounting purposes.
The Corporation will continue to make contributions to these funded plans as necessary. All defined-benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.
Pension accounting requires explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the discount rate for the benefit obligations, and the long-term rate for future salary increases. Pension assumptions are reviewed annually by outside actuaries and senior management. These assumptions are adjusted as appropriate to reflect changes in market rates and outlook. The long-term expected earnings rate on U.S. pension plan assets in 2022 was 4.6 percent. The 10-year and 20-year actual returns on U.S. pension plan assets were 4 percent and 7 percent, respectively. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class. A worldwide reduction of 0.5 percent in the long-term rate of return on assets would increase annual pension expense by approximately $140 million before tax.
Differences between actual returns on fund assets and the long-term expected return are not recognized in pension expense in the year that the difference occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected remaining service life of employees.
Litigation and Tax Contingencies
A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending lawsuits. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. For contingencies where an unfavorable outcome is reasonably possible and significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The status of significant claims is summarized in Note 16.
Management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past. Payments have not had a material adverse effect on our operations or financial condition. In the Corporation’s experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement.
The Corporation is subject to income taxation in many jurisdictions around the world. The benefits of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict. The Corporation’s unrecognized tax benefits and a description of open tax years are summarized in Note 19.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management, including the Corporation’s Chief Executive Officer, Chief Financial Officer, and Principal Accounting Officer, is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 2022.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2022, as stated in their report included in the Financial Section of this report.
| | | | | | | | |
| | |
Darren W. Woods Chief Executive Officer | Kathryn A. Mikells Senior Vice President and Chief Financial Officer | Len M. Fox Vice President and Controller (Principal Accounting Officer) |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Exxon Mobil Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheet of Exxon Mobil Corporation and its subsidiaries (the “Corporation”) as of December 31, 2022 and 2021, and the related consolidated statements of income, of comprehensive income, of changes in equity and of cash flows for each of the three years in the period ended December 31, 2022, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Corporation's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Corporation as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Corporation's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on the Corporation’s consolidated financial statements and on the Corporation's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Oil and Natural Gas Reserves on Upstream Property, Plant and Equipment, Net
As described in Notes 1, 9 and 18 to the consolidated financial statements, the Corporation's consolidated upstream property, plant and equipment (PP&E), net balance was $144.1 billion as of December 31, 2022, and the related depreciation and depletion expense for the year ended December 31, 2022 was $19.8 billion. Management uses the successful efforts method to account for its exploration and production activities. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. As disclosed by management, proved oil and natural gas reserve volumes are used as the basis to calculate unit-of-production depreciation rates for most upstream assets. The estimation of proved oil and natural gas reserve volumes is an ongoing process based on technical evaluations, commercial and market assessments, and detailed analysis of well information such as flow rates and reservoir pressure declines, development and production costs, among other factors. As further disclosed by management, reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Global Reserves and Resources Group (together "management's specialists").
The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural gas reserves on upstream PP&E, net is a critical audit matter are (i) the significant judgment by management, including the use of management's specialists, when developing the estimates of proved oil and natural gas reserve volumes, as the reserve volumes are based on engineering assumptions and methods, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods and assumptions used by management and its specialists in developing the estimates of proved oil and natural gas reserve volumes and the assumptions applied to the data related to future development costs, as applicable.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's estimates of proved oil and natural gas reserve volumes. The work of management's specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserve volumes. As a basis for using this work, the specialists' qualifications were understood and the Corporation's relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of the specialists' findings. These procedures also included, among others, testing the completeness and accuracy of the data related to future development costs. Additionally, these procedures included evaluating whether the assumptions applied to the data related to future development costs were reasonable considering the past performance of the Corporation.
/s/ PricewaterhouseCoopers LLP
Dallas, Texas
February 22, 2023
We have served as the Corporation’s auditor since 1934.
CONSOLIDATED STATEMENT OF INCOME
| | | | | | | | | | | | | | | | | | | | | | | |
(millions of dollars) | Note
Reference
Number | | 2022 | | 2021 | | 2020 |
| Revenues and other income | | | | | | | |
| Sales and other operating revenue | 18 | | 398,675 | | | 276,692 | | | 178,574 | |
| Income from equity affiliates | 7 | | 11,463 | | | 6,657 | | | 1,732 | |
| Other income | | | 3,542 | | | 2,291 | | | 1,196 | |
| Total revenues and other income | | | 413,680 | | | 285,640 | | | 181,502 | |
| Costs and other deductions | | | | | | | |
| Crude oil and product purchases | | | 228,959 | | | 155,164 | | | 94,007 | |
| Production and manufacturing expenses | | | 42,609 | | | 36,035 | | | 30,431 | |
| Selling, general and administrative expenses | | | 10,095 | | | 9,574 | | | 10,168 | |
| Depreciation and depletion (includes impairments) | 2, 9 | | 24,040 | | | 20,607 | | | 46,009 | |
| Exploration expenses, including dry holes | | | 1,025 | | | 1,054 | | | 1,285 | |
| Non-service pension and postretirement benefit expense | 17 | | 482 | | | 786 | | | 1,205 | |
| Interest expense | | | 798 | | | 947 | | | 1,158 | |
| Other taxes and duties | 19 | | 27,919 | | | 30,239 | | | 26,122 | |
| Total costs and other deductions | | | 335,927 | | | 254,406 | | | 210,385 | |
| Income (loss) before income taxes | | | 77,753 | | | 31,234 | | | (28,883) | |
| Income tax expense (benefit) | 19 | | 20,176 | | | 7,636 | | | (5,632) | |
| Net income (loss) including noncontrolling interests | | | 57,577 | | | 23,598 | | | (23,251) | |
| Net income (loss) attributable to noncontrolling interests | | | 1,837 | | | 558 | | | (811) | |
| Net income (loss) attributable to ExxonMobil | | | 55,740 | | | 23,040 | | | (22,440) | |
| | | | | | | |
Earnings (loss) per common share (dollars) | 12 | | 13.26 | | | 5.39 | | | (5.25) | |
| | | | | | | |
Earnings (loss) per common share - assuming dilution (dollars) | 12 | | 13.26 | | | 5.39 | | | (5.25) | |
| | | | | | | |
| The information in the Notes to Consolidated Financial Statements is an integral part of these statements. |
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
| | | | | | | | | | | | | | | | | |
| (millions of dollars) | 2022 | | 2021 | | 2020 |
| Net income (loss) including noncontrolling interests | 57,577 | | | 23,598 | | | (23,251) | |
| | | | | |
| Other comprehensive income (loss) (net of income taxes) | | | | | |
| Foreign exchange translation adjustment | (3,482) | | | (872) | | | 1,916 | |
| Adjustment for foreign exchange translation (gain)/loss included in net income | — | | | (2) | | | 14 | |
| Postretirement benefits reserves adjustment (excluding amortization) | 3,395 | | | 3,118 | | | 30 | |
| Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs | 403 | | | 925 | | | 896 | |
| Total other comprehensive income (loss) | 316 | | | 3,169 | | | 2,856 | |
| Comprehensive income (loss) including noncontrolling interests | 57,893 | | | 26,767 | | | (20,395) | |
| Comprehensive income (loss) attributable to noncontrolling interests | 1,659 | | | 786 | | | (743) | |
| Comprehensive income (loss) attributable to ExxonMobil | 56,234 | | | 25,981 | | | (19,652) | |
| | | | | |
| The information in the Notes to Consolidated Financial Statements is an integral part of these statements. |
CONSOLIDATED BALANCE SHEET
| | | | | | | | | | | | | | | | | |
| (millions of dollars) | Note
Reference
Number | | December 31, 2022 | | December 31, 2021 |
| | | | | |
| ASSETS | | | | | |
| Current assets | | | | | |
| Cash and cash equivalents | | | 29,640 | | | 6,802 | |
| Cash and cash equivalents – restricted | | | 25 | | | — | |
| Notes and accounts receivable – net | 6 | | 41,749 | | | 32,383 | |
| Inventories | | | | | |
| Crude oil, products and merchandise | 3 | | 20,434 | | | 14,519 | |
| Materials and supplies | | | 4,001 | | | 4,261 | |
| Other current assets | | | 1,782 | | | 1,189 | |
| Total current assets | | | 97,631 | | | 59,154 | |
| Investments, advances and long-term receivables | 8 | | 49,793 | | | 45,195 | |
| Property, plant and equipment, at cost, less accumulated depreciation and depletion | 9 | | 204,692 | | | 216,552 | |
| Other assets, including intangibles – net | | | 16,951 | | | 18,022 | |
| Total Assets | | | 369,067 | | | 338,923 | |
| | | | | |
| LIABILITIES | | | | | |
| Current liabilities | | | | | |
| Notes and loans payable | 6 | | 634 | | | 4,276 | |
| Accounts payable and accrued liabilities | 6 | | 63,197 | | | 50,766 | |
| Income taxes payable | | | 5,214 | | | 1,601 | |
| Total current liabilities | | | 69,045 | | | 56,643 | |
| Long-term debt | 14 | | 40,559 | | | 43,428 | |
| Postretirement benefits reserves | 17 | | 10,045 | | | 18,430 | |
| Deferred income tax liabilities | 19 | | 22,874 | | | 20,165 | |
| Long-term obligations to equity companies | | | 2,338 | | | 2,857 | |
| Other long-term obligations | | | 21,733 | | | 21,717 | |
| Total Liabilities | | | 166,594 | | | 163,240 | |
| | | | | |
| Commitments and contingencies | 16 | | | | |
| | | | | |
| EQUITY | | | | | |
Common stock without par value (9,000 million shares authorized, 8,019 million shares issued) | | | 15,752 | | | 15,746 | |
| Earnings reinvested | | | 432,860 | | | 392,059 | |
| Accumulated other comprehensive income | | | (13,270) | | | (13,764) | |
Common stock held in treasury (3,937 million shares in 2022 and 3,780 million shares in 2021) | | | (240,293) | | | (225,464) | |
| ExxonMobil share of equity | | | 195,049 | | | 168,577 | |
| Noncontrolling interests | | | 7,424 | | | 7,106 | |
| Total Equity | | | 202,473 | | | 175,683 | |
| Total Liabilities and Equity | | | 369,067 | | | 338,923 | |
| | | | | |
| The information in the Notes to Consolidated Financial Statements is an integral part of these statements. |
CONSOLIDATED STATEMENT OF CASH FLOWS
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| (millions of dollars) | Note Reference Number | | 2022 | | 2021 | | 2020 |
| | | | | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | |
| Net income (loss) including noncontrolling interests | | | 57,577 | | | 23,598 | | | (23,251) | |
| Adjustments for noncash transactions | | | | | | | |
| Depreciation and depletion (includes impairments) | 2, 9 | | 24,040 | | | 20,607 | | | 46,009 | |
| Deferred income tax charges/(credits) | 19 | | 3,758 | | | 303 | | | (8,856) | |
| Postretirement benefits expense in excess of/(less than) net payments | | | (2,981) | | | 754 | | | 498 | |
| Other long-term obligation provisions in excess of/(less than) payments | | | (1,932) | | | 50 | | | (1,269) | |
| Dividends received greater than/(less than) equity in current earnings of equity companies | | | (2,446) | | | (668) | | | 979 | |
| Changes in operational working capital, excluding cash and debt | | | | | | | |
Notes and accounts receivable reduction/(increase) | | | (11,019) | | | (12,098) | | | 5,384 | |
Inventories reduction/(increase) | | | (6,947) | | | (489) | | | (315) | |
Other current assets reduction/(increase) | | | (688) | | | (71) | | | 420 | |
Accounts and other payables increase/(reduction) | | | 18,460 | | | 16,820 | | | (7,142) | |
| Net (gain)/loss on asset sales | 5 | | (1,034) | | | (1,207) | | | 4 | |
| All other items - net | | | 9 | | | 530 | | | 2,207 | |
| Net cash provided by operating activities | | | 76,797 | | | 48,129 | | | 14,668 | |
| | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | |
| Additions to property, plant and equipment | | | (18,407) | | | (12,076) | | | (17,282) | |
| Proceeds from asset sales and returns of investments | | | 5,247 | | | 3,176 | | | 999 | |
| Additional investments and advances | | | (3,090) | | | (2,817) | | | (4,857) | |
| Other investing activities including collection of advances | | | 1,508 | | | 1,482 | | | 2,681 | |
| Net cash used in investing activities | | | (14,742) | | | (10,235) | | | (18,459) | |
| | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | |
| Additions to long-term debt | | | 637 | | | 46 | | | 23,186 | |
| Reductions in long-term debt | | | (5) | | | (8) | | | (8) | |
Additions to short-term debt (1) | | | 198 | | | 12,687 | | | 35,396 | |
Reductions in short-term debt (1) | | | (8,075) | | | (29,396) | | | (28,742) | |
| Additions/(reductions) in commercial paper, and debt with three months or less maturity | | | 25 | | | (2,983) | | | (9,691) | |
| Contingent consideration payments | | | (58) | | | (30) | | | (21) | |
| Cash dividends to ExxonMobil shareholders | | | (14,939) | | | (14,924) | | | (14,865) | |
| Cash dividends to noncontrolling interests | | | (267) | | | (224) | | | (188) | |
| Changes in noncontrolling interests | | | (1,475) | | | (436) | | | 623 | |
| Common stock acquired | | | (15,155) | | | (155) | | | (405) | |
| Net cash provided by (used in) financing activities | | | (39,114) | | | (35,423) | | | 5,285 | |
| | | | | | | | |
| Effects of exchange rate changes on cash | | | (78) | | | (33) | | | (219) | |
| Increase/(decrease) in cash and cash equivalents | | | 22,863 | | | 2,438 | | | 1,275 | |
| Cash and cash equivalents at beginning of year | | | 6,802 | | | 4,364 | | | 3,089 | |
| Cash and cash equivalents at end of year | | | 29,665 | | | 6,802 | | | 4,364 | |
| | | | | | | | |
(1) Includes commercial paper with a maturity greater than three months. |
| | | | | | | | |
| The information in the Notes to Consolidated Financial Statements is an integral part of these statements. |
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
| | | | | | | | | | | | | | | | | | | | | | | |
| | ExxonMobil Share of Equity | | |
| | | | | | | |
(millions of dollars) | Common
Stock | Earnings
Reinvested | Accumulated Other Comprehensive Income | Common
Stock Held in
Treasury | ExxonMobil
Share of
Equity | Non-controlling Interests | Total
Equity |
| | | | | | | | |
| Balance as of December 31, 2019 | 15,637 | | 421,341 | | (19,493) | | (225,835) | | 191,650 | | 7,288 | | 198,938 | |
| Amortization of stock-based awards | 696 | | — | | — | | — | | 696 | | — | | 696 | |
| Other | (645) | | — | | — | | — | | (645) | | 692 | | 47 | |
| Net income (loss) for the year | — | | (22,440) | | — | | — | | (22,440) | | (811) | | (23,251) | |
| Dividends - common shares | — | | (14,865) | | — | | — | | (14,865) | | (188) | | (15,053) | |
| Cumulative effect of accounting change | — | | (93) | | — | | — | | (93) | | (1) | | (94) | |
| Other comprehensive income | — | | — | | 2,788 | | — | | 2,788 | | 68 | | 2,856 | |
| Acquisitions, at cost | — | | — | | — | | (405) | | (405) | | (68) | | (473) | |
| | | | | | | |
| Dispositions | — | | — | | — | | 464 | | 464 | | — | | 464 | |
| Balance as of December 31, 2020 | 15,688 | | 383,943 | | (16,705) | | (225,776) | | 157,150 | | 6,980 | | 164,130 | |
| Amortization of stock-based awards | 534 | | — | | — | | — | | 534 | | — | | 534 | |
| Other | (476) | | — | | — | | — | | (476) | | 115 | | (361) | |
| Net income (loss) for the year | — | | 23,040 | | — | | — | | 23,040 | | 558 | | 23,598 | |
| Dividends - common shares | — | | (14,924) | | — | | — | | (14,924) | | (224) | | (15,148) | |
| | | | | | | |
| Other comprehensive income | — | | — | | 2,941 | | — | | 2,941 | | 228 | | 3,169 | |
| Acquisitions, at cost | — | | — | | — | | (155) | | (155) | | (551) | | (706) | |
| Dispositions | — | | — | | — | | 467 | | 467 | | — | | 467 | |
| Balance as of December 31, 2021 | 15,746 | | 392,059 | | (13,764) | | (225,464) | | 168,577 | | 7,106 | | 175,683 | |
| Amortization of stock-based awards | 481 | | — | | — | | — | | 481 | | — | | 481 | |
| Other | (475) | | — | | — | | — | | (475) | | 405 | | (70) | |
| Net income (loss) for the year | — | | 55,740 | | — | | — | | 55,740 | | 1,837 | | 57,577 | |
| Dividends - common shares | — | | (14,939) | | — | | — | | (14,939) | | (267) | | (15,206) | |
| | | | | | | |
| Other comprehensive income | — | | — | | 494 | | — | | 494 | | (178) | | 316 | |
| Acquisitions, at cost | — | | — | | — | | (15,295) | | (15,295) | | (1,479) | | (16,774) | |
| Dispositions | — | | — | | — | | 466 | | 466 | | — | | 466 | |
| Balance as of December 31, 2022 | 15,752 | | 432,860 | | (13,270) | | (240,293) | | 195,049 | | 7,424 | | 202,473 | |
| | | | | | | | | | | |
Common Stock Share Activity (millions of shares) | Issued | Held in
Treasury | Outstanding |
| | | |
| Balance as of December 31, 2019 | 8,019 | | (3,785) | | 4,234 | |
| Acquisitions | — | | (8) | | (8) | |
| | | |
| Dispositions | — | | 7 | | 7 | |
| Balance as of December 31, 2020 | 8,019 | | (3,786) | | 4,233 | |
| Acquisitions | — | | (2) | | (2) | |
| Dispositions | — | | 8 | | 8 | |
| Balance as of December 31, 2021 | 8,019 | | (3,780) | | 4,239 | |
| Acquisitions | — | | (165) | | (165) | |
| Dispositions | — | | 8 | | 8 | |
| Balance as of December 31, 2022 | 8,019 | | (3,937) | | 4,082 | |
| | | |
| The information in the Notes to Consolidated Financial Statements is an integral part of these statements. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Exxon Mobil Corporation.
The Corporation’s principal business involves exploration for, and production of, crude oil and natural gas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a wide variety of specialty products; and pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen and lower-emission fuels.
The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Prior years’ data have been reclassified in certain cases to conform to the 2022 presentation basis.
1. Summary of Accounting Policies
Principles of Consolidation and Accounting for Investments
The Consolidated Financial Statements include the accounts of subsidiaries the Corporation controls and any variable interest entities where it is deemed the primary beneficiary. They also include the Corporation’s share of the undivided interest in certain upstream assets, liabilities, revenues, and expenses. Amounts representing the Corporation’s interest in entities that it does not control, but over which it exercises significant influence, are included in “Investments, advances and long-term receivables”. Under the equity method of accounting, the Corporation recognizes its share of the net income of these companies in “Income from equity affiliates”.
Majority ownership is normally the indicator of control that is the basis on which subsidiaries are consolidated. However, certain factors may indicate that a majority-owned investment is not controlled and, therefore, should be accounted for using the equity method of accounting. These factors occur where the minority shareholders are granted, by law or by contract, substantive participating rights. These include the right to approve operating policies, expense budgets, financing and investment plans, and management compensation and succession plans.
Investments accounted for by the equity method are assessed for possible impairment when events or changes in circumstances indicate that the carrying value of an investment may not be recoverable. Examples of key indicators include a history of operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If the decline in value of the investment is other than temporary, the carrying value of the investment is written down to fair value. In the absence of market prices for the investment, discounted cash flows are used to assess fair value. The Corporation’s share of the cumulative foreign exchange translation adjustment for equity method investments is reported in “Accumulated other comprehensive income”.
Investments in equity securities, other than consolidated subsidiaries and equity method investments, are measured at fair value with changes in fair value recognized in net income. The Corporation uses the modified approach for equity securities that do not have a readily determinable fair value. This modified approach measures investments at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions in a similar investment of the same issuer.
Revenue Recognition
The Corporation generally sells crude oil, natural gas, and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases (e.g., natural gas), products may be sold under long-term agreements, with periodic price adjustments to reflect market conditions. Revenue is recognized at the amount the Corporation expects to receive when the customer has taken control, which is typically when title transfers and the customer has assumed the risks and rewards of ownership. The prices of certain sales are based on price indices that are sometimes not available until the next period. In such cases, estimated realizations are accrued when the sale is recognized, and are finalized when the price is available. Such adjustments to revenue from performance obligations satisfied in previous periods are not significant. Payment for revenue transactions is typically due within 30 days. Future volume delivery obligations that are unsatisfied at the end of the period are expected to be fulfilled through ordinary production or purchases. These performance obligations are based on market prices at the time of the transaction and are fully constrained due to market price volatility.
Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and recorded as exchanges measured at the book value of the item sold.
“Sales and other operating revenue” and “Notes and accounts receivable” include revenue and receivables both within the scope of ASC 606 "Revenue from Contracts with Customers” and those outside the scope of ASC 606. Long-term receivables are primarily from receivables outside the scope of ASC 606. Contract assets are mainly from marketing assistance programs and are not significant. Contract liabilities are mainly customer prepayments and accruals of expected volume discounts and are not significant.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income and Other Taxes
The Corporation excludes from the Consolidated Statement of Income certain sales and value-added taxes imposed on and concurrent with revenue-producing transactions with customers and collected on behalf of governmental authorities. Similar taxes, for which the Corporation is not considered to be an agent for the government, are reported on a gross basis (included in both “Sales and other operating revenue” and “Other taxes and duties”).
The Corporation accounts for U.S. tax on global intangible low-taxed income as an income tax expense in the period in which it is incurred.
Derivative Instruments
The Corporation may use derivative instruments for trading purposes and to offset exposures associated with commodity prices, foreign currency exchange rates, and interest rates that arise from existing assets, liabilities, firm commitments, and forecasted transactions. All derivative instruments, except those designated as normal purchase and normal sale, are recorded at fair value. Derivative assets and liabilities with the same counterparty are netted if the right of offset exists and certain other criteria are met. Collateral payables or receivables are netted against derivative assets and derivative liabilities, respectively.
Recognition and classification of the gain or loss that results from adjusting a derivative to fair value depends on the purpose for the derivative. All gains and losses from derivative instruments for which the Corporation does not apply hedge accounting are immediately recognized in earnings. The Corporation may designate derivatives as fair value or cash flow hedges. For fair value hedges, the gain or loss from derivative instruments and the offsetting gain or loss from the hedged item are recognized in earnings. For cash flow hedges, the gain or loss from the derivative instrument is initially reported as a component of other comprehensive income and subsequently reclassified into earnings in the period that the forecasted transaction affects earnings.
Fair Value
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy levels 1, 2, and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy level 2 inputs are inputs other than quoted prices included within level 1 that are directly or indirectly observable for the asset or liability. Hierarchy level 3 inputs are inputs that are not observable in the market.
Inventories
Crude oil, products, and merchandise inventories are carried at the lower of current market value or cost (generally determined under the last-in, first-out method – LIFO). Inventory costs include expenditures and other charges (including depreciation) directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less.
Property, Plant, and Equipment
Cost Basis. The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. Exploratory well costs are carried as an asset when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Development costs, including costs of productive wells and development dry holes, are capitalized.
Interest costs incurred to finance expenditures during the construction phase of multiyear projects are capitalized as part of the historical cost of acquiring the constructed assets. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Capitalized interest costs are included in property, plant, and equipment and are depreciated over the service life of the related assets.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Depreciation, Depletion, and Amortization. Depreciation, depletion, and amortization are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life, taking obsolescence into consideration.
Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and natural gas reserve volumes. Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using the unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and natural gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.
In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative method is used. The straight-line method is used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the Corporation uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life.
To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes.
Investments in refinery, chemical process, and lubes basestock manufacturing equipment are generally depreciated on a straight-line basis over a 25-year life. Service station buildings and fixed improvements are generally depreciated over a 20-year life. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired.
Impairment Assessment. The Corporation tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Among the events or changes in circumstances which could indicate that the carrying value of an asset or asset group may not be recoverable are the following:
•a significant decrease in the market price of a long-lived asset;
•a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, including a significant decrease in current and projected reserve volumes;
•a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator;
•an accumulation of project costs significantly in excess of the amount originally expected;
•a current-period operating loss combined with a history and forecast of operating or cash flow losses; and
•a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
The Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of ASC 360 and ASC 932, and relies, in part, on the Corporation’s planning and budgeting cycle. Asset valuation analysis, profitability reviews, and other periodic control processes assist the Corporation in assessing whether events or changes in circumstances indicate the carrying amounts of any of its assets may not be recoverable.
Because the lifespans of the vast majority of the Corporation’s major assets are measured in decades, the future cash flows of these assets are predominantly based on long-term oil and natural gas commodity prices and industry margins, development costs, and production costs. Significant reductions in the Corporation’s view of oil or natural gas commodity prices or margin ranges, especially the longer-term prices and margins, and changes in the development plans, including decisions to defer, reduce, or eliminate planned capital spending, can be an indicator of potential impairment. Other events or changes in circumstances can be indicators of potential impairment as well.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In general, the Corporation does not view temporarily low prices or margins as an indication of impairment. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments, and technology and efficiency advancements. OPEC investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities, alternative energy sources, and levels of prosperity. During the lifespan of its major assets, the Corporation expects that oil and gas prices and industry margins will experience significant volatility. Consequently, these assets will experience periods of higher earnings and periods of lower earnings, or even losses. In assessing whether events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the Corporation considers recent periods of operating losses in the context of its longer-term view of prices and margins.
In the Upstream, the standardized measure of discounted cash flows included in the Supplemental Information on Oil and Gas Exploration and Production Activities is required to use prices based on the average of first-of-month prices in the year. These prices represent discrete points in time and could be higher or lower than the Corporation’s price assumptions which are used for impairment assessments. The Corporation believes the standardized measure does not provide a reliable estimate of the expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its oil and gas reserves, and therefore, does not consider it relevant in determining whether events or changes in circumstances indicate the need for an impairment assessment.
Outlook for Energy and Cash Flow Assessment.The annual planning and budgeting process, known as the Corporate Plan, is the mechanism by which resources (capital, operating expenses, and people) are allocated across the Corporation. The foundation for the assumptions supporting the Corporate Plan is the Outlook for Energy (Outlook), which contains the Corporation’s demand and supply projections based on its assessment of current trends in technology, government policies, consumer preferences, geopolitics, economic development, and other factors. Reflective of the existing global policy environment, the Outlook does not attempt to project the degree of necessary future policy and technology advancement and deployment for the world, or the Corporation, to meet net zero by 2050. As future policies and technology advancements emerge, they will be incorporated into the Outlook, and the Corporation’s business plans will be updated accordingly.
If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on the assumptions developed in the Corporate Plan, which is reviewed and approved by the Board of Directors, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the Corporation’s assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, development and operating costs including greenhouse gas emission prices, and foreign currency exchange rates. Notably, when assessing future cash flows, the Corporation includes the estimated costs in support of reaching its 2030 greenhouse gas emission-reduction plans, including its goal of net-zero greenhouse gas emissions (Scope 1 and 2) from unconventional operated assets in the Permian Basin. Volumes are based on projected field and facility production profiles, throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities. Cash flow estimates for impairment testing exclude the effects of derivative instruments. As part of the Corporate Plan, the Company considers estimated greenhouse gas emission costs, even for jurisdictions without a current greenhouse gas pricing policy.
Fair Value of Impaired Assets.An asset group is impaired if its estimated undiscounted cash flows are less than the asset group's carrying value. Impairments are measured by the excess of the carrying value over fair value. The assessment of fair value is based upon the views of a likely market participant. The principal parameters used to establish fair value include estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, throughput and product sales volumes, commodity prices which are consistent with the average of third-party industry experts and government agencies, refining and chemical margins, drilling and development costs, operating costs, and discount rates which are reflective of the characteristics of the asset group.
Other Impairments Related to Property, Plant and Equipment.Unproved properties are assessed periodically to determine whether they have been impaired. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the Corporation's future development plans, the estimated economic chance of success, and the length of time that the Corporation expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.
Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the assets are considered impaired and adjusted to the lower value. Gains on sales of proved and unproved properties are only recognized when there is neither uncertainty about the recovery of costs applicable to any interest retained nor any substantial obligation for future performance by the Corporation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Environmental Liabilities
Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties, and projected cash expenditures are not discounted.
Foreign Currency Translation
The Corporation selects the functional reporting currency for its international subsidiaries based on the currency of the primary economic environment in which each subsidiary operates. Operations in the Product Solutions businesses use the local currency. However, the U.S. dollar is used in countries with a history of high inflation (primarily in Latin America) and Singapore, which predominantly sells into the U.S. dollar export market. Upstream operations which are relatively self-contained and integrated within a particular country, such as in Canada and Europe, use the local currency. Some Upstream operations, primarily in Asia and Africa, use the U.S. dollar because they predominantly sell crude and natural gas production into U.S. dollar-denominated markets.
For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. Russia
In response to Russia’s military action in Ukraine, the Corporation announced in early 2022 that it planned to discontinue operations on the Sakhalin-1 project (“Sakhalin”) and develop steps to exit the venture. In light of this, an impairment assessment was conducted, and management determined that the carrying value of the asset group was not recoverable. As a result, the Corporation’s first-quarter earnings included after-tax charges of $3.4 billion largely representing the full impairment of its operations related to Sakhalin. On a before-tax basis, the charges amounted to $4.6 billion, substantially all of which is reflected in the line captioned “Depreciation and depletion (including impairments)” on the Consolidated Statement of Income. Effective October 14, the Russian government unilaterally terminated the Corporation’s interests in Sakhalin, transferring operations to a Russian operator. The Corporation’s fourth-quarter results include an after-tax benefit of $1.1 billion largely reflecting the impact of the expropriation on the company’s various obligations related to Sakhalin. The Corporation's exit from the project results in approximately 150 million oil-equivalent barrels no longer qualifying as proved reserves at year-end 2022.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. Miscellaneous Financial Information
Research and development expenses totaled $824 million in 2022, $843 million in 2021, and $1,016 million in 2020.
Net income included before-tax aggregate foreign exchange transaction losses of $218 million, $18 million, and $24 million in 2022, 2021, and 2020, respectively.
LIFO Inventory. In 2022, 2021, and 2020, net income included gains of $367 million, $54 million, and $41 million, respectively, attributable to the combined effects of LIFO inventory accumulations and drawdowns. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by $14.9 billion and $14.0 billion at December 31, 2022 and 2021, respectively.
Crude oil, products. and merchandise as of year-end 2022 and 2021 consist of the following:
| | | | | | | | | | | |
| (millions of dollars) | Dec 31, 2022 | | Dec 31, 2021 |
| Crude oil | 6,909 | | | 4,162 | |
| Petroleum products | 6,291 | | | 5,081 | |
Chemical products (1) | 3,806 | | | 3,354 | |
| Gas/other | 3,428 | | | 1,922 | |
| Total | 20,434 | | | 14,519 | |
| | | |
(1) Chemical products includes basic chemicals (olefins and aromatics), polymers (such as polyolefins, adhesions, specialty elastomers, & butyl), intermediates (e.g. hydrocarbon fluids, plasticizers) and synthetics. |
Goodwill Impairments. Mainly as a result of declines in prices for crude oil, natural gas and petroleum products and a significant decline in its market capitalization at the end of the first quarter of 2020, the Corporation recognized before-tax goodwill impairment charges of $611 million. Fair value of the goodwill reporting units primarily reflected market-based estimates of historical EBITDA multiples at the end of the first quarter. Charges related to goodwill impairments in 2020 are included in “Depreciation and depletion” on the Consolidated Statement of Income.
Restructuring. During 2020, ExxonMobil conducted an extensive global review of staffing levels and subsequently commenced targeted workforce reductions within a number of countries to improve efficiency and reduce costs. The programs were completed by the end of 2021 and included both voluntary and involuntary employee separations as well as reductions in contractors.
In 2020 and 2021, the Corporation recorded before-tax charges of $450 million and $58 million respectively, consisting primarily of employee separation costs, associated with announced workforce reduction programs. These costs are captured in “Selling, general and administrative expenses” on the Consolidated Statement of Income and reported within Corporate and Financing. No charges related to the disclosed workforce reduction programs were recorded in 2022, and no further charges are expected.
The reserves recorded in “Accounts payable and accrued liabilities” on the Consolidated Balance Sheet were $403 million at December 31, 2020, and were not material at year-end 2021 and 2022. The cash outflows associated with this liability balance occurred primarily in 2021, and the remainder will occur over the next few years, mainly in the form of monthly payments.
Government Assistance. ASC 832 "Government Assistance" requires disclosure of certain types of government assistance not otherwise covered by authoritative accounting guidance. During 2022, certain governments outside the United States provided payments which, individually and in aggregate, were immaterial to the Corporation's financial results. Among these are programs where governments endeavor to stabilize or cap fuel and energy costs for local consumers. To compensate producers who sell at the government-mandated prices, these governments provide reimbursements to the producers. In 2022, these reimbursements totaled approximately $1.5 billion before tax, and were reflected as reductions to the line captioned "Crude oil and product purchases" on the Consolidated Statement of Income. At December 31, 2022, "Notes and accounts receivable - net" on the Consolidated Balance Sheet included $0.5 billion related to pending government reimbursements. The terms and conditions of these programs, including their duration, vary by country. In the event that any of these programs are discontinued, the Corporation does not expect a significant impact to its financial results. Additionally, in connection with cap and trade programs in certain countries outside the United States, companies receive allowances from governments covering a specified level of emissions from facilities they operate. The terms of these programs vary by country. The Corporation records these allowances at a nominal amount in “Other assets, including intangibles – net” on the Consolidated Balance Sheet.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. Other Comprehensive Income Information
| | | | | | | | | | | | | | | | | |
ExxonMobil Share of Accumulated Other Comprehensive Income (millions of dollars) | Cumulative Foreign Exchange Translation Adjustment | | Postretirement Benefits Reserves Adjustment | | Total |
| | | | | | |
| Balance as of December 31, 2019 | (12,446) | | | (7,047) | | | (19,493) | |
| Current period change excluding amounts reclassified from accumulated other comprehensive income | 1,818 | | | 95 | | | 1,913 | |
| Amounts reclassified from accumulated other comprehensive income | 14 | | | 861 | | | 875 | |
| Total change in accumulated other comprehensive income | 1,832 | | | 956 | | | 2,788 | |
| Balance as of December 31, 2020 | (10,614) | | | (6,091) | | | (16,705) | |
| | | | | |
Current period change excluding amounts reclassified from accumulated other comprehensive income (1) | (883) | | | 2,938 | | | 2,055 | |
| Amounts reclassified from accumulated other comprehensive income | (2) | | | 888 | | | 886 | |
| Total change in accumulated other comprehensive income | (885) | | | 3,826 | | | 2,941 | |
| Balance as of December 31, 2021 | (11,499) | | | (2,265) | | | (13,764) | |
| | | | | |
Current period change excluding amounts reclassified from accumulated other comprehensive income (1) | (3,092) | | | 3,205 | | | 113 | |
| Amounts reclassified from accumulated other comprehensive income | — | | | 381 | | | 381 | |
| Total change in accumulated other comprehensive income | (3,092) | | | 3,586 | | | 494 | |
| Balance as of December 31, 2022 | (14,591) | | | 1,321 | | | (13,270) | |
| | | | | |
(1) Cumulative Foreign Exchange Translation Adjustment includes net investment hedge gain/(loss) net of taxes of $230 million and $329 million in 2022 and 2021, respectively. |
| | | | | | | | | | | | | | | | | |
Amounts Reclassified Out of Accumulated Other Comprehensive Income - Before-tax Income/(Expense) (millions of dollars) | 2022 | | 2021 | | 2020 |
| | | | | | |
Foreign exchange translation gain/(loss) included in net income (Statement of Income line: Other income) | — | | | 2 | | | (14) | |
| Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs (Statement of Income line: Non-service pension and postretirement benefit expense) | (519) | | | (1,229) | | | (1,158) | |
| | | | | | | | | | | | | | | | | |
Income Tax (Expense)/Credit For Components of Other Comprehensive Income (millions of dollars) | 2022 | | 2021 | | 2020 |
| | | | | | |
| Foreign exchange translation adjustment | 54 | | | (114) | | | 118 | |
| Postretirement benefits reserves adjustment (excluding amortization) | (1,120) | | | (983) | | | 109 | |
| Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs | (116) | | | (304) | | | (262) | |
| Total | (1,182) | | | (1,401) | | | (35) | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. Cash Flow Information
The Consolidated Statement of Cash Flows provides information about changes in cash and cash equivalents. Highly liquid investments with maturities of three months or less when acquired are classified as cash equivalents.
For 2022, the “Net (gain)/loss on asset sales” on the Consolidated Statement of Cash Flows includes before-tax amounts from the sale of certain unproved assets in Romania and unconventional assets in Canada and the United States, as well as other smaller divestments.For 2021, the “Net (gain)/loss on asset sales” line includes before-tax amounts from the sale of non-operated upstream assets in the United Kingdom Central and Northern North Sea and the sale of ExxonMobil's global Santoprene business.
For 2020, the “Depreciation and depletion” and “Deferred income tax charges/(credits)” on the Consolidated Statement of Cash Flows include impacts from asset impairments, primarily in Upstream.
| | | | | | | | | | | | | | | | | |
| (millions of dollars) | 2022 | | 2021 | | 2020 |
| | | | | | |
| Income taxes paid | 15,364 | | | 5,341 | | | 2,428 | |
| | | | | |
| Cash interest paid | | | | | |
| Included in cash flows from operating activities | 666 | | | 819 | | | 786 | |
| Capitalized, included in cash flows from investing activities | 838 | | | 655 | | | 665 | |
| Total cash interest paid | 1,504 | | | 1,474 | | | 1,451 | |
6. Additional Working Capital Information
| | | | | | | | | | | | | | | | | | | | | | | |
| (millions of dollars) | | Dec 31, 2022 | | Dec 31, 2021 |
| | | | | |
| Notes and accounts receivable | | | | |
| Trade, less reserves of $168 million and $159 million | | 32,844 | | | 26,883 | |
| Other, less reserves of $402 million and $381 million | | 8,905 | | | 5,500 | |
| Total | | 41,749 | | | 32,383 | |
| Notes and loans payable | | | | |
| Bank loans | | 379 | | | 276 | |
| Commercial paper | | 74 | | | 1,608 | |
| Long-term debt due within one year | | 181 | | | 2,392 | |
| Total | | 634 | | | 4,276 | |
| Accounts payable and accrued liabilities | | | | |
| Trade payables | | 33,169 | | | 26,623 | |
| Payables to equity companies | | 14,585 | | | 8,885 | |
| Accrued taxes other than income taxes | | 3,969 | | | 3,896 | |
| Other | | 11,474 | | | 11,362 | |
| Total | | 63,197 | | | 50,766 | |
Trade notes and accounts receivables include both receivables within the scope of ASC 606 and outside the scope of ASC 606. Receivables outside the scope of ASC 606 primarily relate to physically settled commodity contracts accounted for as derivatives. Credit quality and type of customer are generally similar between receivables within the scope of ASC 606 and those outside it.
The Corporation has short-term committed lines of credit of $0.3 billion which were unused as of December 31, 2022. These lines are available for general corporate purposes.
The weighted-average interest rate on short-term borrowings outstanding was 1.5 percent and 0.2 percent at December 31, 2022 and 2021, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. Equity Company Information
The summarized financial information below includes amounts related to certain less-than-majority-owned companies and majority-owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see Note 1). These companies are primarily engaged in oil and gas exploration and production, natural gas marketing, transportation of crude oil, and petrochemical manufacturing in North America; natural gas exploration, production and distribution in Europe; liquefied natural gas (LNG) operations in Africa; and exploration, production, LNG operations, and the manufacture and sale of petroleum and petrochemical products in Asia and the Middle East. Also included are several refining and marketing ventures.
The share of total equity company revenues from sales to ExxonMobil consolidated companies was 11 percent, 10 percent and 11 percent in the years 2022, 2021 and 2020, respectively.
The Corporation’s ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships. Differences between the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned, to the extent practicable, to specific assets and liabilities based on the company’s analysis of the factors giving rise to the difference. The amortization of this difference, as appropriate, is included in “Income from equity affiliates” on the Consolidated Statement of Income.
Impairments related to upstream equity investments of $0.6 billion, $0.2 billion and $0.6 billion in 2022, 2021, and 2020, respectively, are included in “Income from equity affiliates” or “Other income” on the Consolidated Statement of Income.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Equity Company Financial Summary (millions of dollars) | | 2022 | | 2021 | | 2020 |
| Total | ExxonMobil
Share | | Total | ExxonMobil Share | | Total | ExxonMobil
Share |
| | | | | | | | | | |
| Total revenues | | 183,812 | | 57,528 | | | 116,972 | | 34,995 | | | 69,954 | | 21,282 | |
| Income before income taxes | | 61,550 | | 19,279 | | | 35,142 | | 9,278 | | | 12,743 | | 2,830 | |
| Income taxes | | 23,149 | | 7,603 | | | 11,010 | | 2,763 | | | 4,333 | | 870 | |
| Income from equity affiliates | | 38,401 | | 11,676 | | | 24,132 | | 6,515 | | | 8,410 | | 1,960 | |
| | | | | | | | | |
| Current assets | | 77,457 | | 24,994 | | | 45,267 | | 15,542 | | | 33,419 | | 11,969 | |
| Long-term assets | | 153,186 | | 42,921 | | | 150,699 | | 41,614 | | | 150,358 | | 41,457 | |
| Total assets | | 230,643 | | 67,915 | | | 195,966 | | 57,156 | | | 183,777 | | 53,426 | |
| | | | | | | | | |
| Current liabilities | | 53,640 | | 15,555 | | | 28,862 | | 8,297 | | | 18,827 | | 5,245 | |
| Long-term liabilities | | 62,009 | | 18,929 | | | 63,138 | | 19,084 | | | 66,053 | | 19,927 | |
| Net assets | | 114,994 | | 33,431 | | | 103,966 | | 29,775 | | | 98,897 | | 28,254 | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A list of significant equity companies as of December 31, 2022, together with the Corporation’s percentage ownership interest, is detailed below:
| | | | | |
| Percentage Ownership Interest |
| |
| Upstream | |
| Aera Energy LLC | 48 |
| Barzan Gas Company Limited | 7 |
| BEB Erdgas und Erdoel GmbH & Co. KG | 50 |
| Caspian Pipeline Consortium | 8 |
| Coral FLNG S.A. | 25 |
| Cross Timbers Energy LLC | 50 |
| GasTerra B.V. | 25 |
| Golden Pass LNG Terminal LLC | 30 |
| Golden Pass Pipeline LLC | 30 |
| Marine Well Containment Company LLC | 10 |
| Mozambique Rovuma Venture S.p.A. | 36 |
| Nederlandse Aardolie Maatschappij B.V. | 50 |
| Papua New Guinea Liquefied Natural Gas Global Company LDC | 33 |
| Permian Highway Pipeline LLC | 20 |
| Qatar Liquefied Gas Company Limited (2) | 24 |
| Qatar Liquefied Gas Company Limited (7) | 25 |
| Ras Laffan Liquefied Natural Gas Company Limited | 25 |
| Ras Laffan Liquefied Natural Gas Company Limited (II) | 31 |
| Ras Laffan Liquefied Natural Gas Company Limited (3) | 30 |
| South Hook LNG Terminal Company Limited | 24 |
| Tengizchevroil LLP | 25 |
| Terminale GNL Adriatico S.r.l. | 71 |
| |
| Energy Products, Chemical Products, and/or Specialty Products | |
| Al-Jubail Petrochemical Company | 50 |
| Alberta Products Pipe Line Ltd. | 45 |
| Fujian Refining & Petrochemical Co. Ltd. | 25 |
| Gulf Coast Growth Ventures LLC | 50 |
| Infineum USA L.P. | 50 |
| Permian Express Partners LLC | 12 |
| Saudi Aramco Mobil Refinery Company Ltd. | 50 |
| Saudi Yanbu Petrochemical Co. | 50 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. Investments, Advances and Long-Term Receivables
| | | | | | | | |
| (millions of dollars) | Dec 31, 2022 | Dec 31, 2021 |
| | |
| Equity method company investments and advances | | |
| Investments | 34,522 | | 31,225 | |
| Advances, net of allowances of $28 million and $34 million | 8,049 | | 8,326 | |
| Total equity method company investments and advances | 42,571 | | 39,551 | |
| Equity securities carried at fair value and other investments at adjusted cost basis | 278 | | 138 | |
| Long-term receivables and miscellaneous, net of reserves of $1,623 million and $5,974 million | 6,944 | | 5,506 | |
| Total | 49,793 | | 45,195 | |
9. Property, Plant and Equipment and Asset Retirement Obligations
| | | | | | | | | | | | | | |
Property, Plant and Equipment (millions of dollars) | December 31, 2022 | December 31, 2021 |
| Cost | Net | Cost | Net |
| | | | | |
| Upstream | 350,748 | | 144,146 | | 375,813 | | 156,951 | |
| Energy Products | 58,393 | | 26,765 | | 58,504 | | 27,354 | |
| Chemical Products | 36,322 | | 19,064 | | 33,514 | | 17,409 | |
| Specialty Products | 8,895 | | 4,303 | | 9,217 | | 4,447 | |
| Other | 18,335 | | 10,414 | | 18,014 | | 10,391 | |
| Total | 472,693 | | 204,692 | | 495,062 | | 216,552 | |
In 2022, the Corporation identified situations where events or changes in circumstances indicated that the carrying value of certain long-lived assets may not be recoverable and conducted impairment assessments. Before-tax impairment charges of $4.5 billion were recognized during the first quarter as a result of the Corporation's plans to discontinue operations on the Sakhalin-1 project and develop steps to exit the venture in response to Russia's military action in Ukraine (Refer to Note 2 for additional information.) Other before-tax impairment charges recognized during 2022 included $1.5 billion in Upstream and $0.4 billion in Energy Products.
In 2021, the Corporation recognized before-tax impairment charges of $1.2 billion largely as a result of changes to Upstream development plans. In 2020, as part of the Corporation's annual review and approval of its business and strategic plan, a decision was made to no longer develop a significant portion of the dry gas portfolio in the United States, Canada and Argentina. The impairment of these assets resulted in before-tax charges of $24.4 billion in Upstream. Other before-tax impairment charges during 2020 included $0.9 billion in Upstream and $0.6 billion in Energy Products.
Impairment charges are primarily recognized in the lines “Depreciation and depletion” and “Exploration expenses, including dry holes” on the Consolidated Statement of Income. Accumulated depreciation and depletion totaled $268,001 million at the end of 2022 and $278,510 million at the end of 2021.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Asset Retirement Obligations
The Corporation incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation;obligation, technical assessments of the assets;assets, estimated amounts and timing of settlements;settlements, discount rates;rates, and inflation rates. Asset retirement obligations incurred in the current period were Level 3 fair value measurements. The costs associated with these liabilities are capitalized as part of the related assets and depreciated as the reserves are produced. Over time, the liabilities are accreted for the change in their present value.
Asset retirement obligations for downstream and chemical facilities in the Product Solutions business generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites generally have indeterminate lives based on plans for continued operations and as such, the fair value of the conditional legal obligations cannot be measured, since it is impossible to estimate the future settlement dates of such obligations.
The following table summarizes the activity in the liability for asset retirement obligations:
| | | 2020 | | 2019 | | 2018 | |
| (millions of dollars) | | (millions of dollars) | | 2022 | | 2021 | | 2020 |
| | | (millions of dollars) | | | | |
| Balance at January 1 | Balance at January 1 | 11,280 | | | 12,103 | | | 12,705 | | Balance at January 1 | | 10,630 | | | 11,247 | | | 11,280 | |
| Accretion expense and other provisions | Accretion expense and other provisions | 584 | | | 649 | | | 681 | | Accretion expense and other provisions | | 744 | | | 548 | | | 584 | |
| Reduction due to property sales | Reduction due to property sales | (77) | | | (1,085) | | | (333) | | Reduction due to property sales | | (328) | | | (1,002) | | | (77) | |
| Payments made | Payments made | (669) | | | (827) | | | (600) | | Payments made | | (518) | | | (444) | | | (669) | |
| Liabilities incurred | Liabilities incurred | 26 | | | 89 | | | 46 | | Liabilities incurred | | 119 | | | 42 | | | 26 | |
| Foreign currency translation | Foreign currency translation | 239 | | | 84 | | | (481) | | Foreign currency translation | | (330) | | | (147) | | | 239 | |
| Revisions | Revisions | (136) | | | 267 | | | 85 | | Revisions | | 174 | | | 386 | | | (136) | |
| Balance at December 31 | Balance at December 31 | 11,247 | | | 11,280 | | | 12,103 | | Balance at December 31 | | 10,491 | | | 10,630 | | | 11,247 | |
The long-term Asset Retirement Obligations were $10,558$9,650 million and $10,279$9,985 million at December 31, 2020,2022 and 2019,2021, respectively, and are included in “Other long-term obligations.”obligations” on the Consolidated Balance Sheet.Estimated cash payments in 2023 and 2024 are $841 million and $806 million, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. Accounting for Suspended Exploratory Well Costs
The Corporation continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports.
The following two tables provide details of the changes in the balance of suspended exploratory well costs, as well asincluding an aging summary of those costs.
Change in capitalized suspended exploratory well costs:
| | | 2020 | | 2019 | | 2018 | |
Change in capitalized suspended exploratory well costs (millions of dollars) | | Change in capitalized suspended exploratory well costs (millions of dollars) | | 2022 | | 2021 | | 2020 |
| | | (millions of dollars) | | | | |
| Balance beginning at January 1 | Balance beginning at January 1 | 4,613 | | | 4,160 | | | 3,700 | | Balance beginning at January 1 | | 4,120 | | | 4,382 | | | 4,613 | |
| Additions pending the determination of proved reserves | Additions pending the determination of proved reserves | 208 | | | 532 | | | 564 | | Additions pending the determination of proved reserves | | 378 | | | 420 | | | 208 | |
| Charged to expense | Charged to expense | (318) | | | (46) | | | (7) | | Charged to expense | | (259) | | | (325) | | | (318) | |
Reclassifications to wells, facilities and equipment based on the
determination of proved reserves | Reclassifications to wells, facilities and equipment based on the
determination of proved reserves | (174) | | | (37) | | | (48) | | Reclassifications to wells, facilities and equipment based on the determination of proved reserves | | (142) | | | (328) | | | (174) | |
| Divestments/Other | Divestments/Other | 53 | | | 4 | | | (49) | | Divestments/Other | | (585) | | | (29) | | | 53 | |
| Ending balance at December 31 | Ending balance at December 31 | 4,382 | | | 4,613 | | | 4,160 | | Ending balance at December 31 | | 3,512 | | | 4,120 | | | 4,382 | |
| Ending balance attributed to equity companies included above | Ending balance attributed to equity companies included above | 306 | | | 306 | | | 306 | | Ending balance attributed to equity companies included above | | 306 | | | 306 | | | 306 | |
Period end capitalized suspended exploratory well costs:
| | | 2020 | | 2019 | | 2018 | |
Period-end capitalized suspended exploratory well costs (millions of dollars) | | Period-end capitalized suspended exploratory well costs (millions of dollars) | | 2022 | | 2021 | | 2020 |
| | | (millions of dollars) | | | | |
| Capitalized for a period of one year or less | Capitalized for a period of one year or less | 208 | | | 532 | | | 564 | | Capitalized for a period of one year or less | | 378 | | | 420 | | | 208 | |
| Capitalized for a period of between one and five years | Capitalized for a period of between one and five years | 1,828 | | | 2,206 | | | 2,028 | | Capitalized for a period of between one and five years | | 969 | | | 1,642 | | | 1,828 | |
| Capitalized for a period of between five and ten years | Capitalized for a period of between five and ten years | 1,932 | | | 1,411 | | | 1,150 | | Capitalized for a period of between five and ten years | | 1,410 | | | 1,657 | | | 1,932 | |
| Capitalized for a period of greater than ten years | Capitalized for a period of greater than ten years | 414 | | | 464 | | | 418 | | Capitalized for a period of greater than ten years | | 755 | | | 401 | | | 414 | |
| Capitalized for a period greater than one year - subtotal | Capitalized for a period greater than one year - subtotal | 4,174 | | | 4,081 | | | 3,596 | | Capitalized for a period greater than one year - subtotal | | 3,134 | | | 3,700 | | | 4,174 | |
| Total | Total | 4,382 | | | 4,613 | | | 4,160 | | Total | | 3,512 | | | 4,120 | | | 4,382 | |
Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a breakdown of the number of projects with only exploratory well costs capitalized for a period of one year or less and those that have had exploratory well costs capitalized for a period greater than one year.
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
Number of projects that only have exploratory well costs capitalized for a
period of one year or less | 3 | | | 4 | | | 6 | |
Number of projects that have exploratory well costs capitalized for a period
greater than one year | 34 | | | 46 | | | 52 | |
| Total | 37 | | | 50 | | | 58 | |
| | | | | | | | | | | | | | | | | | | | |
| | | 2022 | | 2021 | | 2020 |
| Number of projects that only have exploratory well costs capitalized for a period of one year or less | | 10 | | | 4 | | | 3 | |
| Number of projects that have exploratory well costs capitalized for a period greater than one year | | 26 | | | 30 | | | 34 | |
| Total | | 36 | | | 34 | | | 37 | |
Of the 3426 projects that have exploratory well costs capitalized for a period greater than one year as of December 31, 2020, 132022, 11 projects have drilling in the preceding year or exploratory activity planned in the next two years, while the remaining 2115 projects are those with completed exploratory activity progressing toward development.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The table below provides additional detail for those 2115 projects, which total $3,181$2,324 million.
| | | | | | | | | | | | | | | | | |
| Country/Project | Dec. 31, 2020 | Years Wells Drilled / Acquired | Comment |
| (millions of dollars) | |
| Angola |
–Kaombo Split Hub Phase 2 | 10 | 2006 | Evaluating development plan to tie into planned production facilities. |
| Argentina |
–La Invernada | 72 | 2014 | Evaluating development plan to tie into planned infrastructure. |
| Australia |
–Gorgon Area Ullage | 347 | 1994 | - | 2015 | Evaluating development plans to tie into existing LNG facilities. |
| Brazil |
–Bacalhau Phase 1 | 284 | 2018 | Continuing discussions with the government regarding development plan. |
| Canada |
–Hibernia North | 26 | 2019 | Awaiting capacity in existing/planned infrastructure. |
| Iraq |
–Kurdistan Pirmam | 109 | 2015 | Evaluating commercialization alternatives, while waiting for government approval to enter Gas Holding Period. |
| Kazakhstan |
–Kairan | 53 | 2004 | - | 2007 | Evaluating commercialization and field development alternatives, while continuing discussions with the government regarding the development plan. |
| Mozambique |
–Rovuma LNG Future Non-Straddling Train | 120 | 2017 | Evaluating/progressing development plan to tie into planned LNG facilities. |
–Rovuma LNG Phase 1 | 150 | 2017 | Progressing development plan to tie into planned LNG facilities. |
–Rovuma LNG Unitized Trains | 35 | 2017 | Evaluating/progressing development plan to tie into planned LNG facilities. |
| Nigeria |
–Bonga North | 34 | 2004 | - | 2009 | Evaluating/progressing development plan for tieback to existing/planned infrastructure. |
–Bonga SW | 3 | 2001 | Evaluating/progressing development plan for tieback to existing/planned infrastructure. |
–Bosi | 79 | 2002 | - | 2006 | Development activity under way, while continuing discussions with the government regarding development plan. |
–Owowo | 67 | 2009 | - | 2016 | Evaluating development plan for tieback to existing production facilities. |
–Pegi | 32 | 2009 | Awaiting capacity in existing/planned infrastructure. |
–Ukot SW | 41 | 2014 | Evaluating development plan for tieback to existing production facilities. |
| Papua New Guinea |
–Papua LNG | 246 | 2017 | Evaluating/progressing development plans. |
–P'nyang | 116 | 2012 | - | 2018 | Evaluating/progressing development plans. |
| Romania |
–Neptun Deep | 536 | 2012 | - | 2016 | Continuing discussions with the government regarding development plan. |
| Tanzania |
–Tanzania Block 2 | 525 | 2012 | - | 2015 | Evaluating development alternatives, while continuing discussions with the government regarding development plan. |
| Vietnam |
–Blue Whale | 296 | 2011 | - | 2015 | Evaluating/progressing development plans. |
| Total 2020 (21 projects) | 3,181 | |
| | | | | | | | | | | | | | | | | |
| Country/Project | December 31, 2022 | Years Wells Drilled / Acquired | Comment |
| (millions of dollars) |
| | | | | |
| Angola |
| Block 32 Central NE Hub | 66 | 2007 | - | 2021 | Evaluating development plan for tieback to existing infrastructure. |
| | | | | |
| Argentina |
| La Invernada | 72 | 2014 | Evaluating development plan to tie into planned infrastructure. |
| | | | | |
| Australia |
| Gorgon Area Ullage | 305 | 1994 | - | 2015 | Evaluating development plans to tie into existing LNG facilities. |
| | | | | |
| Canada |
| Hibernia North | 24 | 2019 | Awaiting capacity in existing/planned infrastructure. |
| | | | | |
| Guyana |
| Uaru | 117 | 2017 | - | 2021 | Continuing discussions with the government regarding development plan. |
| | | | | |
| Kazakhstan |
| Kairan | 53 | 2004 | - | 2007 | Evaluating commercialization and field development alternatives, while continuing discussions with the government regarding the development plan. |
| | | | | |
| Mozambique |
| Rovuma LNG Future Non-Straddling Train | 120 | 2017 | Evaluating/progressing development plan to tie into planned LNG facilities. |
| Rovuma LNG Phase 1 | 150 | 2017 | Progressing development plan to tie into planned LNG facilities. |
| Rovuma LNG Unitized Trains | 35 | 2017 | Evaluating/progressing development plan to tie into planned LNG facilities. |
| | | | | |
| Nigeria |
| Bonga North | 34 | 2004 | - | 2009 | Evaluating/progressing development plan for tieback to existing/planned infrastructure. |
| | | | | |
| Papua New Guinea |
| Muruk | 165 | 2017 | - | 2019 | Evaluating/progressing development plans. |
| Papua LNG | 246 | 2017 | Evaluating/progressing development plans. |
| P'nyang | 116 | 2012 | - | 2018 | Evaluating/progressing development plans. |
| | | | | |
| Tanzania |
| Block 2 | 525 | 2012 | - | 2015 | Evaluating development alternatives, while continuing discussions with the government regarding development plan. |
| | | | | |
| Vietnam |
| Blue Whale | 296 | 2011 | - | 2015 | Evaluating/progressing development plans. |
| | | | | |
| Total 2022 (15 projects) | 2,324 | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. Leases
The Corporation and its consolidated affiliates generally purchase the property, plant and equipment used in operations, but there are situations where assets are leased, primarily for drilling equipment, tankers, office buildings, railcars, and other moveable equipment. Right of use assets and lease liabilities are established on the balance sheet for leases with an expected term greater than one year by discounting the amounts fixed in the lease agreement for the duration of the lease which is reasonably certain, considering the probability of exercising any early termination and extension options. The portion of the fixed payment related to service costs for drilling equipment, tankers and finance leases is excluded from the calculation of right of use assets and lease liabilities. Generally, assets are leased only for a portion of their useful lives, and are accounted for as operating leases. In limited situations assets are leased for nearly all of their useful lives, and are accounted for as finance leases.
Variable payments under these lease agreements are not significant. Residual value guarantees, restrictions, or covenants related to leases, and transactions with related parties are also not significant. In general, leases are capitalized using the incremental borrowing rate of the leasing affiliate. The Corporation’s activities as a lessor are not significant.
| Lease Cost (millions of dollars) | | Lease Cost (millions of dollars) | | Operating Leases | | Finance Leases |
| | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| | | Operating Leases | | | | | | | | |
| | Drilling Rigs and Related
Equipment | | Other | | Total | | Finance
Leases | |
| | (millions of dollars) | |
| Lease Cost | 2020 | |
| Operating lease cost | Operating lease cost | 297 | | | 1,256 | | | 1,553 | | | Operating lease cost | | 1,776 | | | 1,542 | | | 1,553 | | | | |
| Short-term and other (net of sublease rental income) | Short-term and other (net of sublease rental income) | 530 | | | 1,083 | | | 1,613 | | | Short-term and other (net of sublease rental income) | | 1,389 | | | 1,351 | | | 1,613 | | | | |
| Amortization of right of use assets | Amortization of right of use assets | | 143 | | Amortization of right of use assets | | | | 243 | | | 133 | | | 143 | |
| Interest on lease liabilities | Interest on lease liabilities | | 169 | | Interest on lease liabilities | | | | 210 | | | 158 | | | 169 | |
| Total | 827 | | | 2,339 | | | 3,166 | | | 312 | | |
Total (1) | | Total (1) | | 3,165 | | | 2,893 | | | 3,166 | | | 453 | | | 291 | | | 312 | |
| (1) Includes $908 million, $681 million and $827 million for drilling rigs and related equipment operating leases in 2022, 2021, and 2020, respectively. | | (1) Includes $908 million, $681 million and $827 million for drilling rigs and related equipment operating leases in 2022, 2021, and 2020, respectively. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Leases | | |
| | Drilling Rigs and Related
Equipment | | Other | | Total | | Finance
Leases |
| | (millions of dollars) |
| Lease Cost | 2019 |
| Operating lease cost | 238 | | | 1,196 | | | 1,434 | | | |
| Short-term and other (net of sublease rental income) | 926 | | | 1,116 | | | 2,042 | | | |
| Amortization of right of use assets | | | | | | | 121 | |
| Interest on lease liabilities | | | | | | | 133 | |
| Total | 1,164 | | | 2,312 | | | 3,476 | | | 254 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance Sheet (millions of dollars) | | Operating Leases | | Finance Leases |
| December 31, 2022 | | December 31, 2021 | | December 31, 2022 | | December 31, 2021 |
| | | | | | | | |
| Right of use assets | | | | | | | | |
| Included in Other assets, including intangibles - net | | 6,451 | | | 6,082 | | | | | |
| Included in Property, plant and equipment - net | | | | | | 2,090 | | | 2,412 | |
| Total right of use assets | | 6,451 | | | 6,082 | | | 2,090 | | | 2,412 | |
| | | | | | | | |
| Lease liability due within one year | | | | | | | | |
| Included in Accounts payable and accrued liabilities | | 1,527 | | | 1,367 | | | 5 | | | 4 | |
| Included in Notes and loans payable | | | | | | 69 | | | 111 | |
| Long-term lease liability | | | | | | | | |
| Included in Other long-term obligations | | 4,067 | | | 3,823 | | | | | |
| Included in Long-term debt | | | | | | 1,389 | | | 1,761 | |
| Included in Long-term obligations to equity companies | | | | | | 126 | | | 131 | |
Total lease liability (2) | | 5,594 | | | 5,190 | | | 1,589 | | | 2,007 | |
| | | | | | | | |
| Weighted-average remaining lease term (years) | | 9 | | 10 | | 22 | | 20 |
| Weighted-average discount rate (percent) | | 2.4 | % | | 2.3 | % | | 8.0 | % | | 7.7 | % |
| | | | | | | | |
(2) Includes $1,646 million and $935 million for drilling rigs and related equipment operating leases in 2022 and 2021, respectively. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Leases | | |
| | Drilling Rigs and Related
Equipment | | Other | | Total | | Finance
Leases |
| | (millions of dollars) |
| Balance Sheet | December 31, 2020 |
| Right of use assets | | | | | | | |
| Included in Other assets, including intangibles - net | 834 | | | 5,244 | | | 6,078 | | | |
| Included in Property, plant and equipment - net | | | | | | | 2,188 | |
| Total right of use assets | 834 | | | 5,244 | | | 6,078 | | | 2,188 | |
| | | | | | | |
| Lease liability due within one year | | | | | | | |
| Included in Accounts payable and accrued liabilities | 243 | | | 925 | | | 1,168 | | | 4 | |
| Included in Notes and loans payable | | | | | | | 102 | |
| Long-term lease liability | | | | | | | |
| Included in Other long-term obligations | 589 | | | 3,405 | | | 3,994 | | | |
| Included in Long-term debt | | | | | | | 1,680 | |
| Included in Long-term obligations to equity companies | | | | | | | 135 | |
| Total lease liability | 832 | | | 4,330 | | | 5,162 | | | 1,921 | |
| | | | | | | |
| Weighted average remaining lease term - years | 5 | | 12 | | 11 | | 20 |
| Weighted average discount rate - percent | 2.2 | % | | 3.0 | % | | 2.9 | % | | 8.9 | % |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Leases | | |
| | Drilling Rigs and Related
Equipment | | Other | | Total | | Finance
Leases |
| | (millions of dollars) |
| Balance Sheet | December 31, 2019 |
| Right of use assets | | | | | | | |
| Included in Other assets, including intangibles - net | 572 | | | 6,061 | | | 6,633 | | | |
| Included in Property, plant and equipment - net | | | | | | | 1,997 | |
| Total right of use assets | 572 | | | 6,061 | | | 6,633 | | | 1,997 | |
| | | | | | | |
| Lease liability due within one year | | | | | | | |
| Included in Accounts payable and accrued liabilities | 221 | | | 990 | | | 1,211 | | | 15 | |
| Included in Notes and loans payable | | | | | | | 84 | |
| Long-term lease liability | | | | | | | |
| Included in Other long-term obligations | 330 | | | 4,152 | | | 4,482 | | | |
| Included in Long-term debt | | | | | | | 1,670 | |
| Included in Long-term obligations to equity companies | | | | | | | 139 | |
| Total lease liability | 551 | | | 5,142 | | | 5,693 | | | 1,908 | |
| | | | | | | |
| Weighted average remaining lease term - years | 4 | | 11 | | 10 | | 20 |
| Weighted average discount rate - percent | 3.1 | % | | 3.2 | % | | 3.2 | % | | 9.7 | % |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| Maturity Analysis of Lease Liabilities (millions of dollars) | | Maturity Analysis of Lease Liabilities (millions of dollars) | Operating Leases | | Finance Leases |
| December 31, 2022 |
| | | Operating Leases | | | |
| | Drilling Rigs and Related
Equipment | | Other | | Total | | Finance
Leases | |
| | (millions of dollars) | |
| Maturity Analysis of Lease Liabilities | December 31, 2020 | |
| 2021 | 259 | | | 1,031 | | | 1,290 | | | 268 | | |
| 2022 | 256 | | | 817 | | | 1,073 | | | 259 | | |
| 2023 | 2023 | 97 | | | 482 | | | 579 | | | 252 | | 2023 | 1,623 | | | 195 | |
| 2024 | 2024 | 71 | | | 387 | | | 458 | | | 247 | | 2024 | 1,231 | | | 193 | |
| 2025 | 2025 | 71 | | | 342 | | | 413 | | | 240 | | 2025 | 914 | | | 187 | |
| 2026 and beyond | 124 | | | 2,157 | | | 2,281 | | | 2,544 | | |
| 2026 | | 2026 | 401 | | | 184 | |
| 2027 | | 2027 | 334 | | | 176 | |
| 2028 and beyond | | 2028 and beyond | 1,861 | | | 1,960 | |
| Total lease payments | Total lease payments | 878 | | | 5,216 | | | 6,094 | | | 3,810 | | Total lease payments | 6,364 | | | 2,895 | |
| Discount to present value | Discount to present value | (46) | | | (886) | | | (932) | | | (1,889) | | Discount to present value | (770) | | | (1,306) | |
| Total lease liability | Total lease liability | 832 | | | 4,330 | | | 5,162 | | | 1,921 | | Total lease liability | 5,594 | | | 1,589 | |
In addition to the lease liabilities in the table immediately above, at December 31, 2020,2022, undiscounted commitments for leases not yet commenced totaled $445$4,246 million for operating leases and $4,109$3,054 million for finance leases. Estimated cash payments for operating and finance leases not yet commenced are $268 million and $260 million for 2023 and 2024 respectively. The finance leases relate to floating production storage and offloading vessels, LNG transportation vessels, a wastewater treatment facility, a CO2 transportation and service agreement, and a long-term hydrogen purchase agreement. The underlying assets for these finance leases were primarily designed by, and are being constructed by, the lessors.
| Other Information (millions of dollars) | | Other Information (millions of dollars) | | Operating Leases | | Finance Leases |
| | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| | | Operating Leases | | | | | | | |
| | Drilling Rigs and Related
Equipment | | Other | | Total | | Finance
Leases | |
| | (millions of dollars) | |
| Other Information | 2020 | |
| Cash paid for amounts included in the measurement of lease liabilities | Cash paid for amounts included in the measurement of lease liabilities | | | | | | | | Cash paid for amounts included in the measurement of lease liabilities | | | | | |
| Cash flows from operating activities | Cash flows from operating activities | | 1,159 | | | 1,159 | | | 31 | | Cash flows from operating activities | | 1,119 | | | 1,135 | | | 1,159 | | | 20 | | | 20 | | | 31 | |
| Cash flows from investing activities | Cash flows from investing activities | 283 | | | 283 | | | Cash flows from investing activities | | 500 | | | 291 | | | 283 | | | | |
| Cash flows from financing activities | Cash flows from financing activities | | 94 | | Cash flows from financing activities | | | | 149 | | | 110 | | | 94 | |
| | Noncash right of use assets recorded in exchange for lease liabilities | 552 | | | 183 | | | 735 | | | 108 | | |
| Noncash right of use assets recorded for lease liabilities | | Noncash right of use assets recorded for lease liabilities | | | | | |
| In exchange for lease liabilities during the period | | In exchange for lease liabilities during the period | | 1,997 | | | 1,405 | | | 735 | | | 73 | | | 200 | | | 108 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Leases | | |
| | Drilling Rigs and Related
Equipment | | Other | | Total | | Finance
Leases |
| | (millions of dollars) |
| Other Information | 2019 |
| Cash paid for amounts included in the measurement of lease liabilities | | | | | | | |
| Cash flows from operating activities | | | 1,116 | | | 1,116 | | | 54 | |
| Cash flows from investing activities | 258 | | | | | 258 | | | |
| Cash flows from financing activities | | | | | | | 177 | |
| | | | | | | |
| Noncash right of use assets recorded for lease liabilities | | | | | | | |
For January 1 adoption of ASC 842 | 445 | | | 2,818 | | | 3,263 | | | |
| In exchange for lease liabilities during the period | 350 | | | 3,313 | | | 3,663 | | | 422 | |
Disclosures under the previous lease standard (ASC 840)
Net rental cost incurred under both cancelable and noncancelable operating leases was $2,715 million in 2018.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. Earnings Per Share
| | | | | | | | | | | | | | | | | |
| Earnings per common share | 2020 | | 2019 | | 2018 |
Net income (loss) attributable to ExxonMobil (millions of dollars) | (22,440) | | | 14,340 | | | 20,840 | |
| | | | | |
Weighted average number of common shares outstanding (millions of shares) | 4,271 | | | 4,270 | | | 4,270 | |
| | | | | |
Earnings (Loss) per common share (dollars) (1) | (5.25) | | | 3.36 | | | 4.88 | |
| | | | | |
Dividends paid per common share (dollars) | 3.48 | | | 3.43 | | | 3.23 | |
(1)The earnings (loss) per common share and earnings (loss) per common share - assuming dilution are the same in each period shown. | | | | | | | | | | | | | | | | | |
| Earnings per common share | 2022 | | 2021 | | 2020 |
Net income (loss) attributable to ExxonMobil (millions of dollars) | 55,740 | | | 23,040 | | | (22,440) | |
| | | | | |
Weighted-average number of common shares outstanding (millions of shares) | 4,205 | | | 4,275 | | | 4,271 | |
| | | | | |
Earnings (loss) per common share (dollars) (1) | 13.26 | | | 5.39 | | | (5.25) | |
| | | | | |
Dividends paid per common share (dollars) | 3.55 | | | 3.49 | | | 3.48 | |
| | | | | |
(1) The earnings (loss) per common share and earnings (loss) per common share - assuming dilution are the same in each period shown. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. Financial Instruments and Derivatives
Financial Instruments.The estimated fair value of financial instruments and derivatives at December 31, 20202022 and December 31, 2019,2021, and the related hierarchy level for the fair value measurement iswas as follows:
| | | | At December 31, 2020 | | December 31, 2022 |
| | | (millions of dollars) | | |
| | | Fair Value | | | | | | | | | | Fair Value | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Total Gross Assets & Liabilities | | Effect of Counterparty Netting | | Effect of Collateral Netting | | Difference in Carrying Value and Fair Value | | Net Carrying Value | |
| (millions of dollars) | | (millions of dollars) | Level 1 | | Level 2 | | Level 3 | | Total Gross Assets & Liabilities | | Effect of Counterparty Netting | | Effect of Collateral Netting | | Difference in Carrying Value and Fair Value | | Net Carrying Value |
| Assets | Assets | | | | | | | | | | | | | | | | Assets | | | | | | | | | | | | | | | |
Derivative assets (1) | Derivative assets (1) | 1,247 | | | 194 | | | — | | | 1,441 | | | (1,282) | | | (6) | | | — | | | 153 | | Derivative assets (1) | 4,309 | | | 3,455 | | | — | | | 7,764 | | | (5,778) | | | (969) | | | — | | | 1,017 | |
Advances to/receivables from equity companies (2)(6) | Advances to/receivables from equity companies (2)(6) | — | | | 3,275 | | | 5,904 | | | 9,179 | | | — | | | — | | | (367) | | | 8,812 | | Advances to/receivables from equity companies (2)(6) | — | | | 2,406 | | | 4,958 | | | 7,364 | | | — | | | — | | | 685 | | | 8,049 | |
Other long-term financial assets (3) | Other long-term financial assets (3) | 1,235 | | | — | | | 944 | | | 2,179 | | | — | | | — | | | 125 | | | 2,304 | | Other long-term financial assets (3) | 1,208 | | | — | | | 1,413 | | | 2,621 | | | — | | | — | | | 346 | | | 2,967 | |
| | Liabilities | Liabilities | | Liabilities | |
Derivative liabilities (4) | Derivative liabilities (4) | 1,443 | | | 254 | | | — | | | 1,697 | | | (1,282) | | | (202) | | | — | | | 213 | | Derivative liabilities (4) | 3,417 | | | 3,264 | | | — | | | 6,681 | | | (5,778) | | | (79) | | | — | | | 824 | |
Long-term debt (5) | Long-term debt (5) | 50,263 | | | 125 | | | 4 | | | 50,392 | | | — | | | — | | | (4,890) | | | 45,502 | | Long-term debt (5) | 33,112 | | | 1,880 | | | 6 | | | 34,998 | | | — | | | — | | | 4,173 | | | 39,171 | |
Long-term obligations to equity companies (6) | Long-term obligations to equity companies (6) | — | | | — | | | 3,530 | | | 3,530 | | | — | | | — | | | (277) | | | 3,253 | | Long-term obligations to equity companies (6) | — | | | — | | | 2,467 | | | 2,467 | | | — | | | — | | | (129) | | | 2,338 | |
Other long-term financial liabilities (7) | Other long-term financial liabilities (7) | — | | | — | | | 964 | | | 964 | | | — | | | — | | | 44 | | | 1,008 | | Other long-term financial liabilities (7) | — | | | — | | | 679 | | | 679 | | | — | | | — | | | 38 | | | 717 | |
| | | | At December 31, 2019 | | December 31, 2021 |
| | | (millions of dollars) | | |
| | | Fair Value | | | | | | | | | | Fair Value | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Total Gross Assets & Liabilities | | Effect of Counterparty Netting | | Effect of Collateral Netting | | Difference in Carrying Value and Fair Value | | Net Carrying Value | |
| (millions of dollars) | | (millions of dollars) | Level 1 | | Level 2 | | Level 3 | | Total Gross Assets & Liabilities | | Effect of Counterparty Netting | | Effect of Collateral Netting | | Difference in Carrying Value and Fair Value | | Net Carrying Value |
| Assets | Assets | | | | | | | | | | | | | | | | Assets | | | | | | | | | | | | | | | |
Derivative assets (1) | Derivative assets (1) | 533 | | | 102 | | | — | | | 635 | | | (463) | | | (70) | | | — | | | 102 | | Derivative assets (1) | 1,422 | | | 1,523 | | | — | | | 2,945 | | | (1,930) | | | (28) | | | — | | | 987 | |
Advances to/receivables from equity companies (2)(6) | Advances to/receivables from equity companies (2)(6) | — | | | 1,941 | | | 6,729 | | | 8,670 | | | — | | | — | | | (128) | | | 8,542 | | Advances to/receivables from equity companies (2)(6) | — | | | 3,076 | | | 5,373 | | | 8,449 | | | — | | | — | | | (123) | | | 8,326 | |
Other long-term financial assets (3) | Other long-term financial assets (3) | 1,145 | | | — | | | 974 | | | 2,119 | | | — | | | — | | | 44 | | | 2,163 | | Other long-term financial assets (3) | 1,134 | | | — | | | 1,058 | | | 2,192 | | | — | | | — | | | 181 | | | 2,373 | |
| | Liabilities | Liabilities | | Liabilities | |
Derivative liabilities (4) | Derivative liabilities (4) | 568 | | | 70 | | | — | | | 638 | | | (463) | | | (105) | | | — | | | 70 | | Derivative liabilities (4) | 1,701 | | | 2,594 | | | — | | | 4,295 | | | (1,930) | | | (306) | | | — | | | 2,059 | |
Long-term debt (5) | Long-term debt (5) | 25,652 | | | 134 | | | 3 | | | 25,789 | | | — | | | — | | | (1,117) | | | 24,672 | | Long-term debt (5) | 44,454 | | | 88 | | | 3 | | | 44,545 | | | — | | | — | | | (2,878) | | | 41,667 | |
Long-term obligations to equity companies (6) | Long-term obligations to equity companies (6) | — | | | — | | | 4,245 | | | 4,245 | | | — | | | — | | | (257) | | | 3,988 | | Long-term obligations to equity companies (6) | — | | | — | | | 3,084 | | | 3,084 | | | — | | | — | | | (227) | | | 2,857 | |
Other long-term financial liabilities (7) | Other long-term financial liabilities (7) | — | | | — | | | 1,042 | | | 1,042 | | | — | | | — | | | 16 | | | 1,058 | | Other long-term financial liabilities (7) | — | | | — | | | 902 | | | 902 | | | — | | | — | | | 58 | | | 960 | |
| (1) Included in the Balance Sheet lines: Notes and accounts receivable - net and Other assets, including intangibles - net. | | (1) Included in the Balance Sheet lines: Notes and accounts receivable - net and Other assets, including intangibles - net. |
(2) Included in the Balance Sheet line: Investments, advances and long-term receivables. | | (2) Included in the Balance Sheet line: Investments, advances and long-term receivables. |
(3) Included in the Balance Sheet lines: Investments, advances and long-term receivables and Other assets, including intangibles - net. | | (3) Included in the Balance Sheet lines: Investments, advances and long-term receivables and Other assets, including intangibles - net. |
(4) Included in the Balance Sheet lines: Accounts payable and accrued liabilities and Other long-term obligations. | | (4) Included in the Balance Sheet lines: Accounts payable and accrued liabilities and Other long-term obligations. |
(5) Excluding finance lease obligations. | | (5) Excluding finance lease obligations. |
(6) Advances to/receivables from equity companies and long-term obligations to equity companies are mainly designated as hierarchy level 3 inputs. The fair value is calculated by discounting the remaining obligations by a rate consistent with the credit quality and industry of the company. | | (6) Advances to/receivables from equity companies and long-term obligations to equity companies are mainly designated as hierarchy level 3 inputs. The fair value is calculated by discounting the remaining obligations by a rate consistent with the credit quality and industry of the company. |
(7) Included in the Balance Sheet line: Other long-term obligations. Includes contingent consideration related to a prior year acquisition where fair value is based on expected drilling activities and discount rates. | | (7) Included in the Balance Sheet line: Other long-term obligations. Includes contingent consideration related to a prior year acquisition where fair value is based on expected drilling activities and discount rates. |
(1)Included in the Balance Sheet lines: Notes and accounts receivable - net and Other assets, including intangibles - net
(2)Included in the Balance Sheet line: Investments, advances and long-term receivables
(3)Included in the Balance Sheet lines: Investments, advances and long term receivables and Other assets, including intangibles - net
(4)Included in the Balance Sheet lines: Accounts payable and accrued liabilities and Other long-term obligations
(5)Excluding finance lease obligations
(6)Advances to/receivables from equity companies and long-term obligations to equity companies are mainly designated as hierarchy level 3 inputs. The fair value is calculated by discounting the remaining obligations by a rate consistent with the credit quality and industry of the company.
(7)Included in the Balance Sheet line: Other long-term obligations. Includes contingent consideration related to a prior year acquisition where fair value is based on expected drilling activities and discount rates..
The increase in the estimated fair value and book value of long-term debt reflects the Corporation’s issuance of $23 billion of long-term debt during 2020.
At December 31, 20202022 and December 31, 2019,2021, respectively, the Corporation had $504$1,494 million and $379$641 million of collateral under master netting arrangements not offset against the derivatives on the Consolidated Balance Sheet, primarily related to initial margin requirements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Derivative Instruments. The Corporation’s size, strong capital structure, geographic diversity, and the complementary nature of the Upstream, Downstream and Chemical businessesits business segments reduce the Corporation’s enterprise-wide risk from changes in commodity prices, currency rates, and interest rates. In addition, the Corporation uses commodity-based contracts, including derivatives, to manage commodity price risk and for trading purposes.to generate returns from trading. Commodity contracts held for trading purposes are presented in the Consolidated Statement of Income on a net basis in the line “Sales and other operating revenue”. The Corporation’s commodity derivatives are not accounted for under hedge accounting. At times, the Corporation also enters into currency and interest rate derivatives, none of which are material to the Corporation’s financial position as of December 31, 20202022 and 2019,2021, or results of operations for the years ended 2020, 20192022, 2021, and 2018.2020.
Credit risk associated with the Corporation’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of and financial limits placed on derivative counterparties. The Corporation maintains a system of controls that includes the authorization, reporting, and monitoring of derivative activity.
The net notional long/(short) position of derivative instruments at December 31, 2020,2022 and December 31, 2019,2021, was as follows:
| | December 31, | | December 31, | |
| 2020 | | 2019 | |
| (millions) | | (millions) | December 31, | | December 31, |
| 2022 | | 2021 |
| | (millions) | | | |
| Crude oil (barrels) | Crude oil (barrels) | 40 | | | 57 | | Crude oil (barrels) | 4 | | | 82 | |
| Petroleum products (barrels) | Petroleum products (barrels) | (46) | | | (38) | | Petroleum products (barrels) | (52) | | | (48) | |
| Natural gas (MMBTUs) | Natural gas (MMBTUs) | (500) | | | (165) | | Natural gas (MMBTUs) | (64) | | | (115) | |
|
Realized and unrealized gains/(losses) on derivative instruments that were recognized in the Consolidated Statement of Income are included in the following lines on a before-tax basis:
| | 2020 | | 2019 | | 2018 | |
| (millions of dollars) | | (millions of dollars) | 2022 | | 2021 | | 2020 |
| | (millions of dollars) | | | |
| Sales and other operating revenue | Sales and other operating revenue | 404 | | | (412) | | | 130 | | Sales and other operating revenue | (1,763) | | | (3,818) | | | 404 | |
| Crude oil and product purchases | Crude oil and product purchases | (407) | | | 179 | | | (120) | | Crude oil and product purchases | 314 | | | 48 | | | (407) | |
| Total | Total | (3) | | | (233) | | | 10 | | Total | (1,449) | | | (3,770) | | | (3) | |
14. Long-Term Debt
At December 31, 2020,2022, long-term debt consisted of $41,026$34,507 million due in U.S. dollars and $6,156$6,052 million representing the U.S. dollar equivalent at year-end exchange rates of amounts payable in foreign currencies. These amounts exclude that portion of long-term debt, totaling $2,930$181 million, which matures within one year and is included in current liabilities. The increase in
On December 22, 2022, the estimated fair valueCompany irrevocably deposited sufficient cash with the Trustee to fund (i) the redemption of its 2.726% notes due 2023 and book value(ii) the redemption of long-termits 1.571% notes due 2023. After the deposit of the funds, the Corporation was released from its obligation and the debt reflects the Corporation’s issuance of $23 billion of long-term debt during 2020. was extinguished.
The amounts of long-term debt, excluding finance lease obligations, maturing in each of the four years after December 31, 2021,2023, in millions of dollars, are: 2022 – $3,340; 2023 – $4,024; 2024 – $3,968; and$4,665; 2025 – $4,672.$4,667; 2026 – $3,644; and 2027 – $1,090. At December 31, 2020,2022, the Corporation had 0Corporation's unused long-term lines of credit.credit were $1.2 billion.
The Corporation may use non-derivative financial instruments, such as its foreign currency-denominated debt, as hedges of its net investments in certain foreign subsidiaries. Under this method, the change in the carrying value of the financial instruments due to foreign exchange fluctuations is reported in accumulated other comprehensive income. As of December 31, 2020,2022, the Corporation has designated its $5.5$4.8 billion of Euro-denominated long-term debt and related accrued interest as a net investment hedge of its European business. The net investment hedge is deemed to be perfectly effective.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Summarized long-term debt at year-end 20202022 and 20192021 are shown in the table below:
| | | Average Rate (1) | | Dec 31,
2020 | | Dec 31,
2019 | |
| (millions of dollars, except where stated otherwise) | | (millions of dollars, except where stated otherwise) | Average Rate (1) | | Dec 31, 2022 | | Dec 31, 2021 |
| | | | (millions of dollars) | | | | |
Exxon Mobil Corporation (2) | Exxon Mobil Corporation (2) | | | | | | Exxon Mobil Corporation (2) | | | | | |
| 2.222% notes due 2021 | | 0 | | | 2,500 | | |
| 2.397% notes due 2022 | | 1,150 | | | 1,150 | | |
| 1.902% notes due 2022 | | 750 | | | 750 | | |
Floating-rate notes due 2022 (Issued 2015) | 1.118% | | 500 | | | 500 | | |
Floating-rate notes due 2022 (Issued 2019) | 1.189% | | 750 | | | 750 | | |
| 1.571% notes due 2023 | 1.571% notes due 2023 | | 2,750 | | | 0 | | 1.571% notes due 2023 | | — | | | 2,750 | |
| 2.726% notes due 2023 | 2.726% notes due 2023 | | 1,250 | | | 1,250 | | 2.726% notes due 2023 | | — | | | 1,250 | |
| 3.176% notes due 2024 | 3.176% notes due 2024 | | 1,000 | | | 1,000 | | 3.176% notes due 2024 | | 1,000 | | | 1,000 | |
| 2.019% notes due 2024 | 2.019% notes due 2024 | | 1,000 | | | 1,000 | | 2.019% notes due 2024 | | 1,000 | | | 1,000 | |
| 2.709% notes due 2025 | 2.709% notes due 2025 | | 1,750 | | | 1,750 | | 2.709% notes due 2025 | | 1,750 | | | 1,750 | |
| 2.992% notes due 2025 | 2.992% notes due 2025 | | 2,807 | | | 0 | | 2.992% notes due 2025 | | 2,781 | | | 2,794 | |
| 3.043% notes due 2026 | 3.043% notes due 2026 | | 2,500 | | | 2,500 | | 3.043% notes due 2026 | | 2,500 | | | 2,500 | |
| 2.275% notes due 2026 | 2.275% notes due 2026 | | 1,000 | | | 1,000 | | 2.275% notes due 2026 | | 1,000 | | | 1,000 | |
| 3.294% notes due 2027 | 3.294% notes due 2027 | | 1,000 | | | 0 | | 3.294% notes due 2027 | | 1,000 | | | 1,000 | |
| 2.440% notes due 2029 | 2.440% notes due 2029 | | 1,250 | | | 1,250 | | 2.440% notes due 2029 | | 1,250 | | | 1,250 | |
| 3.482% notes due 2030 | 3.482% notes due 2030 | | 2,000 | | | 0 | | 3.482% notes due 2030 | | 2,000 | | | 2,000�� | |
| 2.610% notes due 2030 | 2.610% notes due 2030 | | 2,000 | | | 0 | | 2.610% notes due 2030 | | 2,000 | | | 2,000 | |
| 2.995% notes due 2039 | 2.995% notes due 2039 | | 750 | | | 750 | | 2.995% notes due 2039 | | 750 | | | 750 | |
| 4.227% notes due 2040 | 4.227% notes due 2040 | | 2,091 | | | 0 | | 4.227% notes due 2040 | | 2,084 | | | 2,087 | |
| 3.567% notes due 2045 | 3.567% notes due 2045 | | 1,000 | | | 1,000 | | 3.567% notes due 2045 | | 1,000 | | | 1,000 | |
| 4.114% notes due 2046 | 4.114% notes due 2046 | | 2,500 | | | 2,500 | | 4.114% notes due 2046 | | 2,500 | | | 2,500 | |
| 3.095% notes due 2049 | 3.095% notes due 2049 | | 1,500 | | | 1,500 | | 3.095% notes due 2049 | | 1,500 | | | 1,500 | |
| 4.327% notes due 2050 | 4.327% notes due 2050 | | 2,750 | | | 0 | | 4.327% notes due 2050 | | 2,750 | | | 2,750 | |
| 3.452% notes due 2051 | 3.452% notes due 2051 | | 2,750 | | | 0 | | 3.452% notes due 2051 | | 2,750 | | | 2,750 | |
| Exxon Mobil Corporation - Euro-denominated | Exxon Mobil Corporation - Euro-denominated | | Exxon Mobil Corporation - Euro-denominated | | | |
| 0.142% notes due 2024 | 0.142% notes due 2024 | | 1,841 | | | 0 | | 0.142% notes due 2024 | | 1,600 | | | 1,698 | |
| 0.524% notes due 2028 | 0.524% notes due 2028 | | 1,227 | | | 0 | | 0.524% notes due 2028 | | 1,066 | | | 1,133 | |
| 0.835% notes due 2032 | 0.835% notes due 2032 | | 1,227 | | | 0 | | 0.835% notes due 2032 | | 1,066 | | | 1,133 | |
| 1.408% notes due 2039 | 1.408% notes due 2039 | | 1,227 | | | 0 | | 1.408% notes due 2039 | | 1,066 | | | 1,133 | |
XTO Energy Inc. (3) | XTO Energy Inc. (3) | | XTO Energy Inc. (3) | | | |
| 6.100% senior notes due 2036 | 6.100% senior notes due 2036 | | 192 | | | 193 | | 6.100% senior notes due 2036 | | 189 | | | 191 | |
| 6.750% senior notes due 2037 | 6.750% senior notes due 2037 | | 294 | | | 296 | | 6.750% senior notes due 2037 | | 289 | | | 291 | |
| 6.375% senior notes due 2038 | 6.375% senior notes due 2038 | | 227 | | | 229 | | 6.375% senior notes due 2038 | | 224 | | | 226 | |
| Mobil Corporation | | |
| 8.625% debentures due 2021 | | 0 | | | 250 | | |
| | | Industrial revenue bonds due 2022-2051 | Industrial revenue bonds due 2022-2051 | 0.437% | | 2,461 | | | 2,461 | | Industrial revenue bonds due 2022-2051 | 1.000% | | 2,245 | | | 2,244 | |
| Other U.S. dollar obligations | | 78 | | | 89 | | |
| Other foreign currency obligations | | 61 | | | 64 | | |
| Finance lease obligations | 8.730% | | 1,680 | | | 1,670 | | |
| | Finance leases & other obligations | | Finance leases & other obligations | 5.856% | | 3,299 | | | 1,862 | |
| Debt issuance costs | Debt issuance costs | | (131) | | | (60) | | Debt issuance costs | | (100) | | | (114) | |
| Total long-term debt | Total long-term debt | | 47,182 | | | 26,342 | | Total long-term debt | | 40,559 | | | 43,428 | |
| (1) Average effective or imputed interest rates at December 31, 2022. | | (1) Average effective or imputed interest rates at December 31, 2022. |
(2) Includes premiums of $115 million in 2022 and $131 million in 2021. | | (2) Includes premiums of $115 million in 2022 and $131 million in 2021. |
(3) Includes premiums of $76 million in 2022 and $82 million in 2021. | | (3) Includes premiums of $76 million in 2022 and $82 million in 2021. |
| |
|
(1)Average effective interest rate for debt and average imputed interest rate for finance leases at December 31, 2020.
(2)Includes premiums of $148 million in 2020.
(3)Includes premiums of $87 million in 2020 and $92 million in 2019.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15. Incentive Program
The 2003 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock, and other forms of awards. Awards may be granted to eligible employees of the Corporation and those affiliates at least 50 percent owned. Outstanding awards are subject to certain forfeiture provisions contained in the program or award instrument. Options and SARs may be granted at prices not less than 100 percent of market value on the date of grant and have a maximum life of 10 years. The maximum number of shares of stock that may be issued under the 2003 Incentive Program is 220 million. Awards that are forfeited, expire, or are settled in cash, do not count against this maximum limit. The 2003 Incentive Program does not have a specified term. New awards may be made until the available shares are depleted, unless the Board terminates the plan early. At the end of 2020,2022, remaining shares available for award under the 2003 Incentive Program were 7160 million.
Restricted Stock and Restricted Stock Units. Awards totaling 8,6819,392 thousand, 8,9368,133 thousand, and 8,7718,681 thousand of restricted (nonvested) common stock units were granted in 2020, 2019,2022, 2021, and 2018,2020, respectively. Compensation expense for these awards is based on the price of the stock at the date of grant and is recognized in income over the requisite service period. Shares for these awards are issued to employees from treasury stock. The units that are settled in cash are recorded as liabilities, and their changes in fair value are recognized over the vesting period. During the applicable restricted periods, the shares and units may not be sold or transferred and are subject to forfeiture. The majority of the awards have graded vesting periods, with 50 percent of the shares and units in each award vesting after three years, and the remaining 50 percent vesting after seven years. As a result of an expansion of the program in 2022, some new participants will be eligible for awards that vest in full after three years. Awards granted to a small number of senior executives have vesting periods of five years for 50 percent of the award and of 10 years for the remaining 50 percent of the award, except that for awards granted prior to 2020 the vesting of the 10-year portion of the award is delayed until retirement if later than 10 years.
The Corporation has purchased shares in the open market and through negotiated transactions to offset shares or units settled in shares issued in conjunction with benefit plans and programs. The Corporation suspended its first quarter 2021 anti-dilutive share repurchase program due to current market uncertainty and intends to resume this program in the future as market conditions improve.
The following tables summarize information about restricted stock and restricted stock units for the year ended December 31, 2020.2022.
| | | 2020 | |
| Restricted stock and units outstanding | | Restricted stock and units outstanding | 2022 |
| Restricted stock and units outstanding | Shares | | Weighted Average Grant-Date
Fair Value per Share | Shares | Weighted-Average
Grant-Date
Fair Value per Share |
| | | (thousands) | | (dollars) | | (thousands) | (dollars) |
| Issued and outstanding at January 1 | Issued and outstanding at January 1 | 39,628 | | | 84.50 | | Issued and outstanding at January 1 | 38,922 | | 70.38 | |
| Awards issued in 2020 | 9,030 | | | 68.95 | | |
| Awards issued in 2022 | | Awards issued in 2022 | 8,222 | | 63.49 | |
| Vested | Vested | (8,990) | | | 86.84 | | Vested | (9,235) | | 76.31 | |
| Forfeited | Forfeited | (83) | | | 82.04 | | Forfeited | (336) | | 63.67 | |
| Issued and outstanding at December 31 | Issued and outstanding at December 31 | 39,585 | | | 80.43 | | Issued and outstanding at December 31 | 37,573 | | 67.47 | |
| | Value of restricted stock units | Value of restricted stock units | 2020 | | 2019 | | 2018 | Value of restricted stock units | 2022 | | 2021 | | 2020 |
Grant price (dollars) | Grant price (dollars) | 41.15 | | | 68.77 | | | 77.66 | | Grant price (dollars) | 110.46 | | | 62.76 | | | 41.15 | |
| | Value at date of grant: | Value at date of grant: | (millions of dollars) | Value at date of grant: | (millions of dollars) |
| Units settled in stock | Units settled in stock | 325 | | | 559 | | | 620 | | Units settled in stock | 931 | | | 461 | | | 325 | |
| Units settled in cash | Units settled in cash | 32 | | | 55 | | | 61 | | Units settled in cash | 106 | | | 49 | | | 32 | |
| Total value | Total value | 357 | | | 614 | | | 681 | | Total value | 1,037 | | | 510 | | | 357 | |
As of December 31, 2020,2022, there was $1,356$1,765 million of unrecognized compensation cost related to the nonvested restricted awards. This cost is expected to be recognized over a weighted-average period of 4.24.8 years. The compensation cost charged against income for the restricted stock and restricted stock units was $648 million, $612 million, and $672 million $741 million,for 2022, 2021, and $774 million for 2020, 2019, and 2018, respectively. The income tax benefit recognized in income related to this compensation expense was $51$52 million, $51$49 million, and $42$51 million for the same periods, respectively. The fair value of shares and units vested in 2022, 2021, and 2020 2019, and 2018 was $367$1,027 million, $647$562 million, and $722$367 million, respectively. Cash payments of $34$89 million, $56$48 million, and $61$34 million for vested restricted stock units settled in cash were made in 2020, 2019,2022, 2021, and 2018,2020, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
16. Litigation and Other Contingencies
Litigation. A variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Corporation does not record liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of our contingency disclosures, “significant” includes material matters, as well as other matters, which management believes should be disclosed. ExxonMobil will continue to defend itself vigorously in these matters. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a material adverse effect upon the Corporation’s operations, financial condition, or financial statements taken as a whole.
Other Contingencies. The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2020,2022, for guarantees relating to notes, loans and performance under contracts. Where guarantees for environmental remediation and other similar matters do not include a stated cap, the amounts reflect management’s estimate of the maximum potential exposure. Where it is not possible to make a reasonable estimation of the maximum potential amount of future payments, future performance is expected to be either immaterial or have only a remote chance of occurrence.
| | | | | | | | | | | | | | | | | |
| | December 31, 2020 |
| | Equity Company Obligations (1) | | Other Third-Party Obligations | | Total |
| | (millions of dollars) |
| Guarantees | | | | | |
| Debt-related | 986 | | | 124 | | | 1,110 | |
| Other | 745 | | | 4,944 | | | 5,689 | |
| Total | 1,731 | | | 5,068 | | | 6,799 | |
(1)ExxonMobil share. | | | | | | | | | | | | | | | | | |
| December 31, 2022 |
| | | | | |
| (millions of dollars) | Equity Company Obligations (1) | | Other Third-Party Obligations | | Total |
| | | | | | |
| Guarantees | | | | | |
| Debt-related | 1,206 | | | 152 | | | 1,358 | |
| Other | 728 | | | 5,374 | | | 6,102 | |
| Total | 1,934 | | | 5,526 | | | 7,460 | |
| | | | | |
(1) ExxonMobil share. |
Additionally, the Corporation and its affiliates have numerous long-term sales and purchase commitments in their various business activities, all of which are expected to be fulfilled with no adverse consequences material to the Corporation’s operations or financial condition.
In accordance with a Venezuelan nationalization decree issued in February 2007, a subsidiary of the Venezuelan National Oil Company (PdVSA) assumed the operatorship of the Cerro Negro Heavy Oil Project. The decree also required conversion of the Cerro Negro Project into a “mixed enterprise” and an increase in PdVSA’s or one of its affiliate’s ownership interest in the Project. ExxonMobil refused to accede to the terms proffered by the government, and on June 27, 2007, the government expropriated ExxonMobil’s 41.67 percent interest in the Cerro Negro Project.
ExxonMobil collected awards of $908 million in an arbitration against PdVSA under the rules of the International Chamber of Commerce in respect of an indemnity related to the Cerro Negro Project and $260 million in an arbitration for compensation due for the La Ceiba Project and for export curtailments at the Cerro Negro Project under rules of International Centre for Settlement of Investment Disputes (ICSID). An ICSID arbitration award relating to the Cerro Negro Project’s expropriation ($1.4 billion) was annulled based on a determination that a prior Tribunal failed to adequately explain why the cap on damages in the indemnity owed by PdVSA did not affect or limit the amount owed for the expropriation of the Cerro Negro Project. ExxonMobil filed a new claim seeking to restore the original award of damages for the Cerro Negro Project with ICSID on September 26, 2018.
The net impact of this matter on the Corporation’s consolidated financial results cannot be reasonably estimated. Regardless, the Corporation does not expect the resolution to have a material effect upon the Corporation’s operations or financial condition.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
An affiliate of ExxonMobil is one of the Contractors under a Production Sharing Contract (PSC) with the Nigerian National Petroleum Corporation (NNPC) covering the Erha block located in the offshore waters of Nigeria. ExxonMobil's affiliate is the operator of the block and owns a 56.25 percent interest under the PSC. The Contractors are in dispute with NNPC regarding NNPC's lifting of crude oil in excess of its entitlement under the terms of the PSC. In accordance with the terms of the PSC, the Contractors initiated arbitration in Abuja, Nigeria, under the Nigerian Arbitration and Conciliation Act. On October 24, 2011, a three-member arbitral Tribunal issued an award upholding the Contractors' position in all material respects and awarding damages to the Contractors jointly in an amount of approximately $1.8 billion plus $234 million in accrued interest. The Contractors petitioned a Nigerian federal court for enforcement of the award, and NNPC petitioned the same court to have the award set aside. On May 22, 2012, the court set aside the award. The Contractors appealed that judgment to the Court of Appeal, Abuja Judicial Division. On July 22, 2016, the Court of Appeal upheld the decision of the lower court setting aside the award. On October 21, 2016, the Contractors appealed the decision to the Supreme Court of Nigeria. In June 2013, the Contractors filed a lawsuit against NNPC in the Nigerian federal high court in order to preserve their ability to seek enforcement of the PSC in the courts if necessary. Following dismissal by this court, the Contractors appealed to the Nigerian Court of Appeal in June 2016. In October 2014, the Contractors filed suit in the United States District Court for the Southern District of New York (SDNY) to enforce, if necessary, the arbitration award against NNPC assets residing within that jurisdiction. NNPC moved to dismiss the lawsuit. On September 4, 2019, the SDNY dismissed the Contractors’ petition to recognize and enforce the Erha arbitration award. The Contractors filed a notice of appeal in the Second Circuit on October 2, 2019. At this time, the net impact of this matter on the Corporation's consolidated financial results cannot be reasonably estimated. However, regardless of the outcome of enforcement proceedings, the Corporation does not expect the proceedings to have a material effect upon the Corporation's operations or financial condition.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
17. Pension and Other Postretirement Benefits
The benefit obligations and plan assets associated with the Corporation’s principal benefit plans are measured on December 31.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement |
| | U.S. | | Non-U.S. | | Benefits |
| | 2020 | | 2019 | | 2020 | | 2019 | | 2020 | | 2019 |
| | (percent) |
| Weighted-average assumptions used to determine benefit obligations at December 31 | | | | | | | | | | | |
| Discount rate | 2.80 | | | 3.50 | | | 1.60 | | | 2.30 | | | 2.80 | | | 3.50 | |
| Long-term rate of compensation increase | 5.50 | | | 5.75 | | | 4.20 | | | 4.80 | | | 5.50 | | | 5.75 | |
| | | | | | | | | | | |
| | (millions of dollars) |
| Change in benefit obligation | | | | | | | | | | | |
| Benefit obligation at January 1 | 20,959 | | | 18,174 | | | 29,918 | | | 25,378 | | | 8,113 | | | 7,471 | |
| Service cost | 965 | | | 757 | | | 707 | | | 551 | | | 181 | | | 139 | |
| Interest cost | 708 | | | 766 | | | 657 | | | 763 | | | 277 | | | 315 | |
Actuarial loss/(gain) (1) | 1,287 | | | 2,562 | | | 2,344 | | | 3,703 | | | (66) | | | 556 | |
Benefits paid (2) (3) | (1,987) | | | (1,300) | | | (1,317) | | | (1,196) | | | (510) | | | (517) | |
| Foreign exchange rate changes | — | | | — | | | 1,375 | | | 391 | | | 23 | | | 25 | |
| Amendments, divestments and other | (270) | | | 0 | | | (58) | | | 328 | | | 117 | | | 124 | |
| Benefit obligation at December 31 | 21,662 | | | 20,959 | | | 33,626 | | | 29,918 | | | 8,135 | | | 8,113 | |
| Accumulated benefit obligation at December 31 | 17,502 | | | 16,387 | | | 30,952 | | | 27,236 | | | — | | | — | |
(1)Actuarial loss/(gain) primarily reflects changes in discount rates, partially offset by lower long-term rates of compensation.
(2)Benefit payments for funded and unfunded plans.
(3)For 2020 and 2019, other postretirement benefits paid are net of $16 million and $20 million of Medicare subsidy receipts, respectively. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | | | | | | | | | | |
| (millions of dollars, except where stated otherwise) | U.S. | | Non-U.S. | | |
| 2022 | | 2021 | | 2022 | | 2021 | | 2022 | | 2021 |
| | | | | | | | | | | | |
| Weighted-average assumptions used to determine benefit obligations at December 31 | | | | | | | | | | | |
Discount rate (percent) | 5.60 | | | 3.00 | | | 4.90 | | | 2.20 | | | 5.60 | | | 3.10 | |
Long-term rate of compensation increase (percent) | 4.50 | | | 4.50 | | | 5.20 | | | 4.20 | | | 4.50 | | | 4.50 | |
| | | | | | | | | | | |
| Change in benefit obligation | | | | | | | | | | | |
| Benefit obligation at January 1 | 18,511 | | | 21,662 | | | 29,492 | | | 33,626 | | | 7,265 | | | 8,135 | |
| Service cost | 712 | | | 919 | | | 570 | | | 774 | | | 138 | | | 188 | |
| Interest cost | 518 | | | 558 | | | 614 | | | 526 | | | 216 | | | 221 | |
Actuarial loss/(gain) (1) | (4,432) | | | (747) | | | (7,742) | | | (2,803) | | | (1,990) | | | (881) | |
Benefits paid (2)(3) | (2,959) | | | (3,810) | | | (1,415) | | | (1,550) | | | (492) | | | (517) | |
| Foreign exchange rate changes | — | | | — | | | (2,258) | | | (1,162) | | | (47) | | | 3 | |
| Amendments, divestments and other | — | | | (71) | | | 81 | | | 81 | | | 121 | | | 116 | |
| Benefit obligation at December 31 | 12,350 | | | 18,511 | | | 19,342 | | | 29,492 | | | 5,211 | | | 7,265 | |
| Accumulated benefit obligation at December 31 | 10,367 | | | 15,781 | | | 18,047 | | | 27,373 | | | — | | | — | |
| | | | | | | | | | | |
(1) Actuarial loss/(gain) primarily reflects higher discount rates. |
(2) Benefit payments for funded and unfunded plans. |
(3) For 2022 and 2021, other postretirement benefits paid are net of $24 million and $9 million of Medicare subsidy receipts, respectively. |
For selection of the discount rate for U.S. plans, several sources of information are considered, including interest rate market indicators and the effective discount rate determined by use of a yield curve based on high-quality, noncallable bonds applied to the estimated cash outflows for benefit payments. For major non-U.S. plans, the discount rate is determined by using a spot yield curve of high-quality, local-currency-denominated bonds at an average maturity approximating that of the liabilities.
The measurement of the accumulated postretirement benefit obligation assumes a health care cost trend rate of 4.54.0 percent in 20222024 and subsequent years.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement |
| | U.S. | | Non-U.S. | | Benefits |
| | 2020 | | 2019 | | 2020 | | 2019 | | 2020 | | 2019 |
| | (millions of dollars) |
| Change in plan assets | | | | | | | | | | | |
| Fair value at January 1 | 13,636 | | | 11,134 | | | 22,916 | | | 19,486 | | | 425 | | | 386 | |
| Actual return on plan assets | 2,269 | | | 2,521 | | | 2,795 | | | 3,210 | | | 42 | | | 54 | |
| Foreign exchange rate changes | — | | | — | | | 1,011 | | | 513 | | | — | | | — | |
| Company contribution | 1,004 | | | 1,022 | | | 597 | | | 602 | | | 37 | | | 41 | |
Benefits paid (1) | (1,609) | | | (1,041) | | | (992) | | | (883) | | | (58) | | | (56) | |
| Other | — | | | — | | | (111) | | | (12) | | | — | | | — | |
| Fair value at December 31 | 15,300 | | | 13,636 | | | 26,216 | | | 22,916 | | | 446 | | | 425 | |
(1)Benefit payments for funded plans.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | | | | | | | | | | |
| (millions of dollars) | U.S. | | Non-U.S. | | |
| 2022 | | 2021 | | 2022 | | 2021 | | 2022 | | 2021 |
| Change in plan assets | | | | | | | | | | | |
| Fair value at January 1 | 13,266 | | | 15,300 | | | 24,880 | | | 26,216 | | | 440 | | | 446 | |
| Actual return on plan assets | (3,265) | | | 479 | | | (5,287) | | | 571 | | | (66) | | | 20 | |
| Foreign exchange rate changes | — | | | — | | | (2,012) | | | (605) | | | — | | | — | |
| Company contribution | 3,596 | | | 794 | | | 655 | | | 293 | | | 27 | | | 28 | |
Benefits paid (1) | (2,608) | | | (3,307) | | | (1,070) | | | (1,167) | | | (53) | | | (54) | |
| Other | — | | | — | | | (409) | | | (428) | | | — | | | — | |
| Fair value at December 31 | 10,989 | | | 13,266 | | | 16,757 | | | 24,880 | | | 348 | | | 440 | |
| | | | | | | | | | | |
(1) Benefit payments for funded plans. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The funding levels of all qualified pension plans are in compliance with standards set by applicable law or regulation. As shown in the table below, certain smaller U.S. pension plans and a number of non-U.S. pension plans are not funded because local applicable tax rules and regulatory practices do not encourage funding of these plans. All defined benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.
| | | | Pension Benefits | | Pension Benefits |
| | | U.S. | | Non-U.S. | | |
| | 2020 | | 2019 | | 2020 | | 2019 | |
| | (millions of dollars) | |
| (millions of dollars) | | (millions of dollars) | U.S. | | Non-U.S. |
| 2022 | | 2021 | | 2022 | | 2021 |
| Assets in excess of/(less than) benefit obligation | Assets in excess of/(less than) benefit obligation | | | | | | | | Assets in excess of/(less than) benefit obligation | | | | |
| Balance at December 31 | Balance at December 31 | | | | | | | | Balance at December 31 | | | | | | | |
| Funded plans | Funded plans | (4,156) | | | (4,656) | | | (1,223) | | | (1,728) | | Funded plans | (23) | | | (3,570) | | | 1,019 | | | 554 | |
| Unfunded plans | Unfunded plans | (2,206) | | | (2,667) | | | (6,187) | | | (5,274) | | Unfunded plans | (1,338) | | | (1,675) | | | (3,604) | | | (5,166) | |
| Total | Total | (6,362) | | | (7,323) | | | (7,410) | | | (7,002) | | Total | (1,361) | | | (5,245) | | | (2,585) | | | (4,612) | |
The authoritative guidance for defined benefit pension and other postretirement plans requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | U.S. | | Non-U.S. | |
| | 2020 | | 2019 | | 2020 | | 2019 | | 2020 | | 2019 |
| | (millions of dollars) |
| Assets in excess of/(less than) benefit obligation | | | | | | | | | | | |
Balance at December 31 (1) | (6,362) | | | (7,323) | | | (7,410) | | | (7,002) | | | (7,689) | | | (7,688) | |
| | | | | | | | | | | |
Amounts recorded in the consolidated balance sheet consist of: | | | | | | | | | | | |
| Other assets | — | | | — | | | 1,931 | | | 1,151 | | | — | | | — | |
| Current liabilities | (377) | | | (242) | | | (273) | | | (267) | | | (327) | | | (351) | |
| Postretirement benefits reserves | (5,985) | | | (7,081) | | | (9,068) | | | (7,886) | | | (7,362) | | | (7,337) | |
| Total recorded | (6,362) | | | (7,323) | | | (7,410) | | | (7,002) | | | (7,689) | | | (7,688) | |
| | | | | | | | | | | |
Amounts recorded in accumulated other comprehensive income consist of: | | | | | | | | | | | |
| Net actuarial loss/(gain) | 3,102 | | | 3,971 | | | 5,904 | | | 5,662 | | | 1,164 | | | 1,339 | |
| Prior service cost | (275) | | | 1 | | | 208 | | | 360 | | | (274) | | | (315) | |
Total recorded in accumulated other comprehensive income | 2,827 | | | 3,972 | | | 6,112 | | | 6,022 | | | 890 | | | 1,024 | |
(1) Fair value of assets less benefit obligation shown on the preceding page. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | | | | | | | | | | |
| (millions of dollars) | U.S. | | Non-U.S. | | | | |
| 2022 | | 2021 | | 2022 | | 2021 | | 2022 | | 2021 |
| Assets in excess of/(less than) benefit obligation | | | | | | | | | | | |
Balance at December 31 (1) | (1,361) | | | (5,245) | | | (2,585) | | | (4,612) | | | (4,863) | | | (6,825) | |
| | | | | | | | | | | |
| Amounts recorded in the consolidated balance sheet consist of: | | | | | | | | | | | |
| Other assets | — | | | — | | | 1,962 | | | 2,544 | | | — | | | — | |
| Current liabilities | (168) | | | (206) | | | (254) | | | (267) | | | (304) | | | (323) | |
| Postretirement benefits reserves | (1,193) | | | (5,039) | | | (4,293) | | | (6,889) | | | (4,559) | | | (6,502) | |
| Total recorded | (1,361) | | | (5,245) | | | (2,585) | | | (4,612) | | | (4,863) | | | (6,825) | |
| | | | | | | | | | | |
| Amounts recorded in accumulated other comprehensive income consist of: | | | | | | | | | | | |
| Net actuarial loss/(gain) | 897 | | | 1,865 | | | 846 | | | 2,841 | | | (1,726) | | | 197 | |
| Prior service cost | (295) | | | (324) | | | 278 | | | 262 | | | (190) | | | (232) | |
| Total recorded in accumulated other comprehensive income | 602 | | | 1,541 | | | 1,124 | | | 3,103 | | | (1,916) | | | (35) | |
| | | | | | | | | | | |
(1) Fair value of assets less benefit obligation shown on the preceding page. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The long-term expected rate of return on funded assets shown below is established for each benefit plan by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class.
| | | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement
Benefits |
| | | U.S. | | Non-U.S. | | | | | |
| | 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 | |
| (millions of dollars, except where stated otherwise) | | (millions of dollars, except where stated otherwise) | U.S. | | Non-U.S. | |
| 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31 | Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31 | (percent) | Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31 | | | | | | |
| Discount rate | 3.50 | | | 4.40 | | | 3.80 | | | 2.30 | | | 3.00 | | | 2.80 | | | 3.50 | | | 4.40 | | | 3.80 | | |
| Long-term rate of return on funded assets | 5.30 | | | 5.30 | | | 6.00 | | | 4.10 | | | 4.10 | | | 4.70 | | | 4.60 | | | 4.60 | | | 6.00 | | |
| Long-term rate of compensation increase | 5.75 | | | 5.75 | | | 5.75 | | | 4.80 | | | 4.30 | | | 4.30 | | | 5.75 | | | 5.75 | | | 5.75 | | |
Discount rate (percent) | | Discount rate (percent) | 3.00 | | | 2.80 | | | 3.50 | | | 2.20 | | | 1.60 | | | 2.30 | | | 3.10 | | | 2.80 | | | 3.50 | |
Long-term rate of return on funded assets (percent) | | Long-term rate of return on funded assets (percent) | 4.60 | | | 5.30 | | | 5.30 | | | 3.50 | | | 4.10 | | | 4.10 | | | 3.80 | | | 4.60 | | | 4.60 | |
Long-term rate of compensation increase (percent) | | Long-term rate of compensation increase (percent) | 4.50 | | | 5.50 | | | 5.75 | | | 4.20 | | | 4.20 | | | 4.80 | | | 4.50 | | | 5.50 | | | 5.75 | |
| | Components of net periodic benefit cost | Components of net periodic benefit cost | (millions of dollars) | Components of net periodic benefit cost | | | | | | |
| Service cost | Service cost | 965 | | | 757 | | | 819 | | | 707 | | | 551 | | | 608 | | | 181 | | | 139 | | | 152 | | Service cost | 712 | | | 919 | | | 965 | | | 570 | | | 774 | | | 707 | | | 138 | | | 188 | | | 181 | |
| Interest cost | Interest cost | 708 | | | 766 | | | 721 | | | 657 | | | 763 | | | 754 | | | 277 | | | 315 | | | 301 | | Interest cost | 518 | | | 558 | | | 708 | | | 614 | | | 526 | | | 657 | | | 216 | | | 221 | | | 277 | |
| Expected return on plan assets | Expected return on plan assets | (703) | | | (568) | | | (727) | | | (897) | | | (777) | | | (951) | | | (18) | | | (15) | | | (23) | | Expected return on plan assets | (560) | | | (722) | | | (703) | | | (815) | | | (1,031) | | | (897) | | | (14) | | | (19) | | | (18) | |
| Amortization of actuarial loss/(gain) | Amortization of actuarial loss/(gain) | 310 | | | 305 | | | 362 | | | 416 | | | 306 | | | 409 | | | 95 | | | 55 | | | 116 | | Amortization of actuarial loss/(gain) | 156 | | | 244 | | | 310 | | | 180 | | | 420 | | | 416 | | | 6 | | | 76 | | | 95 | |
| Amortization of prior service cost | Amortization of prior service cost | 5 | | | 5 | | | 5 | | | 68 | | | 56 | | | 46 | | | (42) | | | (42) | | | (40) | | Amortization of prior service cost | (29) | | | (23) | | | 5 | | | 43 | | | 57 | | | 68 | | | (42) | | | (42) | | | (42) | |
| Net pension enhancement and curtailment/settlement cost | Net pension enhancement and curtailment/settlement cost | 280 | | | 164 | | | 268 | | | 49 | | | (98) | | | 44 | | | — | | | — | | | — | | Net pension enhancement and curtailment/settlement cost | 205 | | | 489 | | | 280 | | | 4 | | | 32 | | | 49 | | | — | | | — | | | — | |
| Net periodic benefit cost | Net periodic benefit cost | 1,565 | | | 1,429 | | | 1,448 | | | 1,000 | | | 801 | | | 910 | | | 493 | | | 452 | | | 506 | | Net periodic benefit cost | 1,002 | | | 1,465 | | | 1,565 | | | 596 | | | 778 | | | 1,000 | | | 304 | | | 424 | | | 493 | |
| | Changes in amounts recorded in accumulated other comprehensive income: | Changes in amounts recorded in accumulated other comprehensive income: | | Changes in amounts recorded in accumulated other comprehensive income: | | | | | | |
| Net actuarial loss/(gain) | Net actuarial loss/(gain) | (279) | | | 609 | | | 479 | | | 446 | | | 1,268 | | | (66) | | | (92) | | | 517 | | | (594) | | Net actuarial loss/(gain) | (607) | | | (504) | | | (279) | | | (1,641) | | | (2,361) | | | 446 | | | (1,910) | | | (891) | | | (92) | |
| Amortization of actuarial (loss)/gain | Amortization of actuarial (loss)/gain | (590) | | | (469) | | | (630) | | | (442) | | | (208) | | | (453) | | | (95) | | | (55) | | | (116) | | Amortization of actuarial (loss)/gain | (361) | | | (733) | | | (590) | | | (183) | | | (430) | | | (442) | | | (6) | | | (76) | | | (95) | |
| Prior service cost/(credit) | Prior service cost/(credit) | (271) | | | 0 | | | 0 | | | (82) | | | 379 | | | 98 | | | 0 | | | 0 | | | 0 | | Prior service cost/(credit) | — | | | (72) | | | (271) | | | 84 | | | 92 | | | (82) | | | — | | | — | | | — | |
| Amortization of prior service (cost)/credit | Amortization of prior service (cost)/credit | (5) | | | (5) | | | (5) | | | (68) | | | (56) | | | (46) | | | 42 | | | 42 | | | 40 | | Amortization of prior service (cost)/credit | 29 | | | 23 | | | (5) | | | (40) | | | (55) | | | (68) | | | 42 | | | 42 | | | 42 | |
| Foreign exchange rate changes | Foreign exchange rate changes | — | | | — | | | — | | | 236 | | | 19 | | | (356) | | | 11 | | | 0 | | | (8) | | Foreign exchange rate changes | — | | | — | | | — | | | (199) | | | (255) | | | 236 | | | (7) | | | — | | | 11 | |
| Total recorded in other comprehensive income | Total recorded in other comprehensive income | (1,145) | | | 135 | | | (156) | | | 90 | | | 1,402 | | | (823) | | | (134) | | | 504 | | | (678) | | Total recorded in other comprehensive income | (939) | | | (1,286) | | | (1,145) | | | (1,979) | | | (3,009) | | | 90 | | | (1,881) | | | (925) | | | (134) | |
| Total recorded in net periodic benefit cost and other comprehensive income, before tax | Total recorded in net periodic benefit cost and other comprehensive income, before tax | 420 | | | 1,564 | | | 1,292 | | | 1,090 | | | 2,203 | | | 87 | | | 359 | | | 956 | | | (172) | | Total recorded in net periodic benefit cost and other comprehensive income, before tax | 63 | | | 179 | | | 420 | | | (1,383) | | | (2,231) | | | 1,090 | | | (1,577) | | | (501) | | | 359 | |
Costs for defined contribution plans were $365 million, $177 million and $358 million $422 millionin 2022, 2021, and $391 million in 2020, 2019 and 2018, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A summary of the change in accumulated other comprehensive income is shown in the table below:
| | | | Total Pension and Other Postretirement Benefits | | Total Pension and Other Postretirement Benefits |
| | | 2020 | | 2019 | | 2018 | | |
(millions of dollars) | | (millions of dollars) | 2022 | | 2021 | | 2020 |
| | | (millions of dollars) | | | |
| (Charge)/credit to other comprehensive income, before tax | (Charge)/credit to other comprehensive income, before tax | | | | | | (Charge)/credit to other comprehensive income, before tax | | | | | |
| U.S. pension | U.S. pension | 1,145 | | | (135) | | | 156 | | U.S. pension | 939 | | | 1,286 | | | 1,145 | |
| Non-U.S. pension | Non-U.S. pension | (90) | | | (1,402) | | | 823 | | Non-U.S. pension | 1,979 | | | 3,009 | | | (90) | |
| Other postretirement benefits | Other postretirement benefits | 134 | | | (504) | | | 678 | | Other postretirement benefits | 1,881 | | | 925 | | | 134 | |
| Total (charge)/credit to other comprehensive income, before tax | Total (charge)/credit to other comprehensive income, before tax | 1,189 | | | (2,041) | | | 1,657 | | Total (charge)/credit to other comprehensive income, before tax | 4,799 | | | 5,220 | | | 1,189 | |
| (Charge)/credit to income tax (see Note 4) | (Charge)/credit to income tax (see Note 4) | (153) | | | 550 | | | (470) | | (Charge)/credit to income tax (see Note 4) | (1,236) | | | (1,287) | | | (153) | |
| (Charge)/credit to investment in equity companies | (Charge)/credit to investment in equity companies | (110) | | | (19) | | | 24 | | (Charge)/credit to investment in equity companies | 235 | | | 110 | | | (110) | |
| (Charge)/credit to other comprehensive income including noncontrolling interests, after tax | (Charge)/credit to other comprehensive income including noncontrolling interests, after tax | 926 | | | (1,510) | | | 1,211 | | (Charge)/credit to other comprehensive income including noncontrolling interests, after tax | 3,798 | | | 4,043 | | | 926 | |
| Charge/(credit) to equity of noncontrolling interests | Charge/(credit) to equity of noncontrolling interests | 30 | | | 146 | | | (114) | | Charge/(credit) to equity of noncontrolling interests | (212) | | | (217) | | | 30 | |
| (Charge)/credit to other comprehensive income attributable to ExxonMobil | (Charge)/credit to other comprehensive income attributable to ExxonMobil | 956 | | | (1,364) | | | 1,097 | | (Charge)/credit to other comprehensive income attributable to ExxonMobil | 3,586 | | | 3,826 | | | 956 | |
The Corporation’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in plan assets and liabilities, and broad diversification to reduce the risk of the portfolio. The benefit plan assets are primarily invested in passive global equity and local currency fixed income index funds to diversify risk while minimizing costs. The equity funds hold ExxonMobil stock only to the extent necessary to replicate the relevant equity index. The fixed income funds are largely invested in investment grade corporate and government debt securities.securities with interest rate sensitivity designed to approximate the interest rate sensitivity of plan liabilities.
StudiesTarget asset allocations for benefit plans are reviewed periodically conducted to establish the preferred target asset allocation percentages.and set based on considerations such as risk, diversification, liquidity, and funding level. The target asset allocationallocations for the U.S.major benefit plans and the major non-U.S. plans isrange from 10 to 30 percent in equity securities and 70 percent debtthe remainder in fixed income securities. The equity for the U.S. and certain non-U.S. plans include a small allocationallocations to private equity partnerships that primarily focus on early-stage venture capital of 4 percent and 2 percent, respectively.less than 5 percent.
The fair value measurement levels are accounting terms that refer to different methods of valuing assets. The terms do not represent the relative risk or credit quality of an investment.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The 20202022 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below:
| | | | U.S. Pension | | Non- U.S. Pension | | | U.S. Pension | | Non-U.S. Pension |
| | | Fair Value Measurement at December 31, 2020, Using: | | | Fair Value Measurement at December 31, 2020, Using: | | | | | | |
| | Level 1 | | Level 2 | | | Level 3 | | Net Asset Value | | Total | | Level 1 | | | Level 2 | | | Level 3 | | Net Asset Value | | Total | |
| (millions of dollars) | | (millions of dollars) | | Fair Value Measurement at December 31, 2022, Using: | | | Fair Value Measurement at December 31, 2022, Using: | |
| | Level 1 | | Level 2 | | | Level 3 | | Net Asset Value | | Total | | Level 1 | | | Level 2 | | | Level 3 | | Net Asset Value | | Total |
| | | (millions of dollars) | | | |
| Asset category: | Asset category: | | | | | | | | | | | | | | | | | | Asset category: | | | | | | | | | | | | | | | | | | |
| Equity securities | Equity securities | | | | | | | | | | | | | | | | | | Equity securities | | | | | | | | | | | | | | | | | | |
| U.S. | U.S. | — | | | — | | | | — | | | 2,323 | | | 2,323 | | | — | | | | — | | | | — | | | 4,177 | | | 4,177 | | U.S. | | — | | | — | | | | — | | | 1,726 | | | 1,726 | | | — | | | | — | | | | — | | | 2,318 | | | 2,318 | |
| Non-U.S. | Non-U.S. | — | | | — | | | | — | | | 1,703 | | | 1,703 | | | 89 | | (1) | | — | | | | — | | | 3,285 | | | 3,374 | | Non-U.S. | | — | | | — | | | | — | | | 1,131 | | | 1,131 | | | 61 | | (1) | | — | | | | — | | | 1,676 | | | 1,737 | |
| Private equity | Private equity | — | | | — | | | | — | | | 548 | | | 548 | | | — | | | | — | | | | — | | | 530 | | | 530 | | Private equity | | — | | | — | | | | — | | | 506 | | | 506 | | | — | | | | — | | | | — | | | 472 | | | 472 | |
| Debt securities | Debt securities | | | | | | | | Debt securities | | | | | | | | |
| Corporate | Corporate | — | | | 5,146 | | (2) | | — | | | 1 | | | 5,147 | | | — | | | | 138 | | (2) | | — | | | 5,212 | | | 5,350 | | Corporate | | — | | | 4,582 | | (2) | | — | | | 1 | | | 4,583 | | | — | | | | 63 | | (2) | | — | | | 4,199 | | | 4,262 | |
| Government | Government | — | | | 5,261 | | (2) | | — | | | 2 | | | 5,263 | | | 250 | | (3) | | 116 | | (2) | | — | | | 11,993 | | | 12,359 | | Government | | — | | | 2,869 | | (2) | | — | | | 2 | | | 2,871 | | | 202 | | (3) | | 144 | | (2) | | — | | | 7,189 | | | 7,535 | |
| Asset-backed | Asset-backed | — | | | — | | | | — | | | 1 | | | 1 | | | — | | | | 24 | | (2) | | — | | | 239 | | | 263 | | Asset-backed | | — | | | — | | | | — | | | 1 | | | 1 | | | — | | | | 22 | | (2) | | — | | | 185 | | | 207 | |
| Cash | Cash | — | | | — | | | | — | | | 308 | | | 308 | | | 69 | | | | 21 | | (4) | | — | | | 50 | | | 140 | | Cash | | — | | | — | | | | — | | | 168 | | | 168 | | | 88 | | | | 40 | | (4) | | — | | | 77 | | | 205 | |
| Total at fair value | Total at fair value | — | | | 10,407 | | | | — | | | 4,886 | | | 15,293 | | | 408 | | | | 299 | | | | — | | | 25,486 | | | 26,193 | | Total at fair value | | — | | | 7,451 | | | | — | | | 3,535 | | | 10,986 | | | 351 | | | | 269 | | | | — | | | 16,116 | | | 16,736 | |
| Insurance contracts at contract value | Insurance contracts at contract value | | | | | | 7 | | | | | | | | | 23 | | Insurance contracts at contract value | | | | | | 3 | | | | | | | 21 | |
| Total plan assets | Total plan assets | | | | | 15,300 | | | | | | | 26,216 | | Total plan assets | | | | | | 10,989 | | | | | | | 16,757 | |
| (1) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges. | | (1) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges. |
(2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions. | | (2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions. |
(3) For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices. | | (3) For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices. |
(4) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input. | | (4) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input. |
(1)For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.
(2)For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.
(3)For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.
(4)For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Other Postretirement |
| | Fair Value Measurement at December 31, 2020, Using: | | |
| | Level 1 | | Level 2 | | | Level 3 | | Net Asset Value | | Total |
| | (millions of dollars) |
| Asset category: | | | | | | | | | | |
| Equity securities | | | | | | | | | | |
| U.S. | 88 | | (1) | — | | | | — | | | 0 | | | 88 | |
| Non-U.S. | 48 | | (1) | — | | | | — | | | 0 | | | 48 | |
| Debt securities | | | | | | | | | | |
| Corporate | — | | | 103 | | (2) | | — | | | — | | | 103 | |
| Government | — | | | 204 | | (2) | | — | | | — | | | 204 | |
| Asset-backed | — | | | — | | | | — | | | — | | | — | |
| Cash | — | | | — | | | | — | | | 3 | | | 3 | |
| Total at fair value | 136 | | | 307 | | | | — | | | 3 | | | 446 | |
(1)For equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.
(2)For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Other Postretirement |
| | | | | | | | | | |
| (millions of dollars) | Fair Value Measurement at December 31, 2022, Using: | | |
| Level 1 | | Level 2 | | | Level 3 | | Net Asset Value | | Total |
| | | | | | | | | | | |
| Asset category: | | | | | | | | | | |
| Equity securities | | | | | | | | | | |
| U.S. | 70 | | (1) | — | | | | — | | | — | | | 70 | |
| Non-U.S. | 37 | | (1) | — | | | | — | | | — | | | 37 | |
| Debt securities | | | | | | | | | | |
| Corporate | — | | | 59 | | (2) | | — | | | — | | | 59 | |
| Government | — | | | 175 | | (2) | | — | | | — | | | 175 | |
| Asset-backed | — | | | 4 | | (2) | | — | | | — | | | 4 | |
| Cash | — | | | 3 | | | | — | | | — | | | 3 | |
| Total at fair value | 107 | | | 241 | | | | — | | | — | | | 348 | |
| | | | | | | | | | |
(1) For equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges. |
(2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The 20192021 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below:
| | | | U.S. Pension | Non-U.S. Pension | | | U.S. Pension | | Non-U.S. Pension |
| | | Fair Value Measurement at December 31, 2019, Using: | | Fair Value Measurement at December 31, 2019, Using: | | | | | |
| | Level 1 | | Level 2 | | | Level 3 | | Net Asset Value | | Total | | Level 1 | | | Level 2 | | | Level 3 | | Net Asset Value | | Total | |
| (millions of dollars) | | (millions of dollars) | | Fair Value Measurement at December 31, 2021, Using: | | | Fair Value Measurement at December 31, 2021, Using: | |
| | Level 1 | | Level 2 | | | Level 3 | | Net Asset Value | | Total | | Level 1 | | | Level 2 | | | Level 3 | | Net Asset Value | | Total |
| | | (millions of dollars) | | |
| Asset category: | Asset category: | | | | | | | | | | | | | | | | | | Asset category: | | | | | | | | | | | | | | | | | | |
| Equity securities | Equity securities | | | | | | | | | | | | | | | | | | Equity securities | | | | | | | | | | | | | | | | | | |
| U.S. | U.S. | — | | | — | | | | — | | | 1,960 | | | 1,960 | | | — | | | | — | | | | — | | | 3,436 | | | 3,436 | | U.S. | | — | | | — | | | | — | | | 1,956 | | | 1,956 | | | — | | | | — | | | | — | | | 3,416 | | | 3,416 | |
| Non-U.S. | Non-U.S. | — | | | — | | | | — | | | 1,656 | | | 1,656 | | | 70 | | (1) | | — | | | | — | | | 3,015 | | | 3,085 | | Non-U.S. | | — | | | — | | | | — | | | 1,290 | | | 1,290 | | | 76 | | (1) | | — | | | | — | | | 2,424 | | | 2,500 | |
| Private equity | Private equity | — | | | — | | | | — | | | 499 | | | 499 | | | — | | | | — | | | | — | | | 489 | | | 489 | | Private equity | | — | | | — | | | | — | | | 661 | | | 661 | | | — | | | | — | | | | — | | | 627 | | | 627 | |
| Debt securities | Debt securities | | | | | | | | Debt securities | | | | | | | |
| Corporate | Corporate | — | | | 4,932 | | (2) | | — | | | 1 | | | 4,933 | | | — | | | 129 | | (2) | | — | | | 4,486 | | | 4,615 | | Corporate | | — | | | 5,242 | | (2) | | — | | | 1 | | | 5,243 | | | — | | | 119 | | (2) | | — | | | 5,831 | | | 5,950 | |
| Government | Government | — | | | 4,470 | | (2) | | — | | | 2 | | | 4,472 | | | 280 | | (3) | | 139 | | (2) | | — | | | 10,511 | | | 10,930 | | Government | | — | | | 3,945 | | (2) | | — | | | 2 | | | 3,947 | | | 209 | | (3) | | 97 | | (2) | | — | | | 11,620 | | | 11,926 | |
| Asset-backed | Asset-backed | — | | | — | | | | — | | | 1 | | | 1 | | | — | | | | 21 | | (2) | | — | | | 212 | | | 233 | | Asset-backed | | — | | | — | | | | — | | | 1 | | | 1 | | | — | | | | 25 | | (2) | | — | | | 191 | | | 216 | |
| Cash | Cash | — | | | — | | | | — | | | 107 | | | 107 | | | 33 | | | | 12 | | (4) | | — | | | 61 | | | 106 | | Cash | | — | | | — | | | | — | | | 162 | | | 162 | | | 62 | | | | 53 | | (4) | | — | | | 108 | | | 223 | |
| Total at fair value | Total at fair value | — | | | 9,402 | | | | — | | | 4,226 | | | 13,628 | | | 383 | | | | 301 | | | | — | | | 22,210 | | | 22,894 | | Total at fair value | | — | | | 9,187 | | | | — | | | 4,073 | | | 13,260 | | | 347 | | | | 294 | | | | — | | | 24,217 | | | 24,858 | |
| Insurance contracts at contract value | Insurance contracts at contract value | | | | | | 8 | | | | | | | | 22 | | Insurance contracts at contract value | | | | | | | 6 | | | | | | | 22 | |
| Total plan assets | Total plan assets | | | | | | 13,636 | | | | | | | 22,916 | | Total plan assets | | | | | | | 13,266 | | | | | | | 24,880 | |
| (1) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges. | | (1) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges. |
(2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions. | | (2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions. |
(3) For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices. | | (3) For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices. |
(4) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input. | | (4) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input. |
(1)For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.
(2)For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.
(3)For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.
(4)For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Other Postretirement |
| | Fair Value Measurement at December 31, 2019, Using: | | |
| | Level 1 | | Level 2 | | | Level 3 | | Net Asset Value | | Total |
| | (millions of dollars) |
| Asset category: | | | | | | | | | | |
| Equity securities | | | | | | | | | | |
| U.S. | — | | | — | | | | — | | | 81 | | | 81 | |
| Non-U.S. | — | | | — | | | | — | | | 49 | | | 49 | |
| Debt securities | | | | | | | | | | |
| Corporate | — | | | 92 | | (1) | | — | | | — | | | 92 | |
| Government | — | | | 200 | | (1) | | — | | | — | | | 200 | |
| Asset-backed | — | | | — | | | | — | | | — | | | — | |
| Cash | — | | | — | | | | — | | | 3 | | | 3 | |
| Total at fair value | — | | | 292 | | | | — | | | 133 | | | 425 | |
(1)For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Other Postretirement |
| | | | | | | | | | |
| (millions of dollars) | Fair Value Measurement at December 31, 2021, Using: | | |
| Level 1 | | Level 2 | | | Level 3 | | Net Asset Value | | Total |
| | | | | | | | | | | |
| Asset category: | | | | | | | | | | |
| Equity securities | | | | | | | | | | |
| U.S. | 91 | | (1) | — | | | | — | | | — | | | 91 | |
| Non-U.S. | 45 | | (1) | — | | | | — | | | — | | | 45 | |
| Debt securities | | | | | | | | | | |
| Corporate | — | | | 95 | | (2) | | — | | | — | | | 95 | |
| Government | — | | | 206 | | (2) | | — | | | — | | | 206 | |
| Asset-backed | — | | | — | | | | — | | | — | | | — | |
| Cash | — | | | 3 | | | | — | | | — | | | 3 | |
| Total at fair value | 136 | | | 304 | | | | — | | | — | | | 440 | |
| | | | | | | | | | |
(1) For equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges. |
(2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A summary of pension plans with an accumulated benefit obligation and projected benefit obligation in excess of plan assets is shown in the table below:
| | | | Pension Benefits | | Pension Benefits |
| | | U.S. | | Non-U.S. | | |
| (millions of dollars) | | (millions of dollars) | U.S. | | Non-U.S. |
| 2022 | | 2021 | | 2022 | | 2021 |
| | | 2020 | | 2019 | | 2020 | | 2019 | | | | | |
| | (millions of dollars) | |
For funded pension plans with an accumulated benefit obligation | | | | | | | |
| in excess of plan assets: | | | | | | | | |
For funded pension plans with an accumulated benefit obligation in excess of plan assets: | | For funded pension plans with an accumulated benefit obligation in excess of plan assets: | | | | | | | |
| Accumulated benefit obligation | Accumulated benefit obligation | 16,129 | | | 14,940 | | | 4,602 | | | 3,026 | | Accumulated benefit obligation | — | | | 14,511 | | | 1,098 | | | 3,108 | |
| Fair value of plan assets | Fair value of plan assets | 15,300 | | | 13,636 | | | 2,652 | | | 1,381 | | Fair value of plan assets | — | | | 13,266 | | | 400 | | | 1,711 | |
| For funded pension plans with a projected benefit obligation in excess of plan assets: | For funded pension plans with a projected benefit obligation in excess of plan assets: | | For funded pension plans with a projected benefit obligation in excess of plan assets: | | | | |
| Projected benefit obligation | Projected benefit obligation | 19,456 | | | 18,292 | | | 13,836 | | | 12,496 | | Projected benefit obligation | 11,012 | | | 16,836 | | | 1,956 | | | 4,840 | |
| Fair value of plan assets | Fair value of plan assets | 15,300 | | | 13,636 | | | 10,681 | | | 9,616 | | Fair value of plan assets | 10,989 | | | 13,266 | | | 1,012 | | | 2,849 | |
| For unfunded pension plans: | For unfunded pension plans: | | For unfunded pension plans: | | | | |
| Projected benefit obligation | Projected benefit obligation | 2,206 | | | 2,667 | | | 6,187 | | | 5,274 | | Projected benefit obligation | 1,338 | | | 1,675 | | | 3,604 | | | 5,166 | |
| Accumulated benefit obligation | Accumulated benefit obligation | 1,373 | | | 1,447 | | | 5,469 | | | 4,629 | | Accumulated benefit obligation | 1,045 | | | 1,270 | | | 3,261 | | | 4,685 | |
All other postretirement benefit plans are unfunded or underfunded.
| | | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits |
| | | U.S. | | Non-U.S. | | Gross | | Medicare Subsidy Receipt | | | | |
| (millions of dollars) | | (millions of dollars) | U.S. | | Non-U.S. | | Gross | | Medicare Subsidy Receipt |
| | | (millions of dollars) | | |
| Contributions expected in 2021 | 865 | | | 395 | | | — | | | — | | |
| Contributions expected in 2023 | | Contributions expected in 2023 | — | | | 570 | | | — | | | — | |
| Benefit payments expected in: | Benefit payments expected in: | | Benefit payments expected in: | |
| 2021 | 2,434 | | | 1,310 | | | 424 | | | 22 | | |
| 2022 | 1,079 | | | 1,193 | | | 426 | | | 23 | | |
| 2023 | 2023 | 1,105 | | | 1,214 | | | 420 | | | 25 | | 2023 | 956 | | | 1,149 | | | 399 | | | 21 | |
| 2024 | 2024 | 1,124 | | | 1,240 | | | 418 | | | 26 | | 2024 | 963 | | | 1,140 | | | 395 | | | 22 | |
| 2025 | 2025 | 1,142 | | | 1,186 | | | 415 | | | 27 | | 2025 | 985 | | | 1,123 | | | 391 | | | 23 | |
| 2026 - 2030 | 5,971 | | | 6,274 | | | 2,058 | | | 143 | | |
| 2026 | | 2026 | 1,009 | | | 1,109 | | | 385 | | | 24 | |
| 2027 | | 2027 | 1,024 | | | 1,154 | | | 382 | | | 24 | |
| 2028 - 2032 | | 2028 - 2032 | 5,430 | | | 5,978 | | | 1,930 | | | 128 | |
18. Disclosures about Segments and Related Information
The Upstream, DownstreamEnergy Products, Chemical Products, and ChemicalSpecialty Products functions best define the operating segments of the business that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment. The Upstream segment is organized and operates to explore for and produce crude oil and natural gas. The Downstream segment isEnergy Products, Chemical Products, and Specialty Products segments are organized and operatesoperate to manufacture and sell petroleum products. The products and petrochemicals.
•Energy Products: Fuels, aromatics, and catalysts and licensing
•Chemical segment is organizedProducts: Olefins, polyolefins, and operates to manufactureintermediates
•Specialty Products: Finished lubricants, basestocks and sell petrochemicals. These segments are broadly understood across the petroleumwaxes, synthetics, and petrochemical industries.elastomers and resins
These functions have been defined as the operating segments of the Corporation because they are the segments (1) that engage in business activities from which revenues are recognized and expenses are incurred; (2) whose operating results are regularly reviewed by the Corporation’s chief operating decision maker to make decisions about resources to be allocated to the segment and to assess its performance; and (3) for which discrete financial information is available.
Earnings after income tax include transfers at estimated market prices.
In the Corporate and financing segment,Financing, interest revenue relates to interest earned on cash deposits and marketable securities. Interest expense includes non-debt-related interest expense of $117 million in 2022, $103 million in 2021, and $148 million in 2020, $105 million in 2019 and $84 million in 2018.2020.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Upstream | | Downstream | | Chemical | | Corporate and | | Corporate |
| | U.S. | | Non-U.S. | | U.S. | | Non-U.S. | | U.S. | | Non-U.S. | | Financing | | Total |
| | (millions of dollars) |
| As of December 31, 2020 | | | | | | | | | | | | | | | |
| Earnings (Loss) after income tax | (19,385) | | | (645) | | | (852) | | | (225) | | | 1,277 | | | 686 | | | (3,296) | | | (22,440) | |
Effect of asset impairments - noncash | (17,138) | | | (2,287) | | | (15) | | | (609) | | | (100) | | | (69) | | | (35) | | | (20,253) | |
| Earnings of equity companies included above | (559) | | | 2,101 | | | 134 | | | (190) | | | (21) | | | 651 | | | (384) | | | 1,732 | |
| Sales and other operating revenue | 5,876 | | | 8,673 | | | 48,256 | | | 92,640 | | | 8,529 | | | 14,562 | | | 38 | | | 178,574 | |
| Intersegment revenue | 8,508 | | | 19,642 | | | 12,258 | | | 15,162 | | | 6,099 | | | 3,881 | | | 221 | | | — | |
| Depreciation and depletion expense | 28,627 | | | 12,723 | | | 716 | | | 1,672 | | | 685 | | | 694 | | | 892 | | | 46,009 | |
| Interest revenue | — | | | — | | | — | | | — | | | — | | | — | | | 49 | | | 49 | |
| Interest expense | 52 | | | 93 | | | 1 | | | 21 | | | — | | | 0 | | | 991 | | | 1,158 | |
| Income tax expense (benefit) | (5,958) | | | 742 | | | (324) | | | 393 | | | 440 | | | 272 | | | (1,197) | | | (5,632) | |
| Additions to property, plant and equipment | 5,726 | | | 4,418 | | | 2,983 | | | 1,731 | | | 1,221 | | | 592 | | | 671 | | | 17,342 | |
| Investments in equity companies | 4,792 | | | 18,135 | | | 352 | | | 879 | | | 2,543 | | | 3,514 | | | (443) | | | 29,772 | |
| Total assets | 71,287 | | | 144,730 | | | 23,754 | | | 34,848 | | | 17,839 | | | 20,220 | | | 20,072 | | | 332,750 | |
| | | | | | | | | | | | | | | |
| As of December 31, 2019 | | | | | | | | | | | | | | | |
| Earnings after income tax | 536 | | | 13,906 | | | 1,717 | | | 606 | | | 206 | | | 386 | | | (3,017) | | | 14,340 | |
| Earnings of equity companies included above | 282 | | | 4,534 | | | 196 | | | 19 | | | (4) | | | 818 | | | (404) | | | 5,441 | |
| Sales and other operating revenue | 9,364 | | | 13,779 | | | 70,523 | | | 134,460 | | | 9,723 | | | 17,693 | | | 41 | | | 255,583 | |
| Intersegment revenue | 10,893 | | | 30,864 | | | 22,416 | | | 24,775 | | | 7,864 | | | 5,905 | | | 224 | | | — | |
| Depreciation and depletion expense | 6,162 | | | 9,305 | | | 674 | | | 832 | | | 555 | | | 621 | | | 849 | | | 18,998 | |
| Interest revenue | — | | | — | | | — | | | — | | | — | | | — | | | 84 | | | 84 | |
| Interest expense | 54 | | | 34 | | | 1 | | | 9 | | | — | | | 1 | | | 731 | | | 830 | |
| Income tax expense (benefit) | (151) | | | 5,509 | | | 465 | | | 361 | | | 58 | | | 305 | | | (1,265) | | | 5,282 | |
| Additions to property, plant and equipment | 10,404 | | | 7,347 | | | 2,685 | | | 1,777 | | | 1,344 | | | 589 | | | 758 | | | 24,904 | |
| Investments in equity companies | 5,313 | | | 17,736 | | | 319 | | | 1,062 | | | 1,835 | | | 3,335 | | | (309) | | | 29,291 | |
| Total assets | 95,750 | | | 151,181 | | | 23,442 | | | 37,133 | | | 16,544 | | | 20,376 | | | 18,171 | | | 362,597 | |
| | | | | | | | | | | | | | | |
| As of December 31, 2018 | | | | | | | | | | | | | | | |
| Earnings after income tax | 1,739 | | | 12,340 | | | 2,962 | | | 3,048 | | | 1,642 | | | 1,709 | | | (2,600) | | | 20,840 | |
| Earnings of equity companies included above | 608 | | | 5,816 | | | 156 | | | (6) | | | 48 | | | 1,113 | | | (380) | | | 7,355 | |
| Sales and other operating revenue | 10,359 | | | 15,158 | | | 74,327 | | | 147,007 | | | 12,239 | | | 20,204 | | | 38 | | | 279,332 | |
| Intersegment revenue | 8,683 | | | 29,659 | | | 21,954 | | | 29,888 | | | 9,044 | | | 7,217 | | | 205 | | | — | |
| Depreciation and depletion expense | 6,024 | | | 9,257 | | | 684 | | | 890 | | | 405 | | | 606 | | | 879 | | | 18,745 | |
| Interest revenue | — | | | — | | | — | | | — | | | — | | | — | | | 64 | | | 64 | |
| Interest expense | 77 | | | 31 | | | 2 | | | 12 | | | — | | | 1 | | | 643 | | | 766 | |
| Income tax expense (benefit) | 104 | | | 8,149 | | | 946 | | | 1,008 | | | 566 | | | 245 | | | (1,486) | | | 9,532 | |
| Additions to property, plant and equipment | 7,119 | | | 7,974 | | | 1,152 | | | 1,595 | | | 1,146 | | | 348 | | | 717 | | | 20,051 | |
| Investments in equity companies | 4,566 | | | 16,337 | | | 293 | | | 1,162 | | | 870 | | | 3,431 | | | (277) | | | 26,382 | |
| Total assets | 90,310 | | | 148,914 | | | 17,898 | | | 34,024 | | | 14,904 | | | 21,131 | | | 19,015 | | | 346,196 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (millions of dollars) | | Upstream | | Energy Products | | Chemical Products | | Specialty Products | | Corporate and Financing | | Corporate Total |
| U.S. | | Non-U.S. | | U.S. | | Non-U.S. | | U.S. | | Non-U.S. | | U.S. | | Non-U.S. | | |
| | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2022 | | | | | | | | | | | | | | | | | | | | |
| Earnings (loss) after income tax | | 11,728 | | | 24,751 | | | 8,340 | | | 6,626 | | | 2,328 | | | 1,215 | | | 1,190 | | | 1,225 | | | (1,663) | | | 55,740 | |
| Earnings of equity companies included above | | 411 | | | 10,133 | | | 126 | | | 322 | | | 91 | | | 771 | | | — | | | (23) | | | (368) | | | 11,463 | |
| Sales and other operating revenue | | 14,579 | | | 30,585 | | | 117,824 | | | 188,153 | | | 10,670 | | | 16,949 | | | 6,152 | | | 13,727 | | | 36 | | | 398,675 | |
| Intersegment revenue | | 25,658 | | | 46,076 | | | 29,001 | | | 36,894 | | | 9,081 | | | 5,201 | | | 2,587 | | | 825 | | | 241 | | | — | |
| Depreciation and depletion expense | | 5,791 | | | 14,013 | | | 741 | | | 1,246 | | | 542 | | | 446 | | | 95 | | | 193 | | | 973 | | | 24,040 | |
| Interest revenue | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 446 | | | 446 | |
| Interest expense | | 51 | | | 38 | | | 1 | | | 7 | | | — | | | 1 | | | — | | | 1 | | | 699 | | | 798 | |
| Income tax expense (benefit) | | 3,330 | | | 11,575 | | | 2,615 | | | 2,420 | | | 520 | | | 292 | | | 334 | | | 252 | | | (1,162) | | | 20,176 | |
| Additions to property, plant and equipment | | 5,940 | | | 6,441 | | | 1,141 | | | 964 | | | 1,026 | | | 1,692 | | | 37 | | | 200 | | | 897 | | | 18,338 | |
| Investments in equity companies | | 4,893 | | | 21,502 | | | 368 | | | 1,154 | | | 3,124 | | | 2,417 | | | — | | | 1,177 | | | (113) | | | 34,522 | |
| Total assets | | 66,695 | | | 139,764 | | | 31,729 | | | 41,836 | | | 17,342 | | | 15,875 | | | 2,839 | | | 8,316 | | | 44,671 | | | 369,067 | |
| | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2021 | | | | | | | | | | | | | | | | | | | | |
| Earnings (loss) after income tax | | 3,663 | | | 12,112 | | | 668 | | | (1,014) | | | 3,697 | | | 3,292 | | | 1,452 | | | 1,807 | | | (2,636) | | | 23,040 | |
| Earnings of equity companies included above | | 288 | | | 5,535 | | | 122 | | | 100 | | | (139) | | | 1,141 | | | — | | | (36) | | | (354) | | | 6,657 | |
| Sales and other operating revenue | | 8,883 | | | 12,914 | | | 78,500 | | | 130,406 | | | 11,995 | | | 16,633 | | | 4,858 | | | 12,473 | | | 30 | | | 276,692 | |
| Intersegment revenue | | 16,692 | | | 33,405 | | | 16,735 | | | 25,097 | | | 5,993 | | | 4,082 | | | 2,193 | | | 749 | | | 227 | | | — | |
| Depreciation and depletion expense | | 6,831 | | | 9,918 | | | 700 | | | 1,036 | | | 505 | | | 450 | | | 97 | | | 195 | | | 875 | | | 20,607 | |
| Interest revenue | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 33 | | | 33 | |
| Interest expense | | 58 | | | 36 | | | 1 | | | 6 | | | — | | | 1 | | | — | | | 1 | | | 844 | | | 947 | |
| Income tax expense (benefit) | | 1,116 | | | 4,871 | | | 156 | | | (165) | | | 1,235 | | | 684 | | | 464 | | | 329 | | | (1,054) | | | 7,636 | |
| Additions to property, plant and equipment | | 3,308 | | | 5,308 | | | 979 | | | 874 | | | 538 | | | 712 | | | 28 | | | 136 | | | 658 | | | 12,541 | |
| Investments in equity companies | | 4,999 | | | 18,544 | | | 353 | | | 972 | | | 3,019 | | | 2,490 | | | — | | | 1,185 | | | (337) | | | 31,225 | |
| Total assets | | 67,294 | | | 141,978 | | | 26,932 | | | 37,698 | | | 16,695 | | | 14,555 | | | 2,878 | | | 8,030 | | | 22,863 | | | 338,923 | |
| | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2020 | | | | | | | | | | | | | | | | | | | | |
| Earnings (loss) after income tax | | (19,385) | | | (645) | | | (1,342) | | | (1,230) | | | 1,196 | | | 1,061 | | | 571 | | | 630 | | | (3,296) | | | (22,440) | |
Effect of asset impairments - noncash | | (17,138) | | | (2,287) | | | (15) | | | (412) | | | (100) | | | (21) | | | — | | | (245) | | | (35) | | | (20,253) | |
| Earnings of equity companies included above | | (559) | | | 2,101 | | | 134 | | | (192) | | | (21) | | | 750 | | | — | | | (97) | | | (384) | | | 1,732 | |
| Sales and other operating revenue | | 5,876 | | | 8,673 | | | 46,401 | | | 86,966 | | | 6,391 | | | 11,243 | | | 3,993 | | | 8,993 | | | 38 | | | 178,574 | |
| Intersegment revenue | | 8,508 | | | 19,642 | | | 9,847 | | | 13,417 | | | 4,313 | | | 2,191 | | | 1,620 | | | 361 | | | 221 | | | — | |
| Depreciation and depletion expense | | 28,627 | | | 12,723 | | | 693 | | | 1,508 | | | 607 | | | 461 | | | 101 | | | 397 | | | 892 | | | 46,009 | |
| Interest revenue | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 49 | | | 49 | |
| Interest expense | | 52 | | | 93 | | | 1 | | | 20 | | | — | | | — | | | — | | | 1 | | | 991 | | | 1,158 | |
| Income tax expense (benefit) | | (5,958) | | | 742 | | | (493) | | | 89 | | | 421 | | | 277 | | | 188 | | | 299 | | | (1,197) | | | (5,632) | |
| Additions to property, plant and equipment | | 5,726 | | | 4,418 | | | 2,937 | | | 1,446 | | | 1,158 | | | 546 | | | 109 | | | 331 | | | 671 | | | 17,342 | |
| Investments in equity companies | | 4,792 | | | 18,135 | | | 352 | | | 952 | | | 2,543 | | | 2,413 | | | — | | | 1,028 | | | (443) | | | 29,772 | |
| Total assets | | 71,287 | | | 144,730 | | | 23,192 | | | 33,566 | | | 15,529 | | | 13,653 | | | 2,872 | | | 7,849 | | | 20,072 | | | 332,750 | |
| | | | | | | | | | | | | | | | | | | | |
| Due to rounding, numbers presented may not add up precisely to the totals indicated. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
GeographicRevenue from Contracts with Customers
| | | | | | | | | | | | | | | | | |
| Sales and other operating revenue | 2020 | | 2019 | | 2018 |
| | (millions of dollars) |
| United States | 62,663 | | | 89,612 | | | 96,930 | |
| Non-U.S. | 115,911 | | | 165,971 | | | 182,402 | |
| Total | 178,574 | | | 255,583 | | | 279,332 | |
| | | | | |
Significant non-U.S. revenue sources include: (1) | | | | | |
| Canada | 13,093 | | | 19,735 | | | 22,672 | |
| United Kingdom | 11,055 | | | 17,479 | | | 18,702 | |
| Singapore | 9,442 | | | 12,128 | | | 13,689 | |
| France | 8,676 | | | 12,740 | | | 13,637 | |
| Italy | 7,091 | | | 10,459 | | | 13,396 | |
| Belgium | 6,231 | | | 11,644 | | | 15,664 | |
| Australia | 5,839 | | | 7,941 | | | 8,780 | |
(1)Revenue is determined by primary country of operations. Excludes certain salesSales and other operating revenues in Non-U.S. operations where attributionrevenue include both revenue within the scope of ASC 606 and outside the scope of ASC 606. Revenue outside the scope of ASC 606 primarily relates to a specific country is not practicable.physically settled commodity contracts accounted for as derivatives. Contractual terms and type of customer are generally similar between contracts within the scope of ASC 606 and those outside it.
| | | | | | | | | | | | | | | | | |
Sales and other operating revenue (millions of dollars) | 2022 | | 2021 | | 2020 |
| | | | | | |
| Revenue from contracts with customers | 304,758 | | | 228,968 | | | 153,478 | |
| Revenue outside the scope of ASC 606 | 93,917 | | | 47,724 | | | 25,096 | |
| Total | 398,675 | | | 276,692 | | | 178,574 | |
| | | | | | | | | | | | | | | | | |
| December 31, |
| Long-lived assets | 2020 | | 2019 | | 2018 |
| | (millions of dollars) |
| United States | 94,732 | | | 114,372 | | | 108,147 | |
| Non-U.S. | 132,821 | | | 138,646 | | | 138,954 | |
| Total | 227,553 | | | 253,018 | | | 247,101 | |
| | | | | |
| Significant non-U.S. long-lived assets include: | | | | | |
| Canada | 36,232 | | | 39,130 | | | 37,433 | |
| Australia | 14,792 | | | 13,933 | | | 14,548 | |
| Singapore | 12,129 | | | 11,645 | | | 11,148 | |
| Kazakhstan | 8,882 | | | 9,315 | | | 9,726 | |
| Papua New Guinea | 7,803 | | | 8,057 | | | 8,269 | |
| Nigeria | 6,345 | | | 7,640 | | | 8,421 | |
| United Arab Emirates | 5,381 | | | 5,262 | | | 4,859 | |
| Russia | 4,616 | | | 5,135 | | | 5,456 | |
| Angola | 4,405 | | | 5,784 | | | 7,021 | |
| | | | | | | | | | | | | | | | | |
Sales and other operating revenue (millions of dollars) | 2022 | | 2021 | | 2020 |
| | | | | | |
| United States | 149,225 | | | 104,236 | | | 62,663 | |
| Non-U.S. | 249,450 | | | 172,456 | | | 115,911 | |
| Total | 398,675 | | | 276,692 | | | 178,574 | |
| | | | | |
Significant non-U.S. revenue sources include: (1) | | | | | |
| United Kingdom | 33,988 | | | 14,759 | | | 11,055 | |
| Canada | 32,970 | | | 22,166 | | | 13,093 | |
| Singapore | 19,029 | | | 15,031 | | | 9,442 | |
| France | 17,727 | | | 13,236 | | | 8,676 | |
| Italy | 11,496 | | | 10,056 | | | 7,091 | |
| Australia | 11,316 | | | 7,646 | | | 5,839 | |
| Belgium | 11,279 | | | 9,153 | | | 6,231 | |
| | | | | |
(1) Revenue is determined by primary country of operations. Excludes certain sales and other operating revenues in Non-U.S. operations where attribution to a specific country is not practicable. |
| | | | | | | | | | | | | | | | | |
Long-lived assets (millions of dollars) | December 31, |
| 2022 | | 2021 | | 2020 |
| | | | | | |
| United States | 90,051 | | | 90,412 | | | 94,732 | |
| Non-U.S. | 114,641 | | | 126,140 | | | 132,821 | |
| Total | 204,692 | | | 216,552 | | | 227,553 | |
| | | | | |
| Significant non-U.S. long-lived assets include: | | | | | |
| Canada | 31,106 | | | 34,907 | | | 36,232 | |
| Singapore | 11,972 | | | 11,969 | | | 12,129 | |
| Australia | 11,372 | | | 12,988 | | | 14,792 | |
| Kazakhstan | 8,172 | | | 8,463 | | | 8,882 | |
| Papua New Guinea | 7,338 | | | 7,534 | | | 7,803 | |
| Guyana | 6,766 | | | 4,892 | | | 3,547 | |
| United Arab Emirates | 5,448 | | | 5,392 | | | 5,381 | |
| Nigeria | 4,090 | | | 5,235 | | | 6,345 | |
| Brazil | 3,649 | | | 4,337 | | | 3,281 | |
| Angola | 2,793 | | | 3,207 | | | 4,405 | |
| Russia | — | | | 4,055 | | | 4,616 | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
19. Income and Other Taxes
| Income tax expense (benefit) (millions of dollars) | | Income tax expense (benefit) (millions of dollars) | 2022 | | 2021 | | 2020 |
| U.S. | Non-U.S. | Total | | U.S. | Non-U.S. | Total | | U.S. | Non-U.S. | Total |
| | | 2020 | | 2019 | | 2018 | | | | |
| | U.S. | | Non-U.S. | | Total | | U.S. | | Non-U.S. | | Total | | U.S. | | Non-U.S. | | Total | |
| | | | | | | | (millions of dollars) | | | | | | | |
| Income tax expense (benefit) | | | | | | | | | | | | | | | | | | |
| Federal and non-U.S. | Federal and non-U.S. | | | | | | | | | | | | | | | | | | Federal and non-U.S. | | | | | |
| Current | Current | 262 | | | 2,908 | | | 3,170 | | | (121) | | | 6,171 | | | 6,050 | | | 459 | | | 9,001 | | | 9,460 | | Current | 696 | | 15,071 | | 15,767 | | | 236 | | 6,948 | | 7,184 | | | 262 | | 2,908 | | 3,170 | |
| Deferred - net | Deferred - net | (6,045) | | | (2,007) | | | (8,052) | | | (255) | | | (420) | | | (675) | | | 518 | | | (614) | | | (96) | | Deferred - net | 4,122 | | (539) | | 3,583 | | | 870 | | (914) | | (44) | | | (6,045) | | (2,007) | | (8,052) | |
| U.S. tax on non-U.S. operations | U.S. tax on non-U.S. operations | 13 | | | — | | | 13 | | | 89 | | | — | | | 89 | | | 42 | | | — | | | 42 | | U.S. tax on non-U.S. operations | 65 | | — | | 65 | | | 26 | | — | | 26 | | | 13 | | — | | 13 | |
| Total federal and non-U.S. | Total federal and non-U.S. | (5,770) | | | 901 | | | (4,869) | | | (287) | | | 5,751 | | | 5,464 | | | 1,019 | | | 8,387 | | | 9,406 | | Total federal and non-U.S. | 4,883 | | 14,532 | | 19,415 | | | 1,132 | | 6,034 | | 7,166 | | | (5,770) | | 901 | | (4,869) | |
| State | State | (763) | | | — | | | (763) | | | (182) | | | — | | | (182) | | | 126 | | | — | | | 126 | | State | 761 | | — | | 761 | | | 470 | | — | | 470 | | | (763) | | — | | (763) | |
| Total income tax expense (benefit) | Total income tax expense (benefit) | (6,533) | | | 901 | | | (5,632) | | | (469) | | | 5,751 | | | 5,282 | | | 1,145 | | | 8,387 | | | 9,532 | | Total income tax expense (benefit) | 5,644 | | 14,532 | | 20,176 | | | 1,602 | | 6,034 | | 7,636 | | | (6,533) | | 901 | | (5,632) | |
| | All other taxes and duties | All other taxes and duties | | All other taxes and duties | | |
| Other taxes and duties | Other taxes and duties | 3,108 | | | 23,014 | | | 26,122 | | | 3,566 | | | 26,959 | | | 30,525 | | | 3,498 | | | 29,165 | | | 32,663 | | Other taxes and duties | 4,087 | | 23,832 | | 27,919 | | | 3,731 | | 26,508 | | 30,239 | | | 3,108 | | 23,014 | | 26,122 | |
Included in production and manufacturing expenses | Included in production and manufacturing expenses | 1,148 | | | 663 | | | 1,811 | | | 1,385 | | | 811 | | | 2,196 | | | 1,245 | | | 857 | | | 2,102 | | Included in production and manufacturing expenses | 2,204 | | 862 | | 3,066 | | | 1,589 | | 674 | | 2,263 | | | 1,148 | | 663 | | 1,811 | |
| Included in SG&A expenses | Included in SG&A expenses | 164 | | | 328 | | | 492 | | | 160 | | | 305 | | | 465 | | | 153 | | | 312 | | | 465 | | Included in SG&A expenses | 151 | | 319 | | 470 | | | 170 | | 283 | | 453 | | | 164 | | 328 | | 492 | |
| Total other taxes and duties | Total other taxes and duties | 4,420 | | | 24,005 | | | 28,425 | | | 5,111 | | | 28,075 | | | 33,186 | | | 4,896 | | | 30,334 | | | 35,230 | | Total other taxes and duties | 6,442 | | 25,013 | | 31,455 | | | 5,490 | | 27,465 | | 32,955 | | | 4,420 | | 24,005 | | 28,425 | |
| Total | Total | (2,113) | | | 24,906 | | | 22,793 | | | 4,642 | | | 33,826 | | | 38,468 | | | 6,041 | | | 38,721 | | | 44,762 | | Total | 12,086 | | 39,545 | | 51,631 | | | 7,092 | | 33,499 | | 40,591 | | | (2,113) | | 24,906 | | 22,793 | |
The above provisions for deferred income taxes include net expenses of $30 million in 2022, and net benefits of $53 million in 2021, and $25 million in 2020 $740 million in 2019, and $289 million in 2018 related to changes in tax laws and rates, and a benefit of $6.3 billion in 2020 related to asset impairments.
Additional European Taxes on the Energy Sector. On October 6, 2022, European Union (“EU”) Member States adopted an EU Council Regulation which, along with other measures, introduced a new tax described as an emergency intervention to address high energy prices. This regulation imposed a mandatory tax on certain companies active in the crude petroleum, coal, natural gas, and refinery sectors. The regulation required Member States to levy a minimum 33 percent tax on in-scope companies’ 2022 and/or 2023 “surplus profits”, defined in the regulation as taxable profits exceeding 120 percent of the annual average profits during the 2018-2021 period. EU Member States were required to implement the tax, or an equivalent national measure, by December 31, 2022. The enactment of these regulations resulted in an after-tax charge of approximately $1.8 billion to the Corporation’s fourth-quarter 2022 results, mainly reflected in the line “Income tax expense (benefit)” on the Consolidated Statement of Income.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The reconciliation between income tax expense (credit) and a theoretical U.S. tax computed by applying a rate of 21 percent for 2020, 20192022, 2021, and 20182020 is as follows:
| | (millions of dollars) | | (millions of dollars) | 2022 | | 2021 | | 2020 |
| | | 2020 | | 2019 | | 2018 | | | |
| | (millions of dollars) | |
| Income (Loss) before income taxes | | | | | | |
| Income (loss) before income taxes | | Income (loss) before income taxes | | | | | |
| United States | United States | (27,704) | | | (53) | | | 5,200 | | United States | 28,281 | | | 9,478 | | | (27,704) | |
| Non-U.S. | Non-U.S. | (1,179) | | | 20,109 | | | 25,753 | | Non-U.S. | 49,472 | | | 21,756 | | | (1,179) | |
| Total | Total | (28,883) | | | 20,056 | | | 30,953 | | Total | 77,753 | | | 31,234 | | | (28,883) | |
| Theoretical tax | Theoretical tax | (6,065) | | | 4,212 | | | 6,500 | | Theoretical tax | 16,328 | | | 6,559 | | | (6,065) | |
| Effect of equity method of accounting | Effect of equity method of accounting | (364) | | | (1,143) | | | (1,545) | | Effect of equity method of accounting | (2,407) | | | (1,398) | | | (364) | |
Non-U.S. taxes in excess of/(less than) theoretical U.S. tax (1)(2) | Non-U.S. taxes in excess of/(less than) theoretical U.S. tax (1)(2) | 1,606 | | | 2,573 | | | 4,626 | | Non-U.S. taxes in excess of/(less than) theoretical U.S. tax (1)(2) | 6,423 | | | 2,809 | | | 1,606 | |
State taxes, net of federal tax benefit (1) | State taxes, net of federal tax benefit (1) | (603) | | | (144) | | | 100 | | State taxes, net of federal tax benefit (1) | 601 | | | 371 | | | (603) | |
| Enactment-date effects of U.S. tax reform | 0 | | | 0 | | | (291) | | |
| | Other | Other | (206) | | | (216) | | | 142 | | Other | (769) | | | (705) | | | (206) | |
| Total income tax expense (credit) | Total income tax expense (credit) | (5,632) | | | 5,282 | | | 9,532 | | Total income tax expense (credit) | 20,176 | | | 7,636 | | | (5,632) | |
| | Effective tax rate calculation | Effective tax rate calculation | | Effective tax rate calculation | | |
| Income tax expense (credit) | Income tax expense (credit) | (5,632) | | | 5,282 | | | 9,532 | | Income tax expense (credit) | 20,176 | | | 7,636 | | | (5,632) | |
| ExxonMobil share of equity company income taxes | ExxonMobil share of equity company income taxes | 861 | | | 2,490 | | | 3,142 | | ExxonMobil share of equity company income taxes | 7,594 | | | 2,756 | | | 861 | |
| Total income tax expense (credit) | Total income tax expense (credit) | (4,771) | | | 7,772 | | | 12,674 | | Total income tax expense (credit) | 27,770 | | | 10,392 | | | (4,771) | |
| Net income (loss) including noncontrolling interests | Net income (loss) including noncontrolling interests | (23,251) | | | 14,774 | | | 21,421 | | Net income (loss) including noncontrolling interests | 57,577 | | | 23,598 | | | (23,251) | |
| Total income (loss) before taxes | Total income (loss) before taxes | (28,022) | | | 22,546 | | | 34,095 | | Total income (loss) before taxes | 85,347 | | | 33,990 | | | (28,022) | |
| | Effective income tax rate | Effective income tax rate | 17 | % | | 34 | % | | 37 | % | Effective income tax rate | 33% | | 31% | | 17% |
| (1) 2020 includes the impact of an increase in valuation allowance of $647 million in non-U.S. and $115 million in U.S. state jurisdictions. | | (1) 2020 includes the impact of an increase in valuation allowance of $647 million in non-U.S. and $115 million in U.S. state jurisdictions. |
(2) 2022 includes the impact of the additional European taxes on the energy sector of $1,825 million. | | (2) 2022 includes the impact of the additional European taxes on the energy sector of $1,825 million. |
(1)2020 includes the impact of an increase in valuation allowance of $647 million in non-U.S. and $115 million in U.S. state jurisdictions.
(2)2019 includes taxes less than the theoretical U.S. tax of $773 million from Norway operations and the sale of upstream assets, $657 million from a tax rate change in Alberta, Canada, and $268 million from an adjustment to a prior year tax position.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.
Deferred tax liabilities/(assets) are comprised of the following at December 31:
| | Tax effects of temporary differences for: | 2020 | | 2019 | |
Tax effects of temporary differences for: (millions of dollars) | | Tax effects of temporary differences for: (millions of dollars) | 2022 | | 2021 |
| | | (millions of dollars) | | | |
| Property, plant and equipment | Property, plant and equipment | 28,778 | | | 36,029 | | Property, plant and equipment | 25,607 | | | 27,888 | |
| Other liabilities | Other liabilities | 6,427 | | | 7,653 | | Other liabilities | 7,401 | | | 6,353 | |
| Total deferred tax liabilities | Total deferred tax liabilities | 35,205 | | | 43,682 | | Total deferred tax liabilities | 33,008 | | | 34,241 | |
| | Pension and other postretirement benefits | Pension and other postretirement benefits | (4,703) | | | (4,712) | | Pension and other postretirement benefits | (1,754) | | | (3,687) | |
| Asset retirement obligations | Asset retirement obligations | (3,150) | | | (3,403) | | Asset retirement obligations | (3,045) | | | (2,865) | |
| Tax loss carryforwards | Tax loss carryforwards | (8,982) | | | (7,404) | | Tax loss carryforwards | (4,862) | | | (6,914) | |
| Other assets | Other assets | (7,095) | | | (7,735) | | Other assets | (6,948) | | | (7,694) | |
| Total deferred tax assets | Total deferred tax assets | (23,930) | | | (23,254) | | Total deferred tax assets | (16,609) | | | (21,160) | |
| | Asset valuation allowances | Asset valuation allowances | 2,731 | | | 1,924 | | Asset valuation allowances | 2,650 | | | 2,634 | |
| Net deferred tax liabilities | Net deferred tax liabilities | 14,006 | | | 22,352 | | Net deferred tax liabilities | 19,049 | | | 15,715 | |
In 2020,2022, asset valuation allowances of $2,731$2,650 million increased by $807$16 million and included net provisions of $762of $202 million and foreign currency effects of $41 million.$186 million.
| | Balance sheet classification | 2020 | | 2019 | |
Balance sheet classification (millions of dollars) | | Balance sheet classification (millions of dollars) | 2022 | | 2021 |
| | | (millions of dollars) | | | |
| Other assets, including intangibles, net | Other assets, including intangibles, net | (4,159) | | | (3,268) | | Other assets, including intangibles, net | (3,825) | | | (4,450) | |
| Deferred income tax liabilities | Deferred income tax liabilities | 18,165 | | | 25,620 | | Deferred income tax liabilities | 22,874 | | | 20,165 | |
| Net deferred tax liabilities | Net deferred tax liabilities | 14,006 | | | 22,352 | | Net deferred tax liabilities | 19,049 | | | 15,715 | |
The Corporation’s undistributed earnings from subsidiary companies outside the United States include amounts that have been retained to fund prior and future capital project expenditures. Deferred income taxes have not been recorded for potential future tax obligations, such as foreign withholding tax and state tax, as these undistributed earnings are expected to be indefinitely reinvested for the foreseeable future. As of December 31, 2020,2022, it is not practicable to estimate the unrecognized deferred tax liability. However, unrecognized deferred taxes on remittance of these funds are not expected to be material.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unrecognized Tax Benefits. The Corporation is subject to income taxation in many jurisdictions around the world. The benefits of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. Unrecognized tax benefits reflect the difference between positions taken or expected to be taken on income tax returns and the amounts recognized in the financial statements. The following table summarizes the movement in unrecognized tax benefits:
| | Gross unrecognized tax benefits | 2020 | | 2019 | | 2018 | |
Gross unrecognized tax benefits (millions of dollars) | | Gross unrecognized tax benefits (millions of dollars) | 2022 | | 2021 | | 2020 |
| | | (millions of dollars) | | | |
| Balance at January 1 | Balance at January 1 | 8,844 | | | 9,174 | | | 8,783 | | Balance at January 1 | 9,130 | | | 8,764 | | | 8,844 | |
| Additions based on current year's tax positions | Additions based on current year's tax positions | 253 | | | 287 | | | 375 | | Additions based on current year's tax positions | 539 | | | 358 | | | 253 | |
| Additions for prior years' tax positions | Additions for prior years' tax positions | 218 | | | 120 | | | 240 | | Additions for prior years' tax positions | 294 | | | 100 | | | 218 | |
| Reductions for prior years' tax positions | Reductions for prior years' tax positions | (201) | | | (97) | | | (125) | | Reductions for prior years' tax positions | (6,243) | | | (79) | | | (201) | |
| Reductions due to lapse of the statute of limitations | Reductions due to lapse of the statute of limitations | (237) | | | (279) | | | (5) | | Reductions due to lapse of the statute of limitations | (16) | | | (2) | | | (237) | |
| Settlements with tax authorities | Settlements with tax authorities | (113) | | | (538) | | | (68) | | Settlements with tax authorities | (277) | | | (11) | | | (113) | |
| Foreign exchange effects/other | Foreign exchange effects/other | 0 | | | 177 | | | (26) | | Foreign exchange effects/other | (29) | | | — | | | — | |
| Balance at December 31 | Balance at December 31 | 8,764 | | | 8,844 | | | 9,174 | | Balance at December 31 | 3,398 | | | 9,130 | | | 8,764 | |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The gross unrecognized tax benefit balances shown above are predominantly related to tax positions that would reduce the Corporation’s effective tax rate if the positions are favorably resolved. Unfavorable resolution of these tax positions generally would not increase the effective tax rate. The 2020, 20192022, 2021, and 20182020 changes in unrecognized tax benefits did not have a material effect on the Corporation’s net income.
Resolution of these tax positions through negotiations with the relevant tax authorities or through litigation will take many years to complete. It is difficult to predict the timing of resolution for these tax positions since suchthe timing is not entirely within the control of the Corporation. In the United States, the Corporation filed a refund suit for tax years 2006-2009 with respect to positions at issue for those years. These positions were reflected in the 2021 unrecognized tax benefit table. The IRS asserted penalties associated with several of those positions. The Corporation did not recognize those penalties as an expense because it did not expect the penalties to be sustained in litigation. On August 3, 2022, the Corporation received an adverse ruling on the tax positions and a favorable ruling on the related penalties from the U.S. Court of Appeals for the Fifth Circuit. Neither the Corporation nor the government appealed the ruling. As a result of this litigation, the tax positions that were at issue are not reflected in the ending balance of the 2022 unrecognized tax benefits table. The Corporation has various ongoing U.S. federal income tax positions at issue with the Internal Revenue Service (IRS) for tax years beginning in 2006. The Corporation filed a refund suit for tax years 2006-2009 in U.S. federal district court (District Court) with respect to the positions at issue for those years. These positions are reflected in the unrecognized tax benefits table above. On February 24, 2020, the Corporation received an adverse ruling on this suit. The IRS has asserted penalties associated with several of those positions. The Corporation has not recognized the penalties as an expense because the Corporation does not expect the penalties to be sustained under applicable law. On January 13, 2021, the District Court ruled that no penalties apply to the Corporation's positions in this suit. Proceedings in the District Court are continuing.2010. Unfavorable resolution of all positions at issue with the IRSthese issues would not have a material adverse effect on the Corporation’s operations or financial condition.
It is reasonably possible that the total amount of unrecognized tax benefits could increase by up to 20 percent or decrease by up to 10 percent in the next 12 months.
The following table summarizes the tax years that remain subject to examination by major tax jurisdiction:
| | Country of Operation | Country of Operation | Open Tax Years | Country of Operation | Open Tax Years |
| Abu Dhabi | Abu Dhabi | 2018 | — | 2020 | Abu Dhabi | 2021 | — | 2022 |
| Angola | Angola | 2018 | — | 2020 | Angola | 2018 | — | 2022 |
| Australia | Australia | 2010 | — | 2020 | Australia | 2010 | — | 2022 |
| Belgium | Belgium | 2017 | — | 2020 | Belgium | 2017 | — | 2022 |
| Canada | Canada | 2001 | — | 2020 | Canada | 2001 | — | 2022 |
| Equatorial Guinea | Equatorial Guinea | 2007 | — | 2020 | Equatorial Guinea | 2009 | — | 2022 |
| Indonesia | Indonesia | 2007 | — | 2020 | Indonesia | 2008 | — | 2022 |
| Iraq | Iraq | 2015 | — | 2020 | Iraq | 2017 | — | 2022 |
| Malaysia | Malaysia | 2011 | — | 2020 | Malaysia | 2018 | — | 2022 |
| Nigeria | Nigeria | 2006 | — | 2020 | Nigeria | 2006 | — | 2022 |
| Norway | 2010 | — | 2020 | |
| Papua New Guinea | Papua New Guinea | 2008 | — | 2020 | Papua New Guinea | 2008 | — | 2022 |
| Russia | 2018 | — | 2020 | |
| | United Kingdom | United Kingdom | 2015 | — | 2020 | United Kingdom | 2015 | — | 2022 |
| United States | United States | 2006 | — | 2020 | United States | 2010 | — | 2022 |
The Corporation classifies interest on income tax-related balances as interest expense or interest income and classifies tax-related penalties as operating expense.
For 2022 and 2021 the Corporation's net interest expense on income tax reserves was $16 million and $0 million, respectively. For 2020, the Corporation's net interest expense was a credit of $6 million on income tax reserves. The Corporation incurred $0 million and $3 million in interest expense on income tax reserves in 2019 and 2018, respectively.million. The related interest payable balances were $61$63 million and $71$61 million at December 31, 2020,2022 and 2019,2021, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
20.Restructuring Divestment Activities
During 2020, ExxonMobil conducted an extensive global reviewThe Corporation realized proceeds of staffing levelsapproximately $5 billion and subsequently commenced targeted workforce reductions within a numberrecognized net after-tax earnings of countries to improve efficiencyapproximately $0.4 billion from its divestment activities in 2022. This included the sale of certain unproved assets in Romania and reduce costs. The programs, which are expected to be substantially completed byunconventional assets in Canada and the end of 2021, include both voluntary and involuntary employee separations and reductions in contractors.United States, as well as other smaller divestments.
In 2020August 2022, the Corporation recorded before-tax chargesexecuted an agreement for the sale of $450 million,Mobil California Exploration and Producing Asset Company (United States), consisting primarily of employee separation costs, associated with announced workforce reduction programs in Europe, North America, and Australia. These costs are captured in “Selling, general and administrative expenses” on the Statement of Income and reportedExxonMobil's interest in the CorporateAera Energy joint venture, to Green Gate Resources E, LLC. The transaction is anticipated to close in first quarter 2023.
In November 2022, the Corporation executed an agreement for the sale of the Santa Ynez Unit and financing segment.associated assets in California. The agreement is subject to certain conditions precedent and government approvals and does not yet meet held-for-sale criteria under ASC 360. Should the conditions precedent be met and the potential transaction close, the Corporation estimates additional chargeswould expect to recognize a loss of up to $200 million in 2021 related$2 billion.
In February 2022, the Corporation signed an agreement with Seplat Energy Offshore Limited for the sale of Mobil Producing Nigeria Unlimited. The agreement is subject to planned workforce reduction programs.certain conditions precedent and government approvals. In early July, a Nigerian court issued an order to halt transition activities and enter into arbitration with the Nigerian National Petroleum Company. The closing date and any loss on sale will depend on resolution of these matters.
The following table summarizes the reserves and charges related to the workforce reduction programs, which are recorded in “Accounts payable and accrued liabilities.”
| | | | | |
| 2020 |
| (millions of dollars) |
Balance at January 1 | 0 | |
Additions/adjustments | 450 | |
Payments made | (47) | |
Balance at December 31 | 403 | |
SUPPLEMENTALINFORMATIONONOILANDGASEXPLORATIONANDPRODUCTIONACTIVITIES(unaudited)
The results of operations for producing activities shown below do not include earnings from other activities that ExxonMobil includes in the Upstream function, such as oil and gas transportation operations, LNG liquefaction and transportation operations, coal and power operations, technical service agreements, gains and losses from derivative activity, other nonoperating activities and adjustments for noncontrolling interests. These excluded amounts for both consolidated and equity companies totaled $4,802 million in 2022, $(1,380) million in 2021 and $274 million in 2020, $3,502 million in 2019 and $1,484 million in 2018.2020. Oil sands mining operations are included in the results of operations in accordance with Securities and Exchange Commission and Financial Accounting Standards Board rules.
| | Results of Operations | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total | |
Results of Operations (millions of dollars) | | Results of Operations (millions of dollars) | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total |
| | | (millions of dollars) | | | |
| 2022 | | 2022 | | |
| Consolidated Subsidiaries | Consolidated Subsidiaries | | | | | | | | | | | | | | Consolidated Subsidiaries | | | | | | | | | | | | | |
| 2020 - Revenue | | | | | | | | | | | | | | |
| Sales to third parties | Sales to third parties | 2,933 | | | 1,034 | | | 536 | | | 262 | | | 1,632 | | | 1,983 | | | 8,380 | | Sales to third parties | 8,801 | | | 4,401 | | | 2,388 | | | 463 | | | 2,710 | | | 6,222 | | | 24,985 | |
| Transfers | Transfers | 4,943 | | | 3,938 | | | 362 | | | 4,603 | | | 5,584 | | | 509 | | | 19,939 | | Transfers | 17,020 | | | 12,568 | | | 60 | | | 8,634 | | | 12,274 | | | 996 | | | 51,552 | |
| Revenue | | Revenue | 25,821 | | | 16,969 | | | 2,448 | | | 9,097 | | | 14,984 | | | 7,218 | | | 76,537 | |
| | | 7,876 | | | 4,972 | | | 898 | | | 4,865 | | | 7,216 | | | 2,492 | | | 28,319 | | | |
| Production costs excluding taxes | Production costs excluding taxes | 3,877 | | | 3,928 | | | 786 | | | 1,911 | | | 1,471 | | | 483 | | | 12,456 | | Production costs excluding taxes | 3,965 | | | 5,519 | | | 464 | | | 1,965 | | | 1,492 | | | 513 | | | 13,918 | |
| Exploration expenses | Exploration expenses | 51 | | | 573 | | | 33 | | | 371 | | | 112 | | | 145 | | | 1,285 | | Exploration expenses | 18 | | | 698 | | | 28 | | | 168 | | | 51 | | | 62 | | | 1,025 | |
| Depreciation and depletion | Depreciation and depletion | 27,489 | | | 5,118 | | | 828 | | | 2,788 | | | 2,171 | | | 733 | | | 39,127 | | Depreciation and depletion | 5,472 | | | 3,700 | | | 193 | | | 2,293 | | | 5,672 | | | 829 | | | 18,159 | |
| Taxes other than income | Taxes other than income | 615 | | | 106 | | | 32 | | | 390 | | | 692 | | | 152 | | | 1,987 | | Taxes other than income | 2,314 | | | 120 | | | 140 | | | 729 | | | 2,312 | | | 689 | | | 6,304 | |
| Related income tax | Related income tax | (5,650) | | | (944) | | | (343) | | | (258) | | | 2,130 | | | 241 | | | (4,824) | | Related income tax | 3,294 | | | 1,112 | | | 1,048 | | | 2,004 | | | 6,008 | | | 1,549 | | | 15,015 | |
Results of producing activities for consolidated
subsidiaries | Results of producing activities for consolidated
subsidiaries | (18,506) | | | (3,809) | | | (438) | | | (337) | | | 640 | | | 738 | | | (21,712) | | Results of producing activities for consolidated subsidiaries | 10,758 | | | 5,820 | | | 575 | | | 1,938 | | | (551) | | | 3,576 | | | 22,116 | |
| | Equity Companies | Equity Companies | | | | | | | | | | | | | | Equity Companies | | | | | | | | | | | | | |
| 2020 - Revenue | | | | | | | | | | | | | | |
| Sales to third parties | Sales to third parties | 410 | | | — | | | 513 | | | — | | | 6,289 | | | — | | | 7,212 | | Sales to third parties | 820 | | | — | | | 2,791 | | | 10 | | | 20,750 | | | — | | | 24,371 | |
| Transfers | Transfers | 308 | | | — | | | 12 | | | — | | | 60 | | | — | | | 380 | | Transfers | 640 | | | — | | | 51 | | | — | | | 316 | | | — | | | 1,007 | |
| | 718 | | | — | | | 525 | | | — | | | 6,349 | | | — | | | 7,592 | | |
| Revenue | | Revenue | 1,460 | | | — | | | 2,842 | | | 10 | | | 21,066 | | | — | | | 25,378 | |
| Production costs excluding taxes | Production costs excluding taxes | 545 | | | — | | | 674 | | | 6 | | | 421 | | | — | | | 1,646 | | Production costs excluding taxes | 667 | | | — | | | 607 | | | 21 | | | 379 | | | — | | | 1,674 | |
| Exploration expenses | Exploration expenses | — | | | — | | | 2 | | | — | | | — | | | — | | | 2 | | Exploration expenses | — | | | — | | | 1 | | | — | | | — | | | — | | | 1 | |
| Depreciation and depletion | Depreciation and depletion | 560 | | | — | | | 224 | | | — | | | 543 | | | — | | | 1,327 | | Depreciation and depletion | 280 | | | — | | | 48 | | | 1 | | | 717 | | | — | | | 1,046 | |
| Taxes other than income | Taxes other than income | 34 | | | — | | | 22 | | | — | | | 2,274 | | | — | | | 2,330 | | Taxes other than income | 37 | | | — | | | 232 | | | — | | | 6,857 | | | — | | | 7,126 | |
| Related income tax | Related income tax | — | | | — | | | (246) | | | (1) | | | 1,126 | | | — | | | 879 | | Related income tax | — | | | — | | | 1,413 | | | (2) | | | 4,559 | | | — | | | 5,970 | |
| Results of producing activities for equity companies | Results of producing activities for equity companies | (421) | | | — | | | (151) | | | (5) | | | 1,985 | | | — | | | 1,408 | | Results of producing activities for equity companies | 476 | | | — | | | 541 | | | (10) | | | 8,554 | | | — | | | 9,561 | |
| | Total results of operations | Total results of operations | (18,927) | | | (3,809) | | | (589) | | | (342) | | | 2,625 | | | 738 | | | (20,304) | | Total results of operations | 11,234 | | | 5,820 | | | 1,116 | | | 1,928 | | | 8,003 | | | 3,576 | | | 31,677 | |
| | Results of Operations | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total | |
Results of Operations (millions of dollars) | | Results of Operations (millions of dollars) | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total |
| | | (millions of dollars) | | |
| 2021 | | 2021 | | |
| Consolidated Subsidiaries | Consolidated Subsidiaries | | | | | | | | | | | | | | Consolidated Subsidiaries | | | | | | | | | | | | | |
| 2019 - Revenue | | | | | | | | | | | | | | |
| Sales to third parties | Sales to third parties | 5,070 | | | 1,452 | | | 2,141 | | | 802 | | | 2,393 | | | 3,132 | | | 14,990 | | Sales to third parties | 5,797 | | | 2,480 | | | 1,628 | | | 253 | | | 2,110 | | | 3,182 | | | 15,450 | |
| Transfers | Transfers | 6,544 | | | 5,979 | | | 1,345 | | | 7,892 | | | 8,706 | | | 628 | | | 31,094 | | Transfers | 10,938 | | | 8,492 | | | 412 | | | 6,087 | | | 8,829 | | | 812 | | | 35,570 | |
| | 11,614 | | | 7,431 | | | 3,486 | | | 8,694 | | | 11,099 | | | 3,760 | | | 46,084 | | |
| Revenue | | Revenue | 16,735 | | | 10,972 | | | 2,040 | | | 6,340 | | | 10,939 | | | 3,994 | | | 51,020 | |
| Production costs excluding taxes | Production costs excluding taxes | 4,697 | | | 4,366 | | | 1,196 | | | 2,387 | | | 1,597 | | | 637 | | | 14,880 | | Production costs excluding taxes | 3,436 | | | 4,867 | | | 754 | | | 1,759 | | | 1,471 | | | 481 | | | 12,768 | |
| Exploration expenses | Exploration expenses | 120 | | | 498 | | | 118 | | | 234 | | | 119 | | | 180 | | | 1,269 | | Exploration expenses | 19 | | | 464 | | | 26 | | | 359 | | | 146 | | | 40 | | | 1,054 | |
| Depreciation and depletion | Depreciation and depletion | 5,916 | | | 1,975 | | | 601 | | | 3,019 | | | 2,264 | | | 703 | | | 14,478 | | Depreciation and depletion | 6,185 | | | 2,690 | | | 408 | | | 2,799 | | | 1,965 | | | 1,002 | | | 15,049 | |
| Taxes other than income | Taxes other than income | 998 | | | 122 | | | 113 | | | 682 | | | 1,182 | | | 250 | | | 3,347 | | Taxes other than income | 1,367 | | | 113 | | | 11 | | | 490 | | | 1,258 | | | 423 | | | 3,662 | |
| Related income tax | Related income tax | (29) | | | (423) | | | (20) | | | 1,188 | | | 4,238 | | | 599 | | | 5,553 | | Related income tax | 1,276 | | | 55 | | | 235 | | | 311 | | | 3,858 | | | 610 | | | 6,345 | |
Results of producing activities for consolidated
subsidiaries | Results of producing activities for consolidated
subsidiaries | (88) | | | 893 | | | 1,478 | | | 1,184 | | | 1,699 | | | 1,391 | | | 6,557 | | Results of producing activities for consolidated subsidiaries | 4,452 | | | 2,783 | | | 606 | | | 622 | | | 2,241 | | | 1,438 | | | 12,142 | |
| | Equity Companies | Equity Companies | | | | | | | | | | | | | | Equity Companies | | | | | | | | | | | | | |
| 2019 - Revenue | | | | | | | | | | | | | | |
| Sales to third parties | Sales to third parties | 664 | | | — | | | 1,248 | | | — | | | 10,536 | | | — | | | 12,448 | | Sales to third parties | 620 | | | — | | | 1,332 | | | — | | | 12,239 | | | — | | | 14,191 | |
| Transfers | Transfers | 530 | | | — | | | 6 | | | — | | | 464 | | | — | | | 1,000 | | Transfers | 479 | | | — | | | 33 | | | — | | | 151 | | | — | | | 663 | |
| | 1,194 | | | — | | | 1,254 | | | — | | | 11,000 | | | — | | | 13,448 | | |
| Revenue | | Revenue | 1,099 | | | — | | | 1,365 | | | — | | | 12,390 | | | — | | | 14,854 | |
| Production costs excluding taxes | Production costs excluding taxes | 595 | | | — | | | 570 | | | 6 | | | 555 | | | — | | | 1,726 | | Production costs excluding taxes | 538 | | | — | | | 1,065 | | | 11 | | | 413 | | | — | | | 2,027 | |
| Exploration expenses | Exploration expenses | 1 | | | — | | | 4 | | | — | | | — | | | — | | | 5 | | Exploration expenses | — | | | — | | | 2 | | | — | | | — | | | — | | | 2 | |
| Depreciation and depletion | Depreciation and depletion | 379 | | | — | | | 231 | | | — | | | 528 | | | — | | | 1,138 | | Depreciation and depletion | 509 | | | — | | | 194 | | | — | | | 611 | | | — | | | 1,314 | |
| Taxes other than income | Taxes other than income | 33 | | | — | | | 75 | | | — | | | 3,634 | | | — | | | 3,742 | | Taxes other than income | 33 | | | — | | | 48 | | | — | | | 3,749 | | | — | | | 3,830 | |
| Related income tax | Related income tax | — | | | — | | | 180 | | | (1) | | | 2,275 | | | — | | | 2,454 | | Related income tax | — | | | — | | | 13 | | | 3 | | | 2,652 | | | — | | | 2,668 | |
| Results of producing activities for equity companies | Results of producing activities for equity companies | 186 | | | — | | | 194 | | | (5) | | | 4,008 | | | — | | | 4,383 | | Results of producing activities for equity companies | 19 | | | — | | | 43 | | | (14) | | | 4,965 | | | — | | | 5,013 | |
| | Total results of operations | Total results of operations | 98 | | | 893 | | | 1,672 | | | 1,179 | | | 5,707 | | | 1,391 | | | 10,940 | | Total results of operations | 4,471 | | | 2,783 | | | 649 | | | 608 | | | 7,206 | | | 1,438 | | | 17,155 | |
| | 2020 | | 2020 | | |
| Consolidated Subsidiaries | Consolidated Subsidiaries | | | | | | | | | | | | | | Consolidated Subsidiaries | | | | | | | | | | | | | |
| 2018 - Revenue | | | | | | | | | | | | | | |
| Sales to third parties | Sales to third parties | 5,914 | | | 1,491 | | | 3,680 | | | 1,136 | | | 2,431 | | | 3,256 | | | 17,908 | | Sales to third parties | 2,933 | | | 1,034 | | | 536 | | | 262 | | | 1,632 | | | 1,983 | | | 8,380 | |
| Transfers | Transfers | 5,822 | | | 4,633 | | | 1,573 | | | 8,844 | | | 8,461 | | | 873 | | | 30,206 | | Transfers | 4,943 | | | 3,938 | | | 362 | | | 4,603 | | | 5,584 | | | 509 | | | 19,939 | |
| | 11,736 | | | 6,124 | | | 5,253 | | | 9,980 | | | 10,892 | | | 4,129 | | | 48,114 | | |
| Revenue | | Revenue | 7,876 | | | 4,972 | | | 898 | | | 4,865 | | | 7,216 | | | 2,492 | | | 28,319 | |
| Production costs excluding taxes | Production costs excluding taxes | 3,915 | | | 4,211 | | | 1,348 | | | 2,454 | | | 1,501 | | | 680 | | | 14,109 | | Production costs excluding taxes | 3,877 | | | 3,928 | | | 786 | | | 1,911 | | | 1,471 | | | 483 | | | 12,456 | |
| Exploration expenses | Exploration expenses | 237 | | | 434 | | | 140 | | | 318 | | | 209 | | | 128 | | | 1,466 | | Exploration expenses | 51 | | | 573 | | | 33 | | | 371 | | | 112 | | | 145 | | | 1,285 | |
| Depreciation and depletion | Depreciation and depletion | 5,775 | | | 1,803 | | | 665 | | | 2,788 | | | 2,088 | | | 809 | | | 13,928 | | Depreciation and depletion | 27,489 | | | 5,118 | | | 828 | | | 2,788 | | | 2,171 | | | 733 | | | 39,127 | |
| Taxes other than income | Taxes other than income | 953 | | | 133 | | | 128 | | | 799 | | | 1,155 | | | 335 | | | 3,503 | | Taxes other than income | 615 | | | 106 | | | 32 | | | 390 | | | 692 | | | 152 | | | 1,987 | |
| Related income tax | Related income tax | 250 | | | (121) | | | 1,934 | | | 1,766 | | | 4,008 | | | 622 | | | 8,459 | | Related income tax | (5,650) | | | (944) | | | (343) | | | (258) | | | 2,130 | | | 241 | | | (4,824) | |
Results of producing activities for consolidated
subsidiaries | Results of producing activities for consolidated
subsidiaries | 606 | | | (336) | | | 1,038 | | | 1,855 | | | 1,931 | | | 1,555 | | | 6,649 | | Results of producing activities for consolidated subsidiaries | (18,506) | | | (3,809) | | | (438) | | | (337) | | | 640 | | | 738 | | | (21,712) | |
| | Equity Companies | Equity Companies | | | | | | | | | | | | | | Equity Companies | | | | | | | | | | | | | |
| 2018 - Revenue | | | | | | | | | | | | | | |
| Sales to third parties | Sales to third parties | 747 | | | — | | | 1,420 | | | — | | | 12,028 | | | — | | | 14,195 | | Sales to third parties | 410 | | | — | | | 513 | | | — | | | 6,289 | | | — | | | 7,212 | |
| Transfers | Transfers | 588 | | | — | | | 8 | | | — | | | 935 | | | — | | | 1,531 | | Transfers | 308 | | | — | | | 12 | | | — | | | 60 | | | — | | | 380 | |
| | 1,335 | | | — | | | 1,428 | | | — | | | 12,963 | | | — | | | 15,726 | | |
| Revenue | | Revenue | 718 | | | — | | | 525 | | | — | | | 6,349 | | | — | | | 7,592 | |
| Production costs excluding taxes | Production costs excluding taxes | 535 | | | — | | | 745 | | | 5 | | | 409 | | | — | | | 1,694 | | Production costs excluding taxes | 500 | | | — | | | 674 | | | 6 | | | 421 | | | — | | | 1,601 | |
| Exploration expenses | Exploration expenses | 1 | | | — | | | 4 | | | — | | | 5 | | | — | | | 10 | | Exploration expenses | — | | | — | | | 2 | | | — | | | — | | | — | | | 2 | |
| Depreciation and depletion | Depreciation and depletion | 248 | | | — | | | 172 | | | — | | | 462 | | | — | | | 882 | | Depreciation and depletion | 605 | | | — | | | 224 | | | — | | | 543 | | | — | | | 1,372 | |
| Taxes other than income | Taxes other than income | 33 | | | — | | | 61 | | | — | | | 4,104 | | | — | | | 4,198 | | Taxes other than income | 34 | | | — | | | 22 | | | — | | | 2,274 | | | — | | | 2,330 | |
| Related income tax | Related income tax | — | | | — | | | 271 | | | (1) | | | 2,726 | | | — | | | 2,996 | | Related income tax | — | | | — | | | (246) | | | (1) | | | 1,126 | | | — | | | 879 | |
| Results of producing activities for equity companies | Results of producing activities for equity companies | 518 | | | — | | | 175 | | | (4) | | | 5,257 | | | — | | | 5,946 | | Results of producing activities for equity companies | (421) | | | — | | | (151) | | | (5) | | | 1,985 | | | — | | | 1,408 | |
| | Total results of operations | Total results of operations | 1,124 | | | (336) | | | 1,213 | | | 1,851 | | | 7,188 | | | 1,555 | | | 12,595 | | Total results of operations | (18,927) | | | (3,809) | | | (589) | | | (342) | | | 2,625 | | | 738 | | | (20,304) | |
Oil and Gas Exploration and Production Costs
The amounts shown for net capitalized costs of consolidated subsidiaries are $13,206$10,785 million less at year-end 20202022 and $13,082$12,005 million less at year-end 20192021 than the amounts reported as investments in property, plant and equipment for the Upstream in Note 9. This is due to the exclusion from capitalized costs of certain transportation and research assets and assets relating to LNG operations. Assets related to oil sands and oil shale mining operations are included in the capitalized costs in accordance with Financial Accounting Standards Board rules.
| | Capitalized Costs | | | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total | |
Capitalized Costs (millions of dollars) | | Capitalized Costs (millions of dollars) | | | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total |
| | | | | (millions of dollars) | |
| As of December 31, 2022 | | As of December 31, 2022 | |
| Consolidated Subsidiaries | Consolidated Subsidiaries | | | | | | | | | | | | | | | Consolidated Subsidiaries | | | | | | | | | | | | | | |
| As of December 31, 2020 | | | | | | | | | | | | | | | | |
| Property (acreage) costs | Property (acreage) costs | – Proved | | 18,059 | | | 2,151 | | | 51 | | | 1,332 | | | 2,979 | | | 771 | | | 25,343 | | Property (acreage) costs | – Proved | | 15,547 | | | 3,427 | | | 9 | | | 1,510 | | | 3,023 | | | 695 | | | 24,211 | |
| | | – Unproved | | 23,255 | | | 7,352 | | | 37 | | | 213 | | | 181 | | | 2,642 | | | 33,680 | | | – Unproved | | 13,797 | | | 3,011 | | | 37 | | | 119 | | | 5 | | | 2,659 | | | 19,628 | |
| Total property costs | Total property costs | | | 41,314 | | | 9,503 | | | 88 | | | 1,545 | | | 3,160 | | | 3,413 | | | 59,023 | | Total property costs | | | 29,344 | | | 6,438 | | | 46 | | | 1,629 | | | 3,028 | | | 3,354 | | | 43,839 | |
| Producing assets | Producing assets | | | 104,650 | | | 52,552 | | | 20,286 | | | 55,556 | | | 43,394 | | | 15,348 | | | 291,786 | | Producing assets | | | 96,209 | | | 49,923 | | | 12,156 | | | 53,164 | | | 45,405 | | | 14,296 | | | 271,153 | |
| Incomplete construction | Incomplete construction | | | 5,549 | | | 4,590 | | | 1,446 | | | 1,975 | | | 3,050 | | | 1,972 | | | 18,582 | | Incomplete construction | | | 4,169 | | | 7,774 | | | 172 | | | 1,404 | | | 3,043 | | | 2,276 | | | 18,838 | |
| Total capitalized costs | Total capitalized costs | | | 151,513 | | | 66,645 | | | 21,820 | | | 59,076 | | | 49,604 | | | 20,733 | | | 369,391 | | Total capitalized costs | | | 129,722 | | | 64,135 | | | 12,374 | | | 56,197 | | | 51,476 | | | 19,926 | | | 333,830 | |
| Accumulated depreciation and depletion | Accumulated depreciation and depletion | | 89,401 | | | 26,635 | | | 19,193 | | | 46,567 | | | 24,701 | | | 8,628 | | | 215,125 | | Accumulated depreciation and depletion | | 72,686 | | | 25,852 | | | 11,752 | | | 48,606 | | | 32,025 | | | 9,548 | | | 200,469 | |
| Net capitalized costs for consolidated subsidiaries | Net capitalized costs for consolidated subsidiaries | | 62,112 | | | 40,010 | | | 2,627 | | | 12,509 | | | 24,903 | | | 12,105 | | | 154,266 | | Net capitalized costs for consolidated subsidiaries | | 57,036 | | | 38,283 | | | 622 | | | 7,591 | | | 19,451 | | | 10,378 | | | 133,361 | |
| | Equity Companies | Equity Companies | | | | | | | | | | | | | | | | Equity Companies | | | | | | | | | | | | | | |
| As of December 31, 2020 | | | | | | | | | | | | | | | | |
| Property (acreage) costs | Property (acreage) costs | – Proved | | 98 | | | — | | | 4 | | | 286 | | | — | | | — | | | 388 | | Property (acreage) costs | – Proved | | 99 | | | — | | | 3 | | | 309 | | | — | | | — | | | 411 | |
| | | – Unproved | | 4 | | | — | | | — | | | 3,134 | | | — | | | — | | | 3,138 | | | – Unproved | | 2 | | | — | | | — | | | 3,111 | | | — | | | — | | | 3,113 | |
| Total property costs | Total property costs | | | 102 | | | — | | | 4 | | | 3,420 | | | — | | | — | | | 3,526 | | Total property costs | | | 101 | | | — | | | 3 | | | 3,420 | | | — | | | — | | | 3,524 | |
| Producing assets | Producing assets | | | 6,975 | | | — | | | 5,932 | | | — | | | 8,547 | | | — | | | 21,454 | | Producing assets | | | 6,882 | | | — | | | 5,243 | | | 281 | | | 10,177 | | | — | | | 22,583 | |
| Incomplete construction | Incomplete construction | | | 138 | | | — | | | 34 | | | 721 | | | 10,527 | | | — | | | 11,420 | | Incomplete construction | | | 160 | | | — | | | 35 | | | 550 | | | 11,709 | | | — | | | 12,454 | |
| Total capitalized costs | Total capitalized costs | | | 7,215 | | | — | | | 5,970 | | | 4,141 | | | 19,074 | | | — | | | 36,400 | | Total capitalized costs | | | 7,143 | | | — | | | 5,281 | | | 4,251 | | | 21,886 | | | — | | | 38,561 | |
| Accumulated depreciation and depletion | Accumulated depreciation and depletion | | 3,854 | | | — | | | 5,462 | | | — | | | 5,911 | | | — | | | 15,227 | | Accumulated depreciation and depletion | | 4,512 | | | — | | | 4,934 | | | — | | | 7,171 | | | — | | | 16,617 | |
| Net capitalized costs for equity companies | Net capitalized costs for equity companies | | 3,361 | | | — | | | 508 | | | 4,141 | | | 13,163 | | | — | | | 21,173 | | Net capitalized costs for equity companies | | 2,631 | | | — | | | 347 | | | 4,251 | | | 14,715 | | | — | | | 21,944 | |
| | | As of December 31, 2021 | | As of December 31, 2021 | |
| Consolidated Subsidiaries | Consolidated Subsidiaries | | | | | | | | | | | | | | | Consolidated Subsidiaries | | | | | | | | | | | | | | |
| As of December 31, 2019 | | | | | | | | | | | | | | | | |
| Property (acreage) costs | Property (acreage) costs | – Proved | | 19,046 | | | 2,579 | | | 49 | | | 988 | | | 2,971 | | | 719 | | | 26,352 | | Property (acreage) costs | – Proved | | 18,353 | | | 3,844 | | | 10 | | | 1,422 | | | 2,994 | | | 730 | | | 27,353 | |
| | | – Unproved | | 23,725 | | | 7,113 | | | 37 | | | 166 | | | 181 | | | 2,638 | | | 33,860 | | | – Unproved | | 21,146 | | | 6,231 | | | 37 | | | 119 | | | 5 | | | 2,675 | | | 30,213 | |
| Total property costs | Total property costs | | | 42,771 | | | 9,692 | | | 86 | | | 1,154 | | | 3,152 | | | 3,357 | | | 60,212 | | Total property costs | | | 39,499 | | | 10,075 | | | 47 | | | 1,541 | | | 2,999 | | | 3,405 | | | 57,566 | |
| Producing assets | Producing assets | | | 99,405 | | | 49,942 | | | 18,982 | | | 55,436 | | | 41,181 | | | 13,670 | | | 278,616 | | Producing assets | | | 101,211 | | | 52,092 | | | 14,420 | | | 56,168 | | | 44,228 | | | 14,944 | | | 283,063 | |
| Incomplete construction | Incomplete construction | | | 6,086 | | | 4,315 | | | 1,514 | | | 2,717 | | | 4,299 | | | 1,811 | | | 20,742 | | Incomplete construction | | | 4,125 | | | 7,047 | | | 889 | | | 1,428 | | | 2,888 | | | 2,044 | | | 18,421 | |
| Total capitalized costs | Total capitalized costs | | | 148,262 | | | 63,949 | | | 20,582 | | | 59,307 | | | 48,632 | | | 18,838 | | | 359,570 | | Total capitalized costs | | | 144,835 | | | 69,214 | | | 15,356 | | | 59,137 | | | 50,115 | | | 20,393 | | | 359,050 | |
| Accumulated depreciation and depletion | Accumulated depreciation and depletion | | 63,333 | | | 21,533 | | | 17,544 | | | 43,743 | | | 22,497 | | | 7,235 | | | 175,885 | | Accumulated depreciation and depletion | | 86,830 | | | 28,428 | | | 13,790 | | | 49,312 | | | 26,519 | | | 9,225 | | | 214,104 | |
| Net capitalized costs for consolidated subsidiaries | Net capitalized costs for consolidated subsidiaries | | 84,929 | | | 42,416 | | | 3,038 | | | 15,564 | | | 26,135 | | | 11,603 | | | 183,685 | | Net capitalized costs for consolidated subsidiaries | | 58,005 | | | 40,786 | | | 1,566 | | | 9,825 | | | 23,596 | | | 11,168 | | | 144,946 | |
| | Equity Companies | Equity Companies | | | | | | | | | | | | | | | | Equity Companies | | | | | | | | | | | | | | |
| As of December 31, 2019 | | | | | | | | | | | | | | | | |
| Property (acreage) costs | Property (acreage) costs | – Proved | | 99 | | | — | | | 4 | | | 308 | | | — | | | — | | | 411 | | Property (acreage) costs | – Proved | | 98 | | | — | | | 4 | | | 309 | | | — | | | — | | | 411 | |
| | | – Unproved | | 6 | | | — | | | — | | | 3,112 | | | — | | | — | | | 3,118 | | | – Unproved | | 4 | | | — | | | — | | | 3,111 | | | — | | | — | | | 3,115 | |
| Total property costs | Total property costs | | | 105 | | | — | | | 4 | | | 3,420 | | | — | | | — | | | 3,529 | | Total property costs | | | 102 | | | — | | | 4 | | | 3,420 | | | — | | | — | | | 3,526 | |
| Producing assets | Producing assets | | | 6,825 | | | — | | | 5,413 | | | — | | | 7,731 | | | — | | | 19,969 | | Producing assets | | | 6,946 | | | — | | | 5,487 | | | — | | | 8,676 | | | — | | | 21,109 | |
| Incomplete construction | Incomplete construction | | | 212 | | | — | | | 19 | | | 650 | | | 9,581 | | | — | | | 10,462 | | Incomplete construction | | | 103 | | | — | | | 23 | | | 809 | | | 11,716 | | | — | | | 12,651 | |
| Total capitalized costs | Total capitalized costs | | | 7,142 | | | — | | | 5,436 | | | 4,070 | | | 17,312 | | | — | | | 33,960 | | Total capitalized costs | | | 7,151 | | | — | | | 5,514 | | | 4,229 | | | 20,392 | | | — | | | 37,286 | |
| Accumulated depreciation and depletion | Accumulated depreciation and depletion | | 3,288 | | | — | | | 4,778 | | | — | | | 5,380 | | | — | | | 13,446 | | Accumulated depreciation and depletion | | 4,304 | | | — | | | 5,162 | | | — | | | 6,590 | | | — | | | 16,056 | |
| Net capitalized costs for equity companies | Net capitalized costs for equity companies | | 3,854 | | | — | | | 658 | | | 4,070 | | | 11,932 | | | — | | | 20,514 | | Net capitalized costs for equity companies | | 2,847 | | | — | | | 352 | | | 4,229 | | | 13,802 | | | — | | | 21,230 | |
Oil and Gas Exploration and Production Costs (continued)
The amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligation resulting from changes in cost estimates or abandonment date. Total consolidated costs incurred in 20202022 were $11,254$14,513 million, up $4,636 million from 2021, due primarily to higher development costs. In 2021, costs were $9,877 million, down $7,986$1,377 million from 2019,2020, due primarily to lower development costs, including lower asset retirement obligation cost estimates mainly in Angola. In 2019, costs were $19,240 million, up $2,912 million from 2018, due primarily to higher development costs, partially offset by lowerhigher acquisition costs of unproved properties. Total equity company costs incurred in 20202022 were $2,012$1,769 million, down $904up $318 million from 2019,2021, due primarily to lowerhigher development costs.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Costs Incurred in Property Acquisitions,
Exploration and Development Activities | | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total |
| | | | (millions of dollars) |
| During 2020 | | | | | | | | | | | | | | | |
| Consolidated Subsidiaries | | | | | | | | | | | | | | |
| Property acquisition costs | – Proved | | 1 | | | 30 | | | — | | | 344 | | | 7 | | | — | | | 382 | |
| | – Unproved | | 80 | | | 3 | | | — | | | 47 | | | — | | | — | | | 130 | |
| Exploration costs | | | 60 | | | 702 | | | 40 | | | 232 | | | 110 | | | 83 | | | 1,227 | |
| Development costs | | | 5,675 | | | 2,059 | | | 316 | | | (239) | | | 974 | | | 730 | | | 9,515 | |
| Total costs incurred for consolidated subsidiaries | | 5,816 | | | 2,794 | | | 356 | | | 384 | | | 1,091 | | | 813 | | | 11,254 | |
| | | | | | | | | | | | | | | |
| Equity Companies | | | | | | | | | | | | | | | |
| Property acquisition costs | – Proved | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | – Unproved | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Exploration costs | | | — | | | — | | | 2 | | | — | | | — | | | — | | | 2 | |
| Development costs | | | 135 | | | — | | | 20 | | | 71 | | | 1,784 | | | — | | | 2,010 | |
| Total costs incurred for equity companies | | 135 | | | — | | | 22 | | | 71 | | | 1,784 | | | — | | | 2,012 | |
| | | | | | | | | | | | | | | |
| During 2019 | | | | | | | | | | | | | | | |
| Consolidated Subsidiaries | | | | | | | | | | | | | | |
| Property acquisition costs | – Proved | | 12 | | | — | | | — | | | — | | | 26 | | | — | | | 38 | |
| | – Unproved | | 226 | | | 105 | | | 1 | | | 20 | | | — | | | — | | | 352 | |
| Exploration costs | | | 134 | | | 1,107 | | | 155 | | | 252 | | | 111 | | | 194 | | | 1,953 | |
| Development costs | | | 10,275 | | | 2,946 | | | 809 | | | 1,066 | | | 1,317 | | | 484 | | | 16,897 | |
| Total costs incurred for consolidated subsidiaries | | 10,647 | | | 4,158 | | | 965 | | | 1,338 | | | 1,454 | | | 678 | | | 19,240 | |
| | | | | | | | | | | | | | | |
| Equity Companies | | | | | | | | | | | | | | | |
| Property acquisition costs | – Proved | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | – Unproved | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Exploration costs | | | 1 | | | — | | | 5 | | | — | | | — | | | — | | | 6 | |
| Development costs | | | 241 | | | — | | | 15 | | | 69 | | | 2,585 | | | — | | | 2,910 | |
| Total costs incurred for equity companies | | 242 | | | — | | | 20 | | | 69 | | | 2,585 | | | — | | | 2,916 | |
| | | | | | | | | | | | | | | |
| During 2018 | | | | | | | | | | | | | | | |
| Consolidated Subsidiaries | | | | | | | | | | | | | | |
| Property acquisition costs | – Proved | | 7 | | | 3 | | | — | | | — | | | 321 | | | — | | | 331 | |
| | – Unproved | | 238 | | | 2,109 | | | — | | | 1 | | | — | | | — | | | 2,348 | |
| Exploration costs | | | 235 | | | 1,113 | | | 147 | | | 342 | | | 217 | | | 174 | | | 2,228 | |
| Development costs | | | 7,440 | | | 1,734 | | | 96 | | | 791 | | | 1,104 | | | 256 | | | 11,421 | |
| Total costs incurred for consolidated subsidiaries | | 7,920 | | | 4,959 | | | 243 | | | 1,134 | | | 1,642 | | | 430 | | | 16,328 | |
| | | | | | | | | | | | | | | |
| Equity Companies | | | | | | | | | | | | | | | |
| Property acquisition costs | – Proved | | 21 | | | — | | | — | | | — | | | — | | | — | | | 21 | |
| | – Unproved | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Exploration costs | | | 1 | | | — | | | 4 | | | — | | | 5 | | | — | | | 10 | |
| Development costs | | | 442 | | | — | | | 40 | | | 66 | | | 2,452 | | | — | | | 3,000 | |
| Total costs incurred for equity companies | | 464 | | | — | | | 44 | | | 66 | | | 2,457 | | | — | | | 3,031 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Costs Incurred in Property Acquisitions, Exploration and Development Activities (millions of dollars) | | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total |
| | | | | | | | | | | | | | | | |
| During 2022 | | | | | | | | | | | | | | | |
| Consolidated Subsidiaries | | | | | | | | | | | | | | |
| Property acquisition costs | – Proved | | 10 | | | 11 | | | — | | | 151 | | | 32 | | | — | | | 204 | |
| | – Unproved | | 19 | | | — | | | — | | | — | | | — | | | 7 | | | 26 | |
| Exploration costs | | | 27 | | | 736 | | | 71 | | | 145 | | | 38 | | | 62 | | | 1,079 | |
| Development costs | | | 5,821 | | | 4,759 | | | 161 | | | 533 | | | 1,490 | | | 440 | | | 13,204 | |
| Total costs incurred for consolidated subsidiaries | | 5,877 | | | 5,506 | | | 232 | | | 829 | | | 1,560 | | | 509 | | | 14,513 | |
| | | | | | | | | | | | | | | |
| Equity Companies | | | | | | | | | | | | | | |
| Property acquisition costs | – Proved | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | – Unproved | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Exploration costs | | | — | | | — | | | 1 | | | — | | | — | | | — | | | 1 | |
| Development costs | | | 95 | | | — | | | 13 | | | 22 | | | 1,638 | | | — | | | 1,768 | |
| Total costs incurred for equity companies | | 95 | | | — | | | 14 | | | 22 | | | 1,638 | | | — | | | 1,769 | |
| | | | | | | | | | | | | | | |
| During 2021 | | | | | | | | | | | | | | | |
| Consolidated Subsidiaries | | | | | | | | | | | | | | |
| Property acquisition costs | – Proved | | 37 | | | — | | | — | | | 90 | | | 15 | | | — | | | 142 | |
| | – Unproved | | 78 | | | 575 | | | — | | | — | | | — | | | 35 | | | 688 | |
| Exploration costs | | | 19 | | | 903 | | | 46 | | | 185 | | | 47 | | | 40 | | | 1,240 | |
| Development costs | | | 3,352 | | | 2,619 | | | 207 | | | 389 | | | 805 | | | 435 | | | 7,807 | |
| Total costs incurred for consolidated subsidiaries | | 3,486 | | | 4,097 | | | 253 | | | 664 | | | 867 | | | 510 | | | 9,877 | |
| | | | | | | | | | | | | | | |
| Equity Companies | | | | | | | | | | | | | | |
| Property acquisition costs | – Proved | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | – Unproved | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Exploration costs | | | — | | | — | | | 1 | | | — | | | — | | | — | | | 1 | |
| Development costs | | | 8 | | | — | | | 20 | | | 88 | | | 1,334 | | | — | | | 1,450 | |
| Total costs incurred for equity companies | | 8 | | | — | | | 21 | | | 88 | | | 1,334 | | | — | | | 1,451 | |
| | | | | | | | | | | | | | | |
| During 2020 | | | | | | | | | | | | | | | |
| Consolidated Subsidiaries | | | | | | | | | | | | | | |
| Property acquisition costs | – Proved | | 1 | | | 30 | | | — | | | 344 | | | 7 | | | — | | | 382 | |
| | – Unproved | | 80 | | | 3 | | | — | | | 47 | | | — | | | — | | | 130 | |
| Exploration costs | | | 60 | | | 702 | | | 40 | | | 232 | | | 110 | | | 83 | | | 1,227 | |
| Development costs | | | 5,675 | | | 2,059 | | | 316 | | | (239) | | | 974 | | | 730 | | | 9,515 | |
| Total costs incurred for consolidated subsidiaries | | 5,816 | | | 2,794 | | | 356 | | | 384 | | | 1,091 | | | 813 | | | 11,254 | |
| | | | | | | | | | | | | | | |
| Equity Companies | | | | | | | | | | | | | | |
| Property acquisition costs | – Proved | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | – Unproved | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Exploration costs | | | — | | | — | | | 2 | | | — | | | — | | | — | | | 2 | |
| Development costs | | | 135 | | | — | | | 20 | | | 71 | | | 1,784 | | | — | | | 2,010 | |
| Total costs incurred for equity companies | | 135 | | | — | | | 22 | | | 71 | | | 1,784 | | | — | | | 2,012 | |
Oil and Gas Reserves
The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2018, 20192020, 2021, and 2020.2022.
The definitions used are in accordance with the Securities and Exchange Commission’s Rule 4-10 (a) of Regulation S-X.
Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves.
In accordance with the Securities and Exchange Commission’s (SEC) rules, the Corporation’s year-end reserves volumes as well as the reserves change categories shown in the following tables are required to be calculated on the basis of average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. These reserves quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flows.
Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of (1) already available geologic, reservoir or production data, (2) new geologic, reservoir or production data or (3) changes in the average of first-of-month oil and natural gas prices and/or costs that are used in the estimation of reserves. Revisions can also result from significant changes in either development strategy or production equipment/facility capacity.
During the first and second quarters of 2020, the balance of supply and demand for petroleum and petrochemical products experienced two significant disruptive effects. On the demand side, the COVID-19 pandemic spread rapidly through most areas of the world resulting in substantial reductions in consumer and business activity and significantly reduced demand for crude oil, natural gas, and petroleum products. This reduction in demand coincided with announcements of increased production in certain key oil-producing countries which led to increases in inventory levels and sharp declines in prices for crude oil, natural gas, and petroleum products. Market conditions continued to reflect considerable uncertainty throughout 2020.
Primarily as a result of very low prices during 2020 and the effects of reductions in capital expenditures, under the SEC definition of proved reserves, certain quantities of crude oil, bitumen, and natural gas that qualified as proved reserves in prior years did not qualify as proved reserves at year-end 2020. Amounts no longer qualifying as proved reserves include 3.1 billion barrels of bitumen at Kearl, 0.6 billion barrels of bitumen at Cold Lake, and 0.5 billion oil-equivalent barrels in the United States. The Corporation's near-term reduction in capital expenditures resulted in a net reduction to estimates of proved reserves of approximately 1.5 billion oil-equivalent barrels, mainly related to unconventional drilling in the United States. Among the factors that could result in portions of these amounts being recognized again as proved reserves at some point in the future are a recovery in the SEC price basis, cost reductions, operating efficiencies, and increases in planned capital spending.
Proved reserves include 100 percent of each majority-owned affiliate’s participation in proved reserves and ExxonMobil’s ownership percentage of the proved reserves of equity companies, but exclude royalties and quantities due others. Natural gas reserves exclude the gaseous equivalent of liquids expected to be removed from the natural gas on leases, at field facilities and at gas processing plants. These liquids are included in net proved reserves of crude oil and natural gas liquids.
In the proved reserves tables, consolidated reserves and equity company reserves are reported separately. However, the Corporation does not view equity company reserves any differently than those from consolidated companies.
Reserves reported under production sharing and other nonconcessionary agreements are based on the economic interest as defined by the specific fiscal terms in the agreement. The production and reserves reported for these types of arrangements typically vary inversely with oil and natural gas price changes. As oil and natural gas prices increase, the cash flow and value received by the company increase; however, the production volumes and reserves required to achieve this value will typically be lower because of the higher prices. When prices decrease, the opposite effect generally occurs. The percentage of total liquids and natural gas proved reserves (consolidated subsidiaries plus equity companies) at year-end 20202022 that were associated with production sharing contract arrangements was 15 percent of liquids, 14 percent of natural gas and 1512 percent on an oil-equivalent basis (natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels).
Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Net proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Crude oil, natural gas liquids, and natural gas production quantities shown are the net volumes withdrawn from ExxonMobil’s oil and natural gas reserves. The natural gas quantities differ from the quantities of natural gas delivered for sale by the producing function as reported in the Operating InformationUpstream Operational Results due to volumes consumed or flared and inventory changes.
The changes between 2022 year-end proved reserves and 2021 year-end proved reserves include worldwide production of 1.4 billion oil-equivalent barrels (GOEB), asset sales of 0.4 GOEB primarily in the United States, and other downward revisions of 1.2 GOEB including the impact of the Russia expropriation (0.2 GOEB). Additions to proved reserves include 0.7 GOEB from purchases in Asia and 1.4 GOEB from extensions and discoveries primarily in the United States and Guyana.
The changes between 2021 year-end proved reserves and 2020 year-end proved reserves reflect upward revisions of 2.4 billion barrels of bitumen at Kearl and 0.5 billion barrels of bitumen at Cold Lake, primarily as a result of improved prices. In addition, extensions and discoveries of approximately 1.3 GOEB occurred primarily in the United States (0.9 GOEB), Brazil (0.2 GOEB) and Guyana (0.1 GOEB). Worldwide production in 2021 was 1.4 GOEB.
The downward revisions in 2020, primarily as a result of low prices during 2020, include 3.1 billion barrels of bitumen at Kearl, 0.6 billion barrels of bitumen at Cold Lake, and 0.5 GOEB in the United States. In addition, the Corporation’s near-term reduction in capital expenditures resulted in a net reduction to estimates of proved reserves of approximately 1.5 GOEB, mainly related to unconventional drilling in the United States.
| | Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves | Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves | | | | | | | Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves | | | | | | |
| | | Crude Oil | | Natural Gas
Liquids | | Bitumen | | Synthetic Oil | | Total | | Crude Oil | | Natural Gas
Liquids | | Bitumen | | Synthetic Oil | | Total |
| | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | Australia/
Oceania | Total | | Worldwide | | Canada/
Other
Americas | | Canada/
Other
Americas | | |
| (millions of barrels) | | (millions of barrels) | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | Australia/
Oceania | Total | | Worldwide | | Canada/
Other
Americas | | Canada/
Other
Americas | | Total |
| | | (millions of barrels) | |
| Net proved developed and undeveloped reserves of consolidated subsidiaries | Net proved developed and undeveloped reserves of consolidated subsidiaries | | | | | | | | | | | | | | | | | | Net proved developed and undeveloped reserves of consolidated subsidiaries | | | | | | | | | | | | | | | | | |
| January 1, 2018 | 2,695 | | | 410 | | | 119 | | | 729 | | | 3,496 | | 110 | | 7,559 | | | 1,258 | | | 1,012 | | | 473 | | | 10,302 | | |
| January 1, 2020 | | January 1, 2020 | 3,088 | | | 557 | | | 39 | | | 447 | | | 3,335 | | 94 | | 7,560 | | | 1,275 | | | 3,858 | | | 415 | | | 13,108 | |
| Revisions | Revisions | 61 | | | 28 | | | 63 | | | (9) | | | 4 | | 6 | | 153 | | | (16) | | | 3,286 | | | 15 | | | 3,438 | | Revisions | (1,139) | | | (14) | | | (9) | | | 19 | | | (20) | | (10) | | (1,173) | | | (209) | | | (3,653) | | | (79) | | | (5,114) | |
| Improved recovery | Improved recovery | — | | | — | | | 23 | | | 13 | | | — | | — | | 36 | | | — | | | — | | | — | | | 36 | | Improved recovery | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | |
| Purchases | Purchases | 8 | | | — | | | — | | | — | | | — | | — | | 8 | | | 2 | | | — | | | — | | | 10 | | Purchases | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | |
| Sales | Sales | (11) | | | — | | | (2) | | | — | | | — | | — | | (13) | | | (13) | | | — | | | — | | | (26) | | Sales | (1) | | | (2) | | | — | | | — | | | — | | — | | (3) | | | (3) | | | — | | | — | | | (6) | |
| Extensions/discoveries | Extensions/discoveries | 595 | | | 113 | | | — | | | 9 | | | 3 | | — | | 720 | | | 238 | | | — | | | — | | | 958 | | Extensions/discoveries | 187 | | | 1 | | | — | | | — | | | — | | — | | 188 | | | 65 | | | 1 | | | 133 | | | 387 | |
| Production | Production | (144) | | | (22) | | | (37) | | | (138) | | | (146) | | (11) | | (498) | | | (65) | | | (113) | | | (22) | | | (698) | | Production | (176) | | | (45) | | | (8) | | | (110) | | | (165) | | (10) | | (514) | | | (74) | | | (125) | | | (25) | | | (738) | |
| December 31, 2018 | 3,204 | | | 529 | | | 166 | | | 604 | | | 3,357 | | 105 | | 7,965 | | | 1,404 | | | 4,185 | | | 466 | | | 14,020 | | |
| December 31, 2020 | | December 31, 2020 | 1,959 | | | 497 | | | 22 | | | 356 | | | 3,150 | | 74 | | 6,058 | | | 1,054 | | | 81 | | | 444 | | | 7,637 | |
| Attributable to noncontrolling interests | Attributable to noncontrolling interests | | 44 | | | | 4 | | | 962 | | | 142 | | | | Attributable to noncontrolling interests | | 7 | | | 1 | | | 25 | | | 135 | | |
| | Proportional interest in proved reserves of equity companies | Proportional interest in proved reserves of equity companies | | | | | | | | | | | | | | | | | | Proportional interest in proved reserves of equity companies | | | | | | |
| January 1, 2018 | 245 | | | — | | | 15 | | | 6 | | | 1,097 | | — | | 1,363 | | | 364 | | | — | | | — | | | 1,727 | | |
| January 1, 2020 | | January 1, 2020 | 251 | | | — | | | 14 | | | 6 | | | 897 | | — | | 1,168 | | | 322 | | | — | | | — | | | 1,490 | |
| Revisions | Revisions | 28 | | | — | | | 1 | | | — | | | 6 | | — | | 35 | | | 1 | | | — | | | — | | | 36 | | Revisions | (102) | | | — | | | (4) | | | — | | | 4 | | — | | (102) | | | (22) | | | — | | | — | | | (124) | |
| Improved recovery | Improved recovery | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | | Improved recovery | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | |
| Purchases | Purchases | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | | Purchases | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | |
| Sales | Sales | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | | Sales | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | |
| Extensions/discoveries | Extensions/discoveries | 1 | | | — | | | — | | | — | | | — | | — | | 1 | | | — | | | — | | | — | | | 1 | | Extensions/discoveries | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | |
| Production | Production | (20) | | | — | | | (1) | | | — | | | (83) | | — | | (104) | | | (23) | | | — | | | — | | | (127) | | Production | (18) | | | — | | | (1) | | | — | | | (76) | | — | | (95) | | | (23) | | | — | | | — | | | (118) | |
| December 31, 2018 | 254 | | | — | | | 15 | | | 6 | | | 1,020 | | — | | 1,295 | | | 342 | | | — | | | — | | | 1,637 | | |
| Total liquids proved reserves at December 31, 2018 | 3,458 | | | 529 | | | 181 | | | 610 | | | 4,377 | | 105 | | 9,260 | | | 1,746 | | | 4,185 | | | 466 | | | 15,657 | | |
| December 31, 2020 | | December 31, 2020 | 131 | | | — | | | 9 | | | 6 | | | 825 | | — | | 971 | | | 277 | | | — | | | — | | | 1,248 | |
| Total liquids proved reserves at December 31, 2020 | | Total liquids proved reserves at December 31, 2020 | 2,090 | | | 497 | | | 31 | | | 362 | | | 3,975 | | 74 | | 7,029 | | | 1,331 | | | 81 | | | 444 | | | 8,885 | |
| | Net proved developed and undeveloped reserves of consolidated subsidiaries | Net proved developed and undeveloped reserves of consolidated subsidiaries | | | | | | | | | | | | | | | | | | Net proved developed and undeveloped reserves of consolidated subsidiaries | | | | | | | | | | | | | | | | | |
| January 1, 2019 | 3,204 | | | 529 | | | 166 | | | 604 | | | 3,357 | | 105 | | 7,965 | | | 1,404 | | | 4,185 | | | 466 | | | 14,020 | | |
| January 1, 2021 | | January 1, 2021 | 1,959 | | | 497 | | | 22 | | | 356 | | | 3,150 | | 74 | | 6,058 | | | 1,054 | | | 81 | | | 444 | | | 7,637 | |
| Revisions | Revisions | (677) | | | (66) | | | 20 | | | (25) | | | 136 | | — | | (612) | | | (305) | | | (213) | | | (27) | | | (1,157) | | Revisions | 47 | | | (2) | | | 15 | | | 67 | | | 36 | | 10 | | 173 | | | 4 | | | 2,944 | | | 17 | | | 3,138 | |
| Improved recovery | Improved recovery | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | | Improved recovery | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | 2 | | | — | | | 2 | |
| Purchases | Purchases | 20 | | | — | | | — | | | — | | | — | | — | | 20 | | | 12 | | | — | | | — | | | 32 | | Purchases | 5 | | | — | | | — | | | — | | | — | | — | | 5 | | | 1 | | | — | | | — | | | 6 | |
| Sales | Sales | (1) | | | — | | | (117) | | | — | | | — | | — | | (118) | | | (27) | | | — | | | — | | | (145) | | Sales | (27) | | | (8) | | | (28) | | | — | | | — | | — | | (63) | | | (20) | | | — | | | — | | | (83) | |
| Extensions/discoveries | Extensions/discoveries | 710 | | | 125 | | | — | | | — | | | — | | — | | 835 | | | 263 | | | — | | | — | | | 1,098 | | Extensions/discoveries | 499 | | | 329 | | | — | | | — | | | — | | — | | 828 | | | 183 | | | — | | | — | | | 1,011 | |
| Production | Production | (168) | | | (31) | | | (30) | | | (132) | | | (158) | | (11) | | (530) | | | (72) | | | (114) | | | (24) | | | (740) | | Production | (176) | | | (47) | | | (6) | | | (88) | | | (149) | | (10) | | (476) | | | (86) | | | (133) | | | (23) | | | (718) | |
| December 31, 2019 | 3,088 | | | 557 | | | 39 | | | 447 | | | 3,335 | | 94 | | 7,560 | | | 1,275 | | | 3,858 | | | 415 | | | 13,108 | | |
| December 31, 2021 | | December 31, 2021 | 2,307 | | | 769 | | | 3 | | | 335 | | | 3,037 | | 74 | | 6,525 | | | 1,136 | | | 2,894 | | | 438 | | | 10,993 | |
| Attributable to noncontrolling interests | Attributable to noncontrolling interests | | 21 | | | | 3 | | | 894 | | | 126 | | | | Attributable to noncontrolling interests | | 9 | | | 1 | | | 674 | | | 133 | | |
| | Proportional interest in proved reserves of equity companies | Proportional interest in proved reserves of equity companies | | | | | | | | | | | | | | | | | | Proportional interest in proved reserves of equity companies | | | | | | |
| January 1, 2019 | 254 | | | — | | | 15 | | | 6 | | | 1,020 | | — | | 1,295 | | | 342 | | | — | | | — | | | 1,637 | | |
| January 1, 2021 | | January 1, 2021 | 131 | | | — | | | 9 | | | 6 | | | 825 | | — | | 971 | | | 277 | | | — | | | — | | | 1,248 | |
| Revisions | Revisions | 15 | | | — | | | — | | | — | | | (38) | | — | | (23) | | | 3 | | | — | | | — | | | (20) | | Revisions | 38 | | | — | | | 2 | | | (1) | | | (8) | | — | | 31 | | | 15 | | | — | | | — | | | 46 | |
| Improved recovery | Improved recovery | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | | Improved recovery | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | |
| Purchases | Purchases | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | | Purchases | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | |
| Sales | Sales | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | | Sales | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | |
| Extensions/discoveries | Extensions/discoveries | 1 | | | — | | | — | | | — | | | — | | — | | 1 | | | — | | | — | | | — | | | 1 | | Extensions/discoveries | 2 | | | — | | | — | | | — | | | — | | — | | 2 | | | — | | | — | | | — | | | 2 | |
| Production | Production | (19) | | | — | | | (1) | | | — | | | (85) | | — | | (105) | | | (23) | | | — | | | — | | | (128) | | Production | (16) | | | — | | | (1) | | | — | | | (76) | | — | | (93) | | | (22) | | | — | | | — | | | (115) | |
| December 31, 2019 | 251 | | | — | | | 14 | | | 6 | | | 897 | | — | | 1,168 | | | 322 | | | — | | | — | | | 1,490 | | |
| Total liquids proved reserves at December 31, 2019 | 3,339 | | | 557 | | | 53 | | | 453 | | | 4,232 | | 94 | | 8,728 | | | 1,597 | | | 3,858 | | | 415 | | | 14,598 | | |
| December 31, 2021 | | December 31, 2021 | 155 | | | — | | | 10 | | | 5 | | | 741 | | — | | 911 | | | 270 | | | — | | | — | | | 1,181 | |
| Total liquids proved reserves at December 31, 2021 | | Total liquids proved reserves at December 31, 2021 | 2,462 | | | 769 | | | 13 | | | 340 | | | 3,778 | | 74 | | 7,436 | | | 1,406 | | | 2,894 | | | 438 | | | 12,174 | |
| | Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued) | Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued) | | | | | | | Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued) | | | | | | |
| | | Crude Oil | | Natural Gas
Liquids | | Bitumen | | Synthetic Oil | | Total | | Crude Oil | | Natural Gas
Liquids | | Bitumen | | Synthetic Oil | | Total |
| | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | Australia/
Oceania | Total | | Worldwide | | Canada/
Other
Americas | | Canada/
Other
Americas | | |
| (millions of barrels) | | (millions of barrels) | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | Australia/
Oceania | Total | | Worldwide | | Canada/
Other
Americas | | Canada/
Other
Americas | | Total |
| | | (millions of barrels) | | |
| Net proved developed and undeveloped reserves of consolidated subsidiaries | Net proved developed and undeveloped reserves of consolidated subsidiaries | | | | | | | | | | | | | | | | | | Net proved developed and undeveloped reserves of consolidated subsidiaries | | | | | | | | | | | | | | | | | |
| January 1, 2020 | 3,088 | | | 557 | | | 39 | | | 447 | | | 3,335 | | 94 | | 7,560 | | | 1,275 | | | 3,858 | | | 415 | | | 13,108 | | |
| January 1, 2022 | | January 1, 2022 | 2,307 | | | 769 | | | 3 | | | 335 | | | 3,037 | | 74 | | 6,525 | | | 1,136 | | | 2,894 | | | 438 | | | 10,993 | |
Revisions (1) | | Revisions (1) | (375) | | | 52 | | | 3 | | | 38 | | | (95) | | 2 | | (375) | | | (85) | | | (422) | | | (62) | | | (944) | |
| Improved recovery | | Improved recovery | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | |
| Purchases | | Purchases | 1 | | | — | | | — | | | — | | | — | | — | | 1 | | | — | | | — | | | — | | | 1 | |
| Sales | | Sales | (3) | | | (12) | | | — | | | (17) | | | — | | — | | (32) | | | (20) | | | — | | | — | | | (52) | |
| Extensions/discoveries | | Extensions/discoveries | 465 | | | 208 | | | — | | | — | | | — | | — | | 673 | | | 235 | | | 67 | | | — | | | 975 | |
| Production | | Production | (191) | | | (72) | | | (1) | | | (85) | | | (148) | | (10) | | (507) | | | (90) | | | (119) | | | (23) | | | (739) | |
| December 31, 2022 | | December 31, 2022 | 2,204 | | | 945 | | | 5 | | | 271 | | | 2,794 | | 66 | | 6,285 | | | 1,176 | | | 2,420 | | | 353 | | | 10,234 | |
| Attributable to noncontrolling interests | | Attributable to noncontrolling interests | | 14 | | | 554 | | | 107 | | |
| | Proportional interest in proved reserves of equity companies | | Proportional interest in proved reserves of equity companies | | | | | | | | | | | | | | | | | |
| January 1, 2022 | | January 1, 2022 | 155 | | | — | | | 10 | | | 5 | | | 741 | | — | | 911 | | | 270 | | | — | | | — | | | 1,181 | |
| Revisions | Revisions | (1,139) | | | (14) | | | (9) | | | 19 | | | (20) | | (10) | | (1,173) | | | (209) | | | (3,653) | | | (79) | | | (5,114) | | Revisions | (21) | | | — | | | (7) | | | — | | | (17) | | — | | (45) | | | (10) | | | — | | | — | | | (55) | |
| Improved recovery | Improved recovery | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | | Improved recovery | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | |
| Purchases | Purchases | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | | Purchases | — | | | — | | | — | | | — | | | 110 | | — | | 110 | | | 117 | | | — | | | — | | | 227 | |
| Sales | Sales | (1) | | | (2) | | | — | | | — | | | — | | — | | (3) | | | (3) | | | — | | | — | | | (6) | | Sales | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | |
| Extensions/discoveries | Extensions/discoveries | 187 | | | 1 | | | — | | | — | | | — | | — | | 188 | | | 65 | | | 1 | | | 133 | | | 387 | | Extensions/discoveries | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | |
| Production | Production | (176) | | | (45) | | | (8) | | | (110) | | | (165) | | (10) | | (514) | | | (74) | | | (125) | | | (25) | | | (738) | | Production | (15) | | | — | | | (1) | | | — | | | (78) | | — | | (94) | | | (22) | | | — | | | — | | | (116) | |
| December 31, 2020 | 1,959 | | | 497 | | | 22 | | | 356 | | | 3,150 | | 74 | | 6,058 | | | 1,054 | | | 81 | | | 444 | | | 7,637 | | |
| Attributable to noncontrolling interests | | 7 | | | | 1 | | | 25 | | | 135 | | | | |
| December 31, 2022 | | December 31, 2022 | 119 | | | — | | | 2 | | | 5 | | | 756 | | — | | 882 | | | 355 | | | — | | | — | | | 1,237 | |
| Total liquids proved reserves at December 31, 2022 | | Total liquids proved reserves at December 31, 2022 | 2,323 | | | 945 | | | 7 | | | 276 | | | 3,550 | | 66 | | 7,167 | | | 1,531 | | | 2,420 | | | 353 | | | 11,471 | |
| | Proportional interest in proved reserves of equity companies | | | | | | | | | | | | | | | | | | |
| January 1, 2020 | 251 | | | — | | | 14 | | | 6 | | | 897 | | — | | 1,168 | | | 322 | | | — | | | — | | | 1,490 | | |
| Revisions | (102) | | | — | | | (4) | | | — | | | 4 | | — | | (102) | | | (22) | | | — | | | — | | | (124) | | |
| Improved recovery | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | | |
| Purchases | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | | |
| Sales | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | | |
| Extensions/discoveries | — | | | — | | | — | | | — | | | — | | — | | — | | | — | | | — | | | — | | | — | | |
| Production | (18) | | | — | | | (1) | | | — | | | (76) | | — | | (95) | | | (23) | | | — | | | — | | | (118) | | |
| December 31, 2020 | 131 | | | — | | | 9 | | | 6 | | | 825 | | — | | 971 | | | 277 | | | — | | | — | | | 1,248 | | |
| Total liquids proved reserves at December 31, 2020 | 2,090 | | | 497 | | | 31 | | | 362 | | | 3,975 | | 74 | | 7,029 | | | 1,331 | | | 81 | | | 444 | | | 8,885 | | |
(1) Includes (118) million barrels in Russia which were expropriated. See Note 2: Russia. | | (1) Includes (118) million barrels in Russia which were expropriated. See Note 2: Russia. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued) | | | | | | |
| | Crude Oil and Natural Gas Liquids | | Bitumen | | Synthetic
Oil | | Total |
| | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total | | Canada/
Other
Americas | | Canada/
Other
Americas | |
| | (millions of barrels) |
Proved developed reserves, as of December 31, 2018 | | | | | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 1,696 | | | 153 | | | 123 | | | 578 | | | 2,285 | | | 118 | | | 4,953 | | | 3,880 | | | 466 | | | 9,299 | |
| Equity companies | 208 | | | — | | | 15 | | | — | | | 919 | | | — | | | 1,142 | | | — | | | — | | | 1,142 | |
| | | | | | | | | | | | | | | | | | | |
Proved undeveloped reserves, as of December 31, 2018 | | | | | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 2,616 | | | 403 | | | 78 | | | 111 | | | 1,173 | | | 35 | | | 4,416 | | | 305 | | | — | | | 4,721 | |
| Equity companies | 56 | | | — | | | — | | | 6 | | | 433 | | | — | | | 495 | | | — | | | — | | | 495 | |
Total liquids proved reserves at December 31, 2018 | 4,576 | | | 556 | | | 216 | | | 695 | | | 4,810 | | | 153 | | | 11,006 | | | 4,185 | | | 466 | | | 15,657 | |
| | | | | | | | | | | | | | | | | | | |
Proved developed reserves, as of December 31, 2019 | | | | | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 1,655 | | | 195 | | | 23 | | | 419 | | | 2,309 | | | 90 | | | 4,691 | | | 3,528 | | | 415 | | | 8,634 | |
| Equity companies | 200 | | | — | | | 13 | | | — | | | 727 | | | — | | | 940 | | | — | | | — | | | 940 | |
| | | | | | | | | | | | | | | | | | | |
Proved undeveloped reserves, as of December 31, 2019 | | | | | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 2,474 | | | 381 | | | 29 | | | 68 | | | 1,157 | | | 35 | | | 4,144 | | | 330 | | | — | | | 4,474 | |
| Equity companies | 60 | | | — | | | 1 | | | 6 | | | 483 | | | — | | | 550 | | | — | | | — | | | 550 | |
Total liquids proved reserves at December 31, 2019 | 4,389 | | | 576 | | | 66 | | | 493 | | | 4,676 | | | 125 | | | 10,325 | | | 3,858 | | | 415 | | | 14,598 | |
| | | | | | | | | | | | | | | | | | | |
Proved developed reserves, as of December 31, 2020 | | | | | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 1,473 | | | 293 | | | 13 | | | 345 | | | 2,299 | | | 67 | | | 4,490 | | | 76 | | | 311 | | | 4,877 | |
| Equity companies | 111 | | | — | | | 8 | | | — | | | 646 | | | — | | | 765 | | | — | | | — | | | 765 | |
| | | | | | | | | | | | | | | | | | | |
Proved undeveloped reserves, as of December 31, 2020 | | | | | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 1,342 | | | 209 | | | 16 | | | 42 | | | 975 | | | 38 | | | 2,622 | | | 5 | | | 133 | | | 2,760 | |
| Equity companies | 24 | | | — | | | 1 | | | 6 | | | 452 | | | — | | | 483 | | | — | | | — | | | 483 | |
Total liquids proved reserves at December 31, 2020 | 2,950 | | | 502 | | | 38 | | | 393 | | | 4,372 | | | 105 | | | 8,360 | | (1) | 81 | | | 444 | | | 8,885 | |
(1)See previous pages for natural gas liquids proved reserves attributable to consolidated subsidiaries and equity companies. For additional information on natural gas liquids proved reserves see Item 2. Properties in ExxonMobil’s 2020 Form 10-K. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued) | | | | | | |
| | Crude Oil and Natural Gas Liquids | | Bitumen | | Synthetic Oil | | Total |
| (millions of barrels) | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total | | Canada/
Other
Americas | | Canada/
Other
Americas | |
| | |
| As of December 31, 2020 | | | | | | | | | | | | | | | | | | | |
| Proved developed reserves | | | | | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 1,473 | | | 293 | | | 13 | | | 345 | | | 2,299 | | | 67 | | | 4,490 | | | 76 | | | 311 | | | 4,877 | |
| Equity companies | 111 | | | — | | | 8 | | | — | | | 646 | | | — | | | 765 | | | — | | | — | | | 765 | |
| Proved undeveloped reserves | | | | | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 1,342 | | | 209 | | | 16 | | | 42 | | | 975 | | | 38 | | | 2,622 | | | 5 | | | 133 | | | 2,760 | |
| Equity companies | 24 | | | — | | | 1 | | | 6 | | | 452 | | | — | | | 483 | | | — | | | — | | | 483 | |
| Total liquids proved reserves at December 31, 2020 | 2,950 | | | 502 | | | 38 | | | 393 | | | 4,372 | | | 105 | | | 8,360 | | | 81 | | | 444 | | | 8,885 | |
| | | | | | | | | | | | | | | | | | | |
| As of December 31, 2021 | | | | | | | | | | | | | | | | | | | |
| Proved developed reserves | | | | | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 1,663 | | | 268 | | | 3 | | | 330 | | | 2,154 | | | 63 | | | 4,481 | | | 2,635 | | | 326 | | | 7,442 | |
| Equity companies | 133 | | | — | | | 10 | | | — | | | 474 | | | — | | | 617 | | | — | | | — | | | 617 | |
| Proved undeveloped reserves | | | | | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 1,621 | | | 508 | | | — | | | 31 | | | 988 | | | 32 | | | 3,180 | | | 259 | | | 112 | | | 3,551 | |
| Equity companies | 28 | | | — | | | — | | | 5 | | | 531 | | | — | | | 564 | | | — | | | — | | | 564 | |
| Total liquids proved reserves at December 31, 2021 | 3,445 | | | 776 | | | 13 | | | 366 | | | 4,147 | | | 95 | | | 8,842 | | | 2,894 | | | 438 | | | 12,174 | |
| | | | | | | | | | | | | | | | | | | |
| As of December 31, 2022 | | | | | | | | | | | | | | | | | | | |
| Proved developed reserves | | | | | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 1,688 | | | 378 | | | 5 | | | 259 | | | 2,067 | | | 50 | | | 4,447 | | | 2,288 | | | 248 | | | 6,983 | |
| Equity companies | 126 | | | — | | | 2 | | | 5 | | | 360 | | | — | | | 493 | | | — | | | — | | | 493 | |
| Proved undeveloped reserves | | | | | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 1,568 | | | 568 | | | — | | | 35 | | | 813 | | | 30 | | | 3,014 | | | 132 | | | 105 | | | 3,251 | |
| Equity companies | — | | | — | | | — | | | — | | | 744 | | | — | | | 744 | | | — | | | — | | | 744 | |
| Total liquids proved reserves at December 31, 2022 | 3,382 | | | 946 | | | 7 | | | 299 | | | 3,984 | | | 80 | | | 8,698 | | (1) | 2,420 | | | 353 | | | 11,471 | |
| | | | | | | | | | | | | | | | | | | |
(1) See previous pages for natural gas liquids proved reserves attributable to consolidated subsidiaries and equity companies. For additional information on natural gas liquids proved reserves see Item 2. Properties in ExxonMobil’s 2022 Form 10-K. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural Gas and Oil-Equivalent Proved Reserves | | | | | | | | | | | | |
| | Natural Gas | | |
| | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total | | Oil-Equivalent Total All Products (1) |
| | (billions of cubic feet) | | (millions of oil-equivalent barrels) |
Net proved developed and undeveloped
reserves of consolidated subsidiaries | | | | | | | | | | | | | | |
| January 1, 2018 | 19,033 | | | 1,372 | | | 1,368 | | | 595 | | | 4,340 | | | 6,894 | | | 33,602 | | | 15,903 | |
| Revisions | (98) | | | (29) | | | 306 | | | 38 | | | (147) | | | 1,065 | | | 1,135 | | | 3,626 | |
| Improved recovery | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 36 | |
| Purchases | 104 | | | — | | | — | | | — | | | — | | | — | | | 104 | | | 27 | |
| Sales | (264) | | | (3) | | | (4) | | | — | | | — | | | — | | | (271) | | | (71) | |
| Extensions/discoveries | 3,658 | | | 506 | | | 3 | | | — | | | 1 | | | 7 | | | 4,175 | | | 1,654 | |
| Production | (1,030) | | | (102) | | | (361) | | | (45) | | | (353) | | | (504) | | | (2,395) | | | (1,097) | |
| December 31, 2018 | 21,403 | | | 1,744 | | | 1,312 | | | 588 | | | 3,841 | | | 7,462 | | | 36,350 | | | 20,078 | |
| Attributable to noncontrolling interests | | | 334 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Proportional interest in proved reserves
of equity companies | | | | | | | | | | | | | | | |
| January 1, 2018 | 223 | | | — | | | 6,164 | | | 914 | | | 14,248 | | | — | | | 21,549 | | | 5,318 | |
| Revisions | 12 | | | — | | | (4,801) | | | (51) | | | 102 | | | — | | | (4,738) | | | (753) | |
| Improved recovery | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Purchases | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Sales | — | | | — | | | (38) | | | — | | | — | | | — | | | (38) | | | (6) | |
| Extensions/discoveries | 2 | | | — | | | — | | | — | | | — | | | — | | | 2 | | | 1 | |
| Production | (12) | | | — | | | (268) | | | — | | | (1,029) | | | — | | | (1,309) | | | (345) | |
| December 31, 2018 | 225 | | | — | | | 1,057 | | | 863 | | | 13,321 | | | — | | | 15,466 | | | 4,215 | |
| Total proved reserves at December 31, 2018 | 21,628 | | | 1,744 | | | 2,369 | | | 1,451 | | | 17,162 | | | 7,462 | | | 51,816 | | | 24,293 | |
| | | | | | | | | | | | | | | |
Net proved developed and undeveloped
reserves of consolidated subsidiaries | | | | | | | | | | | | | | | |
| January 1, 2019 | 21,403 | | | 1,744 | | | 1,312 | | | 588 | | | 3,841 | | | 7,462 | | | 36,350 | | | 20,078 | |
| Revisions | (3,213) | | | (301) | | | 41 | | | (171) | | | 953 | | | 39 | | | (2,652) | | | (1,599) | |
| Improved recovery | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Purchases | 85 | | | — | | | — | | | — | | | — | | | — | | | 85 | | | 47 | |
| Sales | (297) | | | (29) | | | (416) | | | — | | | — | | | — | | | (742) | | | (269) | |
| Extensions/discoveries | 2,151 | | | 166 | | | — | | | — | | | — | | | — | | | 2,317 | | | 1,484 | |
| Production | (1,103) | | | (114) | | | (316) | | | (40) | | | (361) | | | (500) | | | (2,434) | | | (1,145) | |
| December 31, 2019 | 19,026 | | | 1,466 | | | 621 | | | 377 | | | 4,433 | | | 7,001 | | | 32,924 | | | 18,596 | |
| Attributable to noncontrolling interests | | | 256 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Proportional interest in proved reserves
of equity companies | | | | | | | | | | | | | | | |
| January 1, 2019 | 225 | | | — | | | 1,057 | | | 863 | | | 13,321 | | | — | | | 15,466 | | | 4,215 | |
| Revisions | (1) | | | — | | | (238) | | | 45 | | | 142 | | | — | | | (52) | | | (29) | |
| Improved recovery | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Purchases | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Sales | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Extensions/discoveries | 1 | | | — | | | — | | | — | | | — | | | — | | | 1 | | | 1 | |
| Production | (12) | | | — | | | (238) | | | — | | | (1,009) | | | — | | | (1,259) | | | (338) | |
| December 31, 2019 | 213 | | | — | | | 581 | | | 908 | | | 12,454 | | | — | | | 14,156 | | | 3,849 | |
| Total proved reserves at December 31, 2019 | 19,239 | | | 1,466 | | | 1,202 | | | 1,285 | | | 16,887 | | | 7,001 | | | 47,080 | | | 22,445 | |
(1)Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural Gas and Oil-Equivalent Proved Reserves | | | | | | | | | | | | |
| | Natural Gas (billions of cubic feet) | | Oil-Equivalent Total All Products (1)
(millions of oil-equivalent barrels) |
| United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total | |
| | | | |
| Net proved developed and undeveloped reserves of consolidated subsidiaries | | | | | | | | | | | | | | |
| January 1, 2020 | 19,026 | | | 1,466 | | | 621 | | | 377 | | | 4,433 | | | 7,001 | | | 32,924 | | | 18,596 | |
| Revisions | (4,904) | | | (753) | | | (4) | | | (23) | | | 245 | | | (405) | | | (5,844) | | | (6,088) | |
| Improved recovery | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Purchases | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Sales | (35) | | | (30) | | | — | | | — | | | — | | | — | | | (65) | | | (17) | |
| Extensions/discoveries | 433 | | | 1 | | | 1 | | | — | | | — | | | — | | | 435 | | | 459 | |
| Production | (1,081) | | | (123) | | | (177) | | | (34) | | | (369) | | | (462) | | | (2,246) | | | (1,113) | |
| December 31, 2020 | 13,439 | | | 561 | | | 441 | | | 320 | | | 4,309 | | | 6,134 | | | 25,204 | | | 11,837 | |
| Attributable to noncontrolling interests | | | 84 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Proportional interest in proved reserves of equity companies | | | | | | | | | | | | | | | |
| January 1, 2020 | 213 | | | — | | | 581 | | | 908 | | | 12,454 | | | — | | | 14,156 | | | 3,849 | |
| Revisions | (99) | | | — | | | (95) | | | 9 | | | (106) | | | — | | | (291) | | | (172) | |
| Improved recovery | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Purchases | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Sales | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Extensions/discoveries | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Production | (12) | | | — | | | (126) | | | — | | | (971) | | | — | | | (1,109) | | | (303) | |
| December 31, 2020 | 102 | | | — | | | 360 | | | 917 | | | 11,377 | | | — | | | 12,756 | | | 3,374 | |
| Total proved reserves at December 31, 2020 | 13,541 | | | 561 | | | 801 | | | 1,237 | | | 15,686 | | | 6,134 | | | 37,960 | | | 15,211 | |
| | | | | | | | | | | | | | | |
| Net proved developed and undeveloped reserves of consolidated subsidiaries | | | | | | | | | | | | | | | |
| January 1, 2021 | 13,439 | | | 561 | | | 441 | | | 320 | | | 4,309 | | | 6,134 | | | 25,204 | | | 11,837 | |
| Revisions | 1,432 | | | 305 | | | 210 | | | 39 | | | (276) | | | 712 | | | 2,422 | | | 3,542 | |
| Improved recovery | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 2 | |
| Purchases | 3 | | | — | | | — | | | — | | | — | | | — | | | 3 | | | 6 | |
| Sales | (164) | | | (18) | | | (120) | | | — | | | — | | | — | | | (302) | | | (134) | |
| Extensions/discoveries | 1,381 | | | 163 | | | — | | | — | | | — | | | — | | | 1,544 | | | 1,269 | |
| Production | (1,103) | | | (92) | | | (148) | | | (42) | | | (340) | | | (483) | | | (2,208) | | | (1,086) | |
| December 31, 2021 | 14,988 | | | 919 | | | 383 | | | 317 | | | 3,693 | | | 6,363 | | | 26,663 | | | 15,436 | |
| Attributable to noncontrolling interests | | | 124 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Proportional interest in proved reserves of equity companies | | | | | | | | | | | | | | | |
| January 1, 2021 | 102 | | | — | | | 360 | | | 917 | | | 11,377 | | | — | | | 12,756 | | | 3,374 | |
| Revisions | 44 | | | — | | | 206 | | | (111) | | | (236) | | | — | | | (97) | | | 30 | |
| Improved recovery | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Purchases | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Sales | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Extensions/discoveries | 5 | | | — | | | — | | | — | | | — | | | — | | | 5 | | | 3 | |
| Production | (11) | | | — | | | (158) | | | — | | | (983) | | | — | | | (1,152) | | | (307) | |
| December 31, 2021 | 140 | | | — | | | 408 | | | 806 | | | 10,158 | | | — | | | 11,512 | | | 3,100 | |
| Total proved reserves at December 31, 2021 | 15,128 | | | 919 | | | 791 | | | 1,123 | | | 13,851 | | | 6,363 | | | 38,175 | | | 18,536 | |
| | | | | | | | | | | | | | | |
(1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural Gas and Oil-Equivalent Proved Reserves (continued) | | | | | | | | | | |
| | Natural Gas | | |
| | United States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total | | Oil-Equivalent Total All Products (1) |
| | (billions of cubic feet) | | (millions of oil-equivalent barrels) |
Net proved developed and undeveloped
reserves of consolidated subsidiaries | | | | | | | | | | | | | | | |
| January 1, 2020 | 19,026 | | | 1,466 | | | 621 | | | 377 | | | 4,433 | | | 7,001 | | | 32,924 | | | 18,596 | |
| Revisions | (4,904) | | | (753) | | | (4) | | | (23) | | | 245 | | | (405) | | | (5,844) | | | (6,088) | |
| Improved recovery | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Purchases | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Sales | (35) | | | (30) | | | — | | | — | | | — | | | — | | | (65) | | | (17) | |
| Extensions/discoveries | 433 | | | 1 | | | 1 | | | — | | | — | | | — | | | 435 | | | 459 | |
| Production | (1,081) | | | (123) | | | (177) | | | (34) | | | (369) | | | (462) | | | (2,246) | | | (1,113) | |
| December 31, 2020 | 13,439 | | | 561 | | | 441 | | | 320 | | | 4,309 | | | 6,134 | | | 25,204 | | | 11,837 | |
| Attributable to noncontrolling interests | | | 84 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Proportional interest in proved reserves
of equity companies | | | | | | | | | | | | | | | |
| January 1, 2020 | 213 | | | — | | | 581 | | | 908 | | | 12,454 | | | — | | | 14,156 | | | 3,849 | |
| Revisions | (99) | | | — | | | (95) | | | 9 | | | (106) | | | — | | | (291) | | | (172) | |
| Improved recovery | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Purchases | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Sales | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Extensions/discoveries | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Production | (12) | | | — | | | (126) | | | — | | | (971) | | | — | | | (1,109) | | | (303) | |
| December 31, 2020 | 102 | | | — | | | 360 | | | 917 | | | 11,377 | | | — | | | 12,756 | | | 3,374 | |
| Total proved reserves at December 31, 2020 | 13,541 | | | 561 | | | 801 | | | 1,237 | | | 15,686 | | | 6,134 | | | 37,960 | | | 15,211 | |
(1)Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural Gas and Oil-Equivalent Proved Reserves (continued) | | | | | | | | | | |
| | Natural Gas (billions of cubic feet) | | Oil-Equivalent Total All Products (1)
(millions of oil-equivalent barrels) |
| | United States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total | |
| | | |
| Net proved developed and undeveloped reserves of consolidated subsidiaries | | | | | | | | | | | | | | | |
| January 1, 2022 | 14,988 | | | 919 | | | 383 | | | 317 | | | 3,693 | | | 6,363 | | | 26,663 | | | 15,436 | |
Revisions (2) | (990) | | | (38) | | | 149 | | | 49 | | | (307) | | | 187 | | | (950) | | | (1,102) | |
| Improved recovery | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Purchases | 2 | | | — | | | — | | | — | | | — | | | — | | | 2 | | | 1 | |
| Sales | (1,551) | | | (272) | | | — | | | (1) | | | — | | | — | | | (1,824) | | | (356) | |
| Extensions/discoveries | 2,232 | | | 175 | | | — | | | — | | | — | | | — | | | 2,407 | | | 1,376 | |
| Production | (1,036) | | | (76) | | | (119) | | | (53) | | | (325) | | | (542) | | | (2,151) | | | (1,097) | |
| December 31, 2022 | 13,645 | | | 708 | | | 413 | | | 312 | | | 3,061 | | | 6,008 | | | 24,147 | | | 14,258 | |
| Attributable to noncontrolling interests | | | 77 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Proportional interest in proved reserves of equity companies | | | | | | | | | | | | | | | |
| January 1, 2022 | 140 | | | — | | | 408 | | | 806 | | | 10,158 | | | — | | | 11,512 | | | 3,100 | |
| Revisions | (3) | | | — | | | 104 | | | (132) | | | 29 | | | — | | | (2) | | | (55) | |
| Improved recovery | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Purchases | — | | | — | | | — | | | — | | | 3,101 | | | — | | | 3,101 | | | 744 | |
| Sales | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Extensions/discoveries | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Production | (10) | | | — | | | (132) | | | (11) | | | (979) | | | — | | | (1,132) | | | (305) | |
| December 31, 2022 | 127 | | | — | | | 380 | | | 663 | | | 12,309 | | | — | | | 13,479 | | | 3,484 | |
| Total proved reserves at December 31, 2022 | 13,772 | | | 708 | | | 793 | | | 975 | | | 15,370 | | | 6,008 | | | 37,626 | | | 17,742 | |
| | | | | | | | | | | | | | | |
(1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels. (2) Includes (199) billion cubic feet of natural gas and (152) million total oil-equivalent barrels in Russia which were expropriated. See Note 2: Russia. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural Gas and Oil-Equivalent Proved Reserves (continued) | | | | | | | | | | |
| | Natural Gas | | |
| | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total | | Oil-Equivalent Total All Products (1) |
| | (billions of cubic feet) | | (millions of oil-equivalent barrels) |
Proved developed reserves, as of December 31, 2018 | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 12,538 | | | 605 | | | 1,116 | | | 581 | | | 3,618 | | | 4,336 | | | 22,794 | | | 13,098 | |
| Equity companies | 152 | | | — | | | 988 | | | — | | | 11,951 | | | — | | | 13,091 | | | 3,324 | |
| | | | | | | | | | | | | | | |
Proved undeveloped reserves, as of December 31, 2018 | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 8,865 | | | 1,139 | | | 196 | | | 7 | | | 223 | | | 3,126 | | | 13,556 | | | 6,980 | |
| Equity companies | 73 | | | — | | | 69 | | | 863 | | | 1,370 | | | — | | | 2,375 | | | 891 | |
| Total proved reserves at December 31, 2018 | 21,628 | | | 1,744 | | | 2,369 | | | 1,451 | | | 17,162 | | | 7,462 | | | 51,816 | | | 24,293 | |
| | | | | | | | | | | | | | | |
Proved developed reserves, as of December 31, 2019 | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 11,882 | | | 613 | | | 502 | | | 377 | | | 3,508 | | | 3,765 | | | 20,647 | | | 12,075 | |
| Equity companies | 143 | | | — | | | 505 | | | — | | | 9,859 | | | — | | | 10,507 | | | 2,691 | |
| | | | | | | | | | | | | | | |
Proved undeveloped reserves, as of December 31, 2019 | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 7,144 | | | 853 | | | 119 | | | — | | | 925 | | | 3,236 | | | 12,277 | | | 6,521 | |
| Equity companies | 70 | | | — | | | 76 | | | 908 | | | 2,595 | | | — | | | 3,649 | | | 1,158 | |
| Total proved reserves at December 31, 2019 | 19,239 | | | 1,466 | | | 1,202 | | | 1,285 | | | 16,887 | | | 7,001 | | | 47,080 | | | 22,445 | |
| | | | | | | | | | | | | | | |
Proved developed reserves, as of December 31, 2020 | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 10,375 | | | 472 | | | 399 | | | 318 | | | 3,323 | | | 3,344 | | | 18,231 | | | 7,915 | |
| Equity companies | 83 | | | — | | | 293 | | | — | | | 8,992 | | | — | | | 9,368 | | | 2,326 | |
| | | | | | | | | | | | | | | |
Proved undeveloped reserves, as of December 31, 2020 | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 3,064 | | | 89 | | | 42 | | | 2 | | | 986 | | | 2,790 | | | 6,973 | | | 3,922 | |
| Equity companies | 19 | | | — | | | 67 | | | 917 | | | 2,385 | | | — | | | 3,388 | | | 1,048 | |
| Total proved reserves at December 31, 2020 | 13,541 | | | 561 | | | 801 | | | 1,237 | | | 15,686 | | | 6,134 | | | 37,960 | | | 15,211 | |
(1)Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural Gas and Oil-Equivalent Proved Reserves (continued) | | | | | | | | | | |
| | Natural Gas (billions of cubic feet) | | Oil-Equivalent Total All Products (1)
(millions of oil-equivalent barrels) |
| | United
States | | Canada/
Other
Americas | | Europe | | Africa | | Asia | | Australia/
Oceania | | Total | |
| | | |
| As of December 31, 2020 | | | | | | | | | | | | | | | |
| Proved developed reserves | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 10,375 | | | 472 | | | 399 | | | 318 | | | 3,323 | | | 3,344 | | | 18,231 | | | 7,915 | |
| Equity companies | 83 | | | — | | | 293 | | | — | | | 8,992 | | | — | | | 9,368 | | | 2,326 | |
| Proved undeveloped reserves | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 3,064 | | | 89 | | | 42 | | | 2 | | | 986 | | | 2,790 | | | 6,973 | | | 3,922 | |
| Equity companies | 19 | | | — | | | 67 | | | 917 | | | 2,385 | | | — | | | 3,388 | | | 1,048 | |
| Total proved reserves at December 31, 2020 | 13,541 | | | 561 | | | 801 | | | 1,237 | | | 15,686 | | | 6,134 | | | 37,960 | | | 15,211 | |
| | | | | | | | | | | | | | | |
| As of December 31, 2021 | | | | | | | | | | | | | | | |
| Proved developed reserves | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 11,287 | | | 574 | | | 377 | | | 315 | | | 2,527 | | | 3,513 | | | 18,593 | | | 10,540 | |
| Equity companies | 117 | | | — | | | 339 | | | — | | | 6,017 | | | — | | | 6,473 | | | 1,696 | |
| Proved undeveloped reserves | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 3,701 | | | 345 | | | 6 | | | 2 | | | 1,166 | | | 2,850 | | | 8,070 | | | 4,896 | |
| Equity companies | 23 | | | — | | | 69 | | | 806 | | | 4,141 | | | — | | | 5,039 | | | 1,404 | |
| Total proved reserves at December 31, 2021 | 15,128 | | | 919 | | | 791 | | | 1,123 | | | 13,851 | | | 6,363 | | | 38,175 | | | 18,536 | |
| | | | | | | | | | | | | | | |
| As of December 31, 2022 | | | | | | | | | | | | | | | |
| Proved developed reserves | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 9,577 | | | 371 | | | 408 | | | 307 | | | 2,037 | | | 3,162 | | | 15,862 | | | 9,627 | |
| Equity companies | 127 | | | — | | | 326 | | | 663 | | | 5,020 | | | — | | | 6,136 | | | 1,516 | |
| Proved undeveloped reserves | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | 4,068 | | | 337 | | | 5 | | | 5 | | | 1,024 | | | 2,846 | | | 8,285 | | | 4,631 | |
| Equity companies | — | | | — | | | 54 | | | — | | | 7,289 | | | — | | | 7,343 | | | 1,968 | |
| Total proved reserves at December 31, 2022 | 13,772 | | | 708 | | | 793 | | | 975 | | | 15,370 | | | 6,008 | | | 37,626 | | | 17,742 | |
| | | | | | | | | | | | | | | |
(1) Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels. |
Standardized Measure of Discounted Future Cash Flows
As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates, and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment, and rehabilitation obligations. The Corporation believes the standardized measure does not provide a reliable estimate of the Corporation’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Standardized Measure of Discounted
Future Cash Flows | United States | | Canada/Other Americas (1) | | Europe | | Africa | | Asia | | Australia/ Oceania | | Total |
| | (millions of dollars) |
| Consolidated Subsidiaries | | | | | | | | | | | | | |
| As of December 31, 2018 | | | | | | | | | | | | | |
| Future cash inflows from sales of oil and gas | 265,527 | | | 204,596 | | | 23,263 | | | 47,557 | | | 241,410 | | | 67,041 | | | 849,394 | |
| Future production costs | 96,489 | | | 125,469 | | | 5,023 | | | 16,019 | | | 61,674 | | | 18,081 | | | 322,755 | |
| Future development costs | 54,457 | | | 29,759 | | | 7,351 | | | 8,356 | | | 13,907 | | | 8,047 | | | 121,877 | |
| Future income tax expenses | 25,365 | | | 9,024 | | | 8,255 | | | 10,491 | | | 124,043 | | | 10,499 | | | 187,677 | |
| Future net cash flows | 89,216 | | | 40,344 | | | 2,634 | | | 12,691 | | | 41,786 | | | 30,414 | | | 217,085 | |
| Effect of discounting net cash flows at 10% | 49,176 | | | 22,315 | | | (6) | | | 2,957 | | | 21,509 | | | 15,030 | | | 110,981 | |
| Discounted future net cash flows | 40,040 | | | 18,029 | | | 2,640 | | | 9,734 | | | 20,277 | | | 15,384 | | | 106,104 | |
| | | | | | | | | | | | | |
| Equity Companies | | | | | | | | | | | | | |
| As of December 31, 2018 | | | | | | | | | | | | | |
| Future cash inflows from sales of oil and gas | 17,730 | | | — | | | 7,264 | | | 3,777 | | | 165,471 | | | — | | | 194,242 | |
| Future production costs | 6,474 | | | — | | | 2,157 | | | 249 | | | 61,331 | | | — | | | 70,211 | |
| Future development costs | 3,359 | | | — | | | 1,165 | | | 370 | | | 10,295 | | | — | | | 15,189 | |
| Future income tax expenses | — | | | — | | | 1,612 | | | 964 | | | 30,662 | | | — | | | 33,238 | |
| Future net cash flows | 7,897 | | | — | | | 2,330 | | | 2,194 | | | 63,183 | | | — | | | 75,604 | |
| Effect of discounting net cash flows at 10% | 4,104 | | | — | | | 713 | | | 1,712 | | | 31,503 | | | — | | | 38,032 | |
| Discounted future net cash flows | 3,793 | | | — | | | 1,617 | | | 482 | | | 31,680 | | | — | | | 37,572 | |
| | | | | | | | | | | | | |
Total consolidated and equity interests in standardized measure of discounted future net cash flows | 43,833 | | | 18,029 | | | 4,257 | | | 10,216 | | | 51,957 | | | 15,384 | | | 143,676 | |
(1)Includes discounted future net cash flows attributable to noncontrolling interests in ExxonMobil consolidated subsidiaries of $2,823 million in 2018. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Standardized Measure of Discounted Future Cash Flows (millions of dollars) | United States | | Canada/Other Americas (1) | | Europe | | Africa | | Asia | | Australia/ Oceania | | Total |
| | | | | | | | | | | | | | |
| As of December 31, 2020 | | | | | | | | | | | | | |
| Consolidated Subsidiaries | | | | | | | | | | | | | |
| Future cash inflows from sales of oil and gas | 93,520 | | | 38,193 | | | 2,734 | | | 15,411 | | | 138,080 | | | 19,794 | | | 307,732 | |
| Future production costs | 53,635 | | | 19,971 | | | 1,815 | | | 6,527 | | | 42,378 | | | 3,188 | | | 127,514 | |
| Future development costs | 27,668 | | | 10,991 | | | 4,244 | | | 6,223 | | | 13,432 | | | 7,580 | | | 70,138 | |
| Future income tax expenses | (2,509) | | | 851 | | | (1,121) | | | 916 | | | 62,223 | | | 1,381 | | | 61,741 | |
| Future net cash flows | 14,726 | | | 6,380 | | | (2,204) | | | 1,745 | | | 20,047 | | | 7,645 | | | 48,339 | |
| Effect of discounting net cash flows at 10% | 8,564 | | | 1,116 | | | (1,565) | | | (511) | | | 10,557 | | | 3,624 | | | 21,785 | |
| Discounted future net cash flows | 6,162 | | | 5,264 | | | (639) | | | 2,256 | | | 9,490 | | | 4,021 | | | 26,554 | |
| | | | | | | | | | | | | |
| Equity Companies | | | | | | | | | | | | | |
| Future cash inflows from sales of oil and gas | 5,304 | | | — | | | 1,511 | | | 740 | | | 63,105 | | | — | | | 70,660 | |
| Future production costs | 3,467 | | | — | | | 694 | | | 247 | | | 29,170 | | | — | | | 33,578 | |
| Future development costs | 2,243 | | | — | | | 1,054 | | | 163 | | | 9,929 | | | — | | | 13,389 | |
| Future income tax expenses | — | | | — | | | (115) | | | 42 | | | 8,088 | | | — | | | 8,015 | |
| Future net cash flows | (406) | | | — | | | (122) | | | 288 | | | 15,918 | | | — | | | 15,678 | |
| Effect of discounting net cash flows at 10% | (378) | | | — | | | (86) | | | 258 | | | 7,443 | | | — | | | 7,237 | |
| Discounted future net cash flows | (28) | | | — | | | (36) | | | 30 | | | 8,475 | | | — | | | 8,441 | |
| | | | | | | | | | | | | |
| Total consolidated and equity interests in standardized measure of discounted future net cash flows | 6,134 | | | 5,264 | | | (675) | | | 2,286 | | | 17,965 | | | 4,021 | | | 34,995 | |
| | | | | | | | | | | | | |
(1) Includes discounted future net cash flows attributable to noncontrolling interests in ExxonMobil consolidated subsidiaries of $(150) million in 2020. |
| Standardized Measure of Discounted
Future Cash Flows (continued) | United States | | Canada/Other Americas (1) | | Europe | | Africa | | Asia | | Australia/ Oceania | | Total | |
Standardized Measure of Discounted Future Cash Flows (continued) (millions of dollars) | | Standardized Measure of Discounted Future Cash Flows (continued) (millions of dollars) | United States | | Canada/Other Americas (1) | | Europe | | Africa | | Asia | | Australia/ Oceania | | Total |
| | | (millions of dollars) | | |
| As of December 31, 2021 | | As of December 31, 2021 | |
| Consolidated Subsidiaries | Consolidated Subsidiaries | | | | | | | | | | | | | | Consolidated Subsidiaries | | | | | | | | | | | | | |
| As of December 31, 2019 | | | | | | | | | | | | | | |
| Future cash inflows from sales of oil and gas | Future cash inflows from sales of oil and gas | 208,981 | | | 190,604 | | | 5,789 | | | 30,194 | | | 215,837 | | | 43,599 | | | 695,004 | | Future cash inflows from sales of oil and gas | 217,023 | | | 209,711 | | | 4,322 | | | 24,812 | | | 211,255 | | | 69,015 | | | 736,138 | |
| Future production costs | Future production costs | 90,448 | | | 133,606 | | | 3,209 | | | 10,177 | | | 58,255 | | | 12,980 | | | 308,675 | | Future production costs | 63,464 | | | 111,468 | | | 1,142 | | | 7,700 | | | 55,241 | | | 14,880 | | | 253,895 | |
| Future development costs | Future development costs | 53,641 | | | 31,158 | | | 4,397 | | | 6,756 | | | 14,113 | | | 8,109 | | | 118,174 | | Future development costs | 29,941 | | | 31,736 | | | 2,113 | | | 5,921 | | | 14,519 | | | 7,286 | | | 91,516 | |
| Future income tax expenses | Future income tax expenses | 12,530 | | | 5,888 | | | (594) | | | 5,374 | | | 108,316 | | | 5,158 | | | 136,672 | | Future income tax expenses | 24,770 | | | 12,004 | | | 451 | | | 4,319 | | | 107,577 | | | 13,038 | | | 162,159 | |
| Future net cash flows | Future net cash flows | 52,362 | | | 19,952 | | | (1,223) | | | 7,887 | | | 35,153 | | | 17,352 | | | 131,483 | | Future net cash flows | 98,848 | | | 54,503 | | | 616 | | | 6,872 | | | 33,918 | | | 33,811 | | | 228,568 | |
| Effect of discounting net cash flows at 10% | Effect of discounting net cash flows at 10% | 30,499 | | | 7,728 | | | (1,265) | | | 872 | | | 18,658 | | | 7,491 | | | 63,983 | | Effect of discounting net cash flows at 10% | 50,524 | | | 25,793 | | | (502) | | | 739 | | | 17,383 | | | 18,751 | | | 112,688 | |
| Discounted future net cash flows | Discounted future net cash flows | 21,863 | | | 12,224 | | | 42 | | | 7,015 | | | 16,495 | | | 9,861 | | | 67,500 | | Discounted future net cash flows | 48,324 | | | 28,710 | | | 1,118 | | | 6,133 | | | 16,535 | | | 15,060 | | | 115,880 | |
| | Equity Companies | Equity Companies | | Equity Companies | |
| As of December 31, 2019 | | |
| Future cash inflows from sales of oil and gas | Future cash inflows from sales of oil and gas | 15,729 | | | — | | | 3,194 | | | 2,509 | | | 115,451 | | | — | | | 136,883 | | Future cash inflows from sales of oil and gas | 10,607 | | | — | | | 5,889 | | | 4,553 | | | 146,845 | | | — | | | 167,894 | |
| Future production costs | Future production costs | 6,848 | | | — | | | 1,302 | | | 246 | | | 48,259 | | | — | | | 56,655 | | Future production costs | 5,005 | | | — | | | 785 | | | 261 | | | 49,810 | | | — | | | 55,861 | |
| Future development costs | Future development costs | 3,681 | | | — | | | 1,182 | | | 247 | | | 11,463 | | | — | | | 16,573 | | Future development costs | 2,340 | | | — | | | 1,137 | | | 62 | | | 8,317 | | | — | | | 11,856 | |
| Future income tax expenses | Future income tax expenses | — | | | — | | | 346 | | | 555 | | | 17,891 | | | — | | | 18,792 | | Future income tax expenses | — | | | — | | | 1,793 | | | 1,168 | | | 29,463 | | | — | | | 32,424 | |
| Future net cash flows | Future net cash flows | 5,200 | | | — | | | 364 | | | 1,461 | | | 37,838 | | | — | | | 44,863 | | Future net cash flows | 3,262 | | | — | | | 2,174 | | | 3,062 | | | 59,255 | | | — | | | 67,753 | |
| Effect of discounting net cash flows at 10% | Effect of discounting net cash flows at 10% | 2,721 | | | — | | | 41 | | | 1,112 | | | 18,573 | | | — | | | 22,447 | | Effect of discounting net cash flows at 10% | 1,553 | | | — | | | 683 | | | 1,868 | | | 25,710 | | | — | | | 29,814 | |
| Discounted future net cash flows | Discounted future net cash flows | 2,479 | | | — | | | 323 | | | 349 | | | 19,265 | | | — | | | 22,416 | | Discounted future net cash flows | 1,709 | | | — | | | 1,491 | | | 1,194 | | | 33,545 | | | — | | | 37,939 | |
| Total consolidated and equity interests in standardized measure of discounted future net cash flows | Total consolidated and equity interests in standardized measure of discounted future net cash flows | 24,342 | | | 12,224 | | | 365 | | | 7,364 | | | 35,760 | | | 9,861 | | | 89,916 | | Total consolidated and equity interests in standardized measure of discounted future net cash flows | 50,033 | | | 28,710 | | | 2,609 | | | 7,327 | | | 50,080 | | | 15,060 | | | 153,819 | |
| | As of December 31, 2022 | | As of December 31, 2022 | |
| Consolidated Subsidiaries | Consolidated Subsidiaries | | | | | | | | | | | | | | Consolidated Subsidiaries | | | | | | | | | | | | | |
| As of December 31, 2020 | | | | | | | | | | | | | | |
| Future cash inflows from sales of oil and gas | Future cash inflows from sales of oil and gas | 93,520 | | | 38,193 | | | 2,734 | | | 15,411 | | | 138,080 | | | 19,794 | | | 307,732 | | Future cash inflows from sales of oil and gas | 316,486 | | | 284,643 | | | 11,806 | | | 30,040 | | | 271,732 | | | 114,959 | | | 1,029,666 | |
| Future production costs | Future production costs | 53,635 | | | 19,971 | | | 1,815 | | | 6,527 | | | 42,378 | | | 3,188 | | | 127,514 | | Future production costs | 78,939 | | | 113,264 | | | 2,627 | | | 7,489 | | | 63,705 | | | 21,972 | | | 287,996 | |
| Future development costs | Future development costs | 27,668 | | | 10,991 | | | 4,244 | | | 6,223 | | | 13,432 | | | 7,580 | | | 70,138 | | Future development costs | 31,960 | | | 34,968 | | | 2,016 | | | 6,143 | | | 9,241 | | | 7,089 | | | 91,417 | |
| Future income tax expenses | Future income tax expenses | (2,509) | | | 851 | | | (1,121) | | | 916 | | | 62,223 | | | 1,381 | | | 61,741 | | Future income tax expenses | 45,278 | | | 31,603 | | | 3,164 | | | 8,300 | | | 156,595 | | | 24,955 | | | 269,895 | |
| Future net cash flows | Future net cash flows | 14,726 | | | 6,380 | | | (2,204) | | | 1,745 | | | 20,047 | | | 7,645 | | | 48,339 | | Future net cash flows | 160,309 | | | 104,808 | | | 3,999 | | | 8,108 | | | 42,191 | | | 60,943 | | | 380,358 | |
| Effect of discounting net cash flows at 10% | Effect of discounting net cash flows at 10% | 8,564 | | | 1,116 | | | (1,565) | | | (511) | | | 10,557 | | | 3,624 | | | 21,785 | | Effect of discounting net cash flows at 10% | 83,711 | | | 49,861 | | | 187 | | | 322 | | | 21,772 | | | 34,896 | | | 190,749 | |
| Discounted future net cash flows | Discounted future net cash flows | 6,162 | | | 5,264 | | | (639) | | | 2,256 | | | 9,490 | | | 4,021 | | | 26,554 | | Discounted future net cash flows | 76,598 | | | 54,947 | | | 3,812 | | | 7,786 | | | 20,419 | | | 26,047 | | | 189,609 | |
| | Equity Companies | Equity Companies | | Equity Companies | |
| As of December 31, 2020 | | |
| Future cash inflows from sales of oil and gas | Future cash inflows from sales of oil and gas | 5,304 | | | — | | | 1,511 | | | 740 | | | 63,105 | | | — | | | 70,660 | | Future cash inflows from sales of oil and gas | 12,312 | | | — | | | 13,706 | | | 7,194 | | | 261,409 | | | — | | | 294,621 | |
| Future production costs | Future production costs | 3,467 | | | — | | | 694 | | | 247 | | | 29,170 | | | — | | | 33,578 | | Future production costs | 5,379 | | | — | | | 1,981 | | | 266 | | | 96,788 | | | — | | | 104,414 | |
| Future development costs | Future development costs | 2,243 | | | — | | | 1,054 | | | 163 | | | 9,929 | | | — | | | 13,389 | | Future development costs | 1,773 | | | — | | | 895 | | | 60 | | | 7,275 | | | — | | | 10,003 | |
| Future income tax expenses | Future income tax expenses | — | | | — | | | (115) | | | 42 | | | 8,088 | | | — | | | 8,015 | | Future income tax expenses | — | | | — | | | 5,262 | | | 1,965 | | | 51,838 | | | — | | | 59,065 | |
| Future net cash flows | Future net cash flows | (406) | | | — | | | (122) | | | 288 | | | 15,918 | | | — | | | 15,678 | | Future net cash flows | 5,160 | | | — | | | 5,568 | | | 4,903 | | | 105,508 | | | — | | | 121,139 | |
| Effect of discounting net cash flows at 10% | Effect of discounting net cash flows at 10% | (378) | | | — | | | (86) | | | 258 | | | 7,443 | | | — | | | 7,237 | | Effect of discounting net cash flows at 10% | 2,236 | | | — | | | 2,234 | | | 2,694 | | | 44,728 | | | — | | | 51,892 | |
| Discounted future net cash flows | Discounted future net cash flows | (28) | | | — | | | (36) | | | 30 | | | 8,475 | | | — | | | 8,441 | | Discounted future net cash flows | 2,924 | | | — | | | 3,334 | | | 2,209 | | | 60,780 | | | — | | | 69,247 | |
| Total consolidated and equity interests in standardized measure of discounted future net cash flows | Total consolidated and equity interests in standardized measure of discounted future net cash flows | 6,134 | | | 5,264 | | | (675) | | | 2,286 | | | 17,965 | | | 4,021 | | | 34,995 | | Total consolidated and equity interests in standardized measure of discounted future net cash flows | 79,522 | | | 54,947 | | | 7,146 | | | 9,995 | | | 81,199 | | | 26,047 | | | 258,856 | |
| (1) Includes discounted future net cash flows attributable to noncontrolling interests in ExxonMobil consolidated subsidiaries of $3,666 million in 2021 and $6,596 million in 2022. | | (1) Includes discounted future net cash flows attributable to noncontrolling interests in ExxonMobil consolidated subsidiaries of $3,666 million in 2021 and $6,596 million in 2022. |
(1)
Includes discounted future net cash flows attributable to noncontrolling interests in ExxonMobil consolidated subsidiaries of $1,064 million in 2019 and $(150) million in 2020.
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
| | Consolidated and Equity Interests | 2018 | |
Consolidated and Equity Interests (millions of dollars) | | Consolidated and Equity Interests (millions of dollars) | 2020 |
| Consolidated Subsidiaries | | Share of Equity Method Investees | | Total Consolidated and Equity Interests |
| | | Consolidated Subsidiaries | | Share of Equity Method Investees | | Total Consolidated and Equity Interests | | |
| | (millions of dollars) | |
| Discounted future net cash flows as of December 31, 2017 | 65,201 | | | 25,003 | | | 90,204 | | |
| Discounted future net cash flows as of December 31, 2019 | | Discounted future net cash flows as of December 31, 2019 | 67,500 | | | 22,416 | | | 89,916 | |
| Value of reserves added during the year due to extensions, discoveries,
improved recovery and net purchases/sales less related costs | Value of reserves added during the year due to extensions, discoveries,
improved recovery and net purchases/sales less related costs | 9,472 | | | (134) | | | 9,338 | | Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs | 169 | | | — | | | 169 | |
| Changes in value of previous-year reserves due to: | Changes in value of previous-year reserves due to: | | Changes in value of previous-year reserves due to: | |
Sales and transfers of oil and gas produced during the year, net of
production (lifting) costs | Sales and transfers of oil and gas produced during the year, net of
production (lifting) costs | (31,706) | | | (9,956) | | | (41,662) | | Sales and transfers of oil and gas produced during the year, net of production (lifting) costs | (15,048) | | | (3,818) | | | (18,866) | |
| Development costs incurred during the year | Development costs incurred during the year | 11,500 | | | 2,762 | | | 14,262 | | Development costs incurred during the year | 9,969 | | | 1,760 | | | 11,729 | |
| Net change in prices, lifting and development costs | Net change in prices, lifting and development costs | 56,798 | | | 23,582 | | | 80,380 | | Net change in prices, lifting and development costs | (80,444) | | | (21,739) | | | (102,183) | |
| Revisions of previous reserves estimates | Revisions of previous reserves estimates | 14,515 | | | (2,091) | | | 12,424 | | Revisions of previous reserves estimates | 2,614 | | | 680 | | | 3,294 | |
| Accretion of discount | Accretion of discount | 8,793 | | | 3,043 | | | 11,836 | | Accretion of discount | 10,786 | | | 3,011 | | | 13,797 | |
| Net change in income taxes | Net change in income taxes | (28,469) | | | (4,637) | | | (33,106) | | Net change in income taxes | 31,008 | | | 6,131 | | | 37,139 | |
| Total change in the standardized measure during the year | Total change in the standardized measure during the year | 40,903 | | | 12,569 | | | 53,472 | | Total change in the standardized measure during the year | (40,946) | | | (13,975) | | | (54,921) | |
| | Discounted future net cash flows as of December 31, 2018 | 106,104 | | | 37,572 | | | 143,676 | | |
| Discounted future net cash flows as of December 31, 2020 | | Discounted future net cash flows as of December 31, 2020 | 26,554 | | | 8,441 | | | 34,995 | |
| | | | | | | | | | | | | | | | | |
Consolidated and Equity Interests (millions of dollars) | 2021 |
| Consolidated Subsidiaries | | Share of Equity Method Investees | | Total Consolidated and Equity Interests |
| | |
| Discounted future net cash flows as of December 31, 2020 | 26,554 | | | 8,441 | | | 34,995 | |
| | | | | |
| Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases/sales less related costs | 11,922 | | | 22 | | | 11,944 | |
| Changes in value of previous-year reserves due to: | | | | | |
| Sales and transfers of oil and gas produced during the year, net of production (lifting) costs | (35,813) | | | (9,948) | | | (45,761) | |
| Development costs incurred during the year | 7,033 | | | 1,563 | | | 8,596 | |
| Net change in prices, lifting and development costs | 118,946 | | | 47,434 | | | 166,380 | |
| Revisions of previous reserves estimates | 27,126 | | | 2,507 | | | 29,633 | |
| Accretion of discount | 3,762 | | | 1,201 | | | 4,963 | |
| Net change in income taxes | (43,650) | | | (13,281) | | | (56,931) | |
| Total change in the standardized measure during the year | 89,326 | | | 29,498 | | | 118,824 | |
| | | | | |
| Discounted future net cash flows as of December 31, 2021 | 115,880 | | | 37,939 | | | 153,819 | |
| | Consolidated and Equity Interests | 2019 | |
Consolidated and Equity Interests (millions of dollars) | | Consolidated and Equity Interests (millions of dollars) | 2022 |
| Consolidated Subsidiaries | | Share of Equity Method Investees | | Total Consolidated and Equity Interests |
| | | Consolidated Subsidiaries | | Share of Equity Method Investees | | Total Consolidated and Equity Interests | | |
| | (millions of dollars) | |
| Discounted future net cash flows as of December 31, 2018 | 106,104 | | | 37,572 | | | 143,676 | | |
| Discounted future net cash flows as of December 31, 2021 | | Discounted future net cash flows as of December 31, 2021 | 115,880 | | | 37,939 | | | 153,819 | |
| Value of reserves added during the year due to extensions, discoveries,
improved recovery and net purchases/sales less related costs | Value of reserves added during the year due to extensions, discoveries,
improved recovery and net purchases/sales less related costs | (1,252) | | | 4 | | | (1,248) | | Value of reserves added during the year due to extensions, discoveries,
improved recovery and net purchases/sales less related costs | 18,592 | | | 3,008 | | | 21,600 | |
| Changes in value of previous-year reserves due to: | Changes in value of previous-year reserves due to: | | Changes in value of previous-year reserves due to: | |
Sales and transfers of oil and gas produced during the year, net of
production (lifting) costs | Sales and transfers of oil and gas produced during the year, net of
production (lifting) costs | (29,159) | | | (8,202) | | | (37,361) | | Sales and transfers of oil and gas produced during the year, net of production (lifting) costs | (57,344) | | | (17,037) | | | (74,381) | |
| Development costs incurred during the year | Development costs incurred during the year | 16,544 | | | 2,927 | | | 19,471 | | Development costs incurred during the year | 11,834 | | | 1,849 | | | 13,683 | |
| Net change in prices, lifting and development costs | Net change in prices, lifting and development costs | (66,455) | | | (21,046) | | | (87,501) | | Net change in prices, lifting and development costs | 139,844 | | | 51,094 | | | 190,938 | |
| Revisions of previous reserves estimates | Revisions of previous reserves estimates | 4,906 | | | 657 | | | 5,563 | | Revisions of previous reserves estimates | (1,985) | | | 2,140 | | | 155 | |
| Accretion of discount | Accretion of discount | 11,433 | | | 3,956 | | | 15,389 | | Accretion of discount | 14,655 | | | 4,938 | | | 19,593 | |
| Net change in income taxes | Net change in income taxes | 25,379 | | | 6,548 | | | 31,927 | | Net change in income taxes | (51,867) | | | (14,684) | | | (66,551) | |
| Total change in the standardized measure during the year | Total change in the standardized measure during the year | (38,604) | | | (15,156) | | | (53,760) | | Total change in the standardized measure during the year | 73,729 | | | 31,308 | | | 105,037 | |
| | Discounted future net cash flows as of December 31, 2019 | 67,500 | | | 22,416 | | | 89,916 | | |
| Discounted future net cash flows as of December 31, 2022 | | Discounted future net cash flows as of December 31, 2022 | 189,609 | | | 69,247 | | | 258,856 | |
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
| | | | | | | | | | | | | | | | | |
| Consolidated and Equity Interests (continued) | 2020 |
| | Consolidated Subsidiaries | | Share of Equity Method Investees | | Total Consolidated and Equity Interests |
| | (millions of dollars) |
| Discounted future net cash flows as of December 31, 2019 | 67,500 | | | 22,416 | | | 89,916 | |
| | | | | |
Value of reserves added during the year due to extensions, discoveries,
improved recovery and net purchases/sales less related costs | 169 | | | — | | | 169 | |
| Changes in value of previous-year reserves due to: | | | | | |
Sales and transfers of oil and gas produced during the year, net of
production (lifting) costs | (15,048) | | | (3,818) | | | (18,866) | |
| Development costs incurred during the year | 9,969 | | | 1,760 | | | 11,729 | |
| Net change in prices, lifting and development costs | (80,444) | | | (21,739) | | | (102,183) | |
| Revisions of previous reserves estimates | 2,614 | | | 680 | | | 3,294 | |
| Accretion of discount | 10,786 | | | 3,011 | | | 13,797 | |
| Net change in income taxes | 31,008 | | | 6,131 | | | 37,139 | |
| Total change in the standardized measure during the year | (40,946) | | | (13,975) | | | (54,921) | |
| | | | | |
| Discounted future net cash flows as of December 31, 2020 | 26,554 | | | 8,441 | | | 34,995 | |
OPERATING INFORMATION (unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2020 | | 2019 | | 2018 | | | | |
| Production of crude oil, natural gas liquids, bitumen and synthetic oil | | | | | | | | | | |
| Net production | | (thousands of barrels daily) |
| United States | | 685 | | 646 | | 551 | | | | |
| Canada/Other Americas | | 536 | | 467 | | 438 | | | | |
| Europe | | 30 | | 108 | | 132 | | | | |
| Africa | | 312 | | 372 | | 387 | | | | |
| Asia | | 742 | | 748 | | 711 | | | | |
| Australia/Oceania | | 44 | | 45 | | 47 | | | | |
| Worldwide | | 2,349 | | 2,386 | | 2,266 | | | | |
| | | | | | | | | | |
| Natural gas production available for sale | | | | | | | | | | |
| Net production | | (millions of cubic feet daily) |
| United States | | 2,691 | | 2,778 | | 2,574 | | | | |
| Canada/Other Americas | | 277 | | 258 | | 227 | | | | |
| Europe | | 789 | | 1,457 | | 1,653 | | | | |
| Africa | | 9 | | 7 | | 13 | | | | |
| Asia | | 3,486 | | 3,575 | | 3,613 | | | | |
| Australia/Oceania | | 1,219 | | 1,319 | | 1,325 | | | | |
| Worldwide | | 8,471 | | 9,394 | | 9,405 | | | | |
| | | | | | | | | | |
| | | (thousands of oil-equivalent barrels daily) |
Oil-equivalent production (1) | | 3,761 | | 3,952 | | 3,833 | | | | |
| | | | | | | | | | |
| Refinery throughput | | (thousands of barrels daily) |
| United States | | 1,549 | | 1,532 | | 1,588 | | | | |
| Canada | | 340 | | 353 | | 392 | | | | |
| Europe | | 1,173 | | 1,317 | | 1,422 | | | | |
| Asia Pacific | | 553 | | 598 | | 706 | | | | |
| Other Non-U.S. | | 158 | | 181 | | 164 | | | | |
| Worldwide | | 3,773 | | 3,981 | | 4,272 | | | | |
Petroleum product sales (2) | | | | | | | | | | |
| United States | | 2,154 | | 2,292 | | 2,210 | | | | |
| Canada | | 418 | | 476 | | 510 | | | | |
| Europe | | 1,253 | | 1,479 | | 1,556 | | | | |
| Asia Pacific and other Eastern Hemisphere | | 1,014 | | 1,156 | | 1,200 | | | | |
| Latin America | | 56 | | 49 | | 36 | | | | |
| Worldwide | | 4,895 | | 5,452 | | 5,512 | | | | |
| Gasoline, naphthas | | 1,994 | | 2,220 | | 2,217 | | | | |
| Heating oils, kerosene, diesel oils | | 1,751 | | 1,867 | | 1,840 | | | | |
| Aviation fuels | | 213 | | 406 | | 402 | | | | |
| Heavy fuels | | 249 | | 270 | | 395 | | | | |
| Specialty petroleum products | | 688 | | 689 | | 658 | | | | |
| Worldwide | | 4,895 | | 5,452 | | 5,512 | | | | |
| | | | | | | | | | |
Chemical prime product sales (2) | | (thousands of metric tons) |
| United States | | 9,010 | | 9,127 | | 9,824 | | | | |
| Non-U.S. | | 16,439 | | 17,389 | | 17,045 | | | | |
| Worldwide | | 25,449 | | 26,516 | | 26,869 | | | | |
Operating statistics include 100 percent of operations of majority-owned subsidiaries; for other companies, crude production, gas, petroleum product and chemical prime product sales include ExxonMobil’s ownership percentage and refining throughput includes quantities processed for ExxonMobil. Net production excludes royalties and quantities due others when produced, whether payment is made in kind or cash.
(1)Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.
(2)Petroleum product and chemical prime product sales data reported net of purchases/sales contracts with the same counterparty.
INDEX TO EXHIBITS
| | | | | |
| Exhibit | Description |
| | |
| Restated Certificate of Incorporation, as restated November 30, 1999, and as further amended effective June 20, 2001 (incorporated by reference to Exhibit 3(i) to the Registrant’s Annual Report on Form 10-K for 2015). |
| | |
| By-Laws, as revisedamended effective March 1, 2020October 25, 2022 (incorporated by reference to Exhibit 3(ii) to the Registrant’s Report on Form 8-K of March 3, 2020)October 31, 2022). |
| | |
| Description of ExxonMobil Capital Stock (incorporated by reference to Exhibit 4(vi) to the Registrant's Annual Report on Form 10-K for 2019). |
| | |
| 2003 Incentive Program, as approved by shareholders May 28, 2003 (incorporated by reference to Exhibit 10(iii)(a.1) to the Registrant’s Annual Report on Form 10-K for 2017).* |
| | |
| Extended Provisions for Restricted Stock Agreements (incorporated by reference to Exhibit 10(iii)(a.2) to the Registrant’s Annual Report on Form 10-K for 2016).* |
| | |
| Extended Provisions for Restricted Stock Unit Agreements – Settlement in Shares (incorporated by reference to Exhibit 99.1 to the Registrant's report on Form 8-K of December 1, 2020).Shares.* |
| | |
| Short Term Incentive Program, as amended (incorporated by reference to Exhibit 10(iii)(b.1) to the Registrant’s Annual Report on Form 10-K for 2018).* |
| | |
| Earnings Bonus Unit instrument (incorporated by reference to Exhibit 10(iii)(b.2) to the Registrant's Annual Report on Form 10-K for 2019).* |
| | |
| Amendment of 2018 and 2019 Earnings Bonus Unit instruments, effective November 23, 2021 (incorporated by reference to Exhibit 99.1 to the Registrant's Report on Form 8-K of November 30, 2021).* |
| |
| ExxonMobil Supplemental Savings Plan (incorporated by reference to Exhibit 10(iii)(c.1) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).Plan.* |
| | |
| ExxonMobil Supplemental Pension Plan (incorporated by reference to Exhibit 10(iii)(c.2) to the Registrant’s Annual Report on Form 10-K for 2014).Plan.* |
| | |
| ExxonMobil Additional Payments Plan (incorporated by reference to Exhibit 10(iii)(c.3) to the Registrant’s Annual Report on Form 10-K for 2018).Plan.* |
| | |
| ExxonMobil Executive Life Insurance and Death Benefit Plan (incorporated by reference to Exhibit 10(iii)(d) to the Registrant’s Annual Report on Form 10-K for 2016).* |
| | |
| 2004 Non-Employee Director Restricted Stock Plan (incorporated by reference to Exhibit 10(iii)(f.1) to the Registrant’s Annual Report on Form 10-K for 2018).* |
| | |
| Standing resolution for non-employee director restricted grants dated September 26, 2007 (incorporated by reference to Exhibit 10(iii)(f.2) to the Registrant’s Annual Report on Form 10-K for 2016).* |
| | |
| Form of restricted stock grant letter for non-employee directors.* |
| | |
| Standing resolution for non-employee director cash fees dated March 1, 2020 (incorporated by reference to Exhibit 10(iii)(f.4) to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2020).* |
| | |
| Code of Ethics and Business Conduct (incorporated by reference to Exhibit 14 to the Registrant’s Annual Report on Form 10-K for 2017). |
| | |
| Subsidiaries of the registrant. |
| | |
| Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm. |
| | |
| Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Executive Officer. |
| | |
| Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by PrincipalChief Financial Officer. |
| | |
| Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Accounting Officer. |
| | |
| Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Executive Officer. |
| | |
| Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by PrincipalChief Financial Officer. |
| | |
| Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Accounting Officer. |
| | |
| 101 | Interactive data files (formatted as Inline XBRL). |
| | |
| 104 | Cover page interactive data file (formatted as Inline XBRL and contained in Exhibit 101). |
| _____________________ | |
| * Compensatory plan or arrangement required to be identified pursuant to Item 15(a)(3) of this Annual Report on Form 10-K. |
The registrant has not filed with this report copies of the instruments defining the rights of holders of long-term debt of the registrant and its subsidiaries for which consolidated or unconsolidated financial statements are required to be filed. The registrant agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon request.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | | | | | | | | | | |
| Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. |
| | | |
| | EXXON MOBIL CORPORATION |
| | | |
| | By: | /s/ DARREN W. WOODS |
| Dated February 22, 2023 | | (Darren W. Woods,
Board)Board |
Dated February 24, 2021
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Jeremy R. Osterstock, Antony E. Peters, and David R. Woodcock and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated and on February 24, 2021.
| | | | | | | | |
Each person whose signature appears below constitutes and appoints John D. Buchanan, Brian J. Conjelko, and Antony E. Peters and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. |
| | | | | |
| | | | | | |
| | |
/s/ DARREN W. WOODS | | ChairmanPursuant to the requirements of the BoardSecurities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated and on February 22, 2023. |
(Darren W. Woods) | | (Principal Executive Officer) |
| | |
/s/ SUSAN K. AVERY | | Director |
(Susan K. Avery) | | |
| | |
/s/ ANGELA F. BRALY | | Director |
(Angela F. Braly) | | |
| | |
/s/ URSULA M. BURNS | | Director |
(Ursula M. Burns) | | |
| | |
| | | | | |
| Principal Executive Officer | | | Directors |
| | | | | |
/s/ KENNETH C. FRAZIERDARREN W. WOODS | | | /s/ MICHAEL J. ANGELAKIS | | Director/s/ KAISA H. HIETALA |
(Kenneth C. Frazier)Darren W. Woods, Chairman of the Board | | | Michael J. Angelakis | | Kaisa H. Hietala |
| | | | |
| | | /s/ SUSAN K. AVERY | | |
| /s/ JOSEPH L. HOOLEY |
| Principal Financial Officer | | | DirectorSusan K. Avery | | Joseph L. Hooley |
(Joseph L. Hooley) | | | | | |
| /s/ KATHRYN A. MIKELLS | | | /s/ ANGELA F. BRALY | |
| /s/ STEVEN A. KANDARIAN | | Director |
(Kathryn A. Mikells, Senior Vice President and Chief Financial Officer | | | Angela F. Braly | | Steven A. Kandarian) | | |
| | |
/s/ DOUGLAS R. OBERHELMAN | | Director |
(Douglas R. Oberhelman) | | |
| | |
/s/ SAMUEL J. PALMISANO | | Director |
(Samuel J. Palmisano) | | Kandarian |
| | |
/s/ WILLIAM C. WELDON | | Director |
(William C. Weldon) | | |
| | |
/s/ WAN ZULKIFLEE | | Director |
(Wan Zulkiflee) | | |
| | |
/s/ ANDREW P. SWIGERURSULA M. BURNS | | Senior Vice President/s/ ALEXANDER A. KARSNER |
(Andrew P. Swiger)Principal Accounting Officer | | | Ursula M. Burns | | (Principal Financial Officer)Alexander A. Karsner |
| | | | | |
/s/ DAVID S. ROSENTHALLEN M. FOX | | | /s/ GREGORY J. GOFF | | Vice President and Controller/s/ LAWRENCE W. KELLNER |
(David S. Rosenthal)Len M. Fox, Vice President
and Controller | | | Gregory J. Goff | | (Principal Accounting Officer)Lawrence W. Kellner |
| | | | |
| | | | | |
| | | /s/ JOHN D. HARRIS II | | /s/ JEFFREY W. UBBEN |
| | | John D. Harris II | | Jeffrey W. Ubben |
| | | | | |
