What changed in this filing

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Item 9A. Controls and Procedures

2022-02-23 compared with 2021-02-24 · 742 added, 785 removed, 2551 unchanged (37% of the section changed)

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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, Principal Financial Officer and Principal Accounting Officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2020.

As indicated in the certifications in Exhibit 31 of this report, the Corporation’s Chief Executive Officer, Chief Financial Officer, and Principal Accounting Officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2021.

Based on that evaluation, these officers have concluded that the Corporation’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Corporation in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

Management’s Report on Internal Control Over Financial Reporting

Management, including the Corporation’s Chief Executive Officer, Principal Financial Officer and Principal Accounting Officer, is responsible for establishing and maintaining adequate internal control over the Corporation’s 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.

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OTHER INFORMATION

DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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• 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”;

• The “Audit Committee” portion, “Director Independence” portion, and the membership table of the portions entitled “Board Meetings and Annual Meeting Attendance” and “Board Committees” of the section entitled “Corporate Governance”.

• The “Audit Committee” portion, “Director Independence” portion, “Board Meetings and Annual Meeting Attendance” portion, and the membership table of the portion entitled “Board Committees” of the section entitled “Corporate Governance”.

EXECUTIVE COMPENSATION

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

Functional Earnings 39

Forward-Looking Statements 42

Business Environment and Risk Assessment 40

Review of 2020 and 2019 Results

Business Environment 43

Business Results 46

Liquidity and Capital Resources 56

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Environmental Matters 61

Market Risks, Inflation and Other Uncertainties 54

Restructuring Activities 55

Market Risks 61

Critical Accounting Estimates 63

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Summary of Accounting Policies 75

Accounting Changes 74

Restructuring Activities 79

Miscellaneous Financial Information 80

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Income and Other Taxes 106

Restructuring Activities 107

Supplemental Information on Oil and Gas Exploration and Production Activities 110

Operating Information 123

BUSINESS PROFILE

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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 from both operating the Corporation’s assets and from the divesting of assets.

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.

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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.

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 – corporate total 10.9% (9.3)% 6.5%

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.

United States (19,385) 536 1,739

Structural Cost Savings

Structural cost savings describe decreases in the below 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 $4.9 billion, of which $1.9 billion was achieved in 2021.

The total change between periods in expenses below will reflect both structural cost savings and other changes in spend, including market factors, such as energy costs, inflation, and foreign exchange impacts, as well as changes in activity levels and costs associated with new operations.

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.

Consolidated Statement of Income Line Items Targeted for Structural Cost Savings 2021 2020 2019

(millions of dollars)

Production and manufacturing expenses 36,035 30,431 36,826

Selling, general and administrative expenses 9,574 10,168 11,398

Exploration expenses, including dry holes 1,054 1,285 1,269

Total 46,663 41,884 49,493

FREQUENTLY USED TERMS

Earnings (Loss) excluding Identified Items

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.

2021 2020 2019

United States (852) 1,717 2,962

Upstream U.S.

(millions of dollars)

Earnings (loss) (U.S.

GAAP) 3,663 12,112 15,775 (19,385) (645) (20,030) 536 13,906 14,442

Impairments (263) (489) (752) (17,092) (2,244) (19,336) — — —

Gain/(loss) on sale of assets — 459 459 — — — — 3,679 3,679

Inventory valuation - lower of cost or market — — — — (61) (61) — — —

Tax-related items — — — — (297) (297) — 755 755

Contractual provisions — (250) (250) — — — — — —

Identified Items (263) (280) (543) (17,092) (2,602) (19,694) — 4,434 4,434

Earnings (loss) excluding Identified Items 3,926 12,392 16,318 (2,293) 1,957 (336) 536 9,472 10,008

2021 2020 2019

United States 1,277 206 1,642

Downstream U.S.

(millions of dollars)

Earnings (loss) (U.S.

GAAP) 1,314 791 2,105 (852) (225) (1,077) 1,717 606 2,323

Impairments — — — (4) (593) (597) — — —

Gain/(loss) on sale of assets 4 — 4 — — — — — —

Tax-related items — — — — (262) (262) — (9) (9)

Identified Items 4 — 4 (4) (855) (859) — (9) (9)

Earnings (loss) excluding Identified Items 1,310 791 2,101 (848) 630 (218) 1,717 615 2,332

2021 2020 2019

Chemical U.S.

(millions of dollars)

Earnings (loss) (U.S.

GAAP) 4,502 3,294 7,796 1,277 686 1,963 206 386 592

Impairments — — — (90) (2) (92) — — —

Gain/(loss) on sale of assets 494 136 630 — — — — — —

Tax-related items — — — — (22) (22) — 2 2

Identified Items 494 136 630 (90) (24) (114) — 2 2

Earnings (loss) excluding Identified Items 4,008 3,158 7,166 1,367 710 2,077 206 384 590

FREQUENTLY USED TERMS

Corporate and Financing 2021 2020 2019

(millions of dollars)

Earnings (loss) (U.S.

GAAP) (2,636) (3,296) (3,017)

Impairments — (35) —

Gain/(loss) on sale of assets (12) — (24)

Tax-related items — — 332

Severance charges (52) (326) —

Identified Items (64) (361) 308

Earnings (loss) excluding Identified Items (2,572) (2,935) (3,325)

Corporate Total 2021 2020 2019

(millions of dollars)

Net income (loss) attributable to ExxonMobil (U.S.

GAAP) 23,040 (22,440) 14,340

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 ExxonMobil’s share after excluding amounts attributable to noncontrolling interests.

Impairments (752) (20,060) —

Gain/(loss) on sale of assets 1,081 — 3,655

Inventory valuation - lower of cost or market — (61) —

Tax-related items — (581) 1,080

Severance charges (52) (326) —

Contractual provisions (250) — —

Identified Items 27 (21,028) 4,735

Earnings (loss) excluding Identified Items 23,013 (1,412) 9,605

References in Frequently Used Terms and Management's Discussion & Analysis to total corporate earnings (loss) mean net income (loss) attributable to ExxonMobil from the Consolidated Statement of Income.

Unless otherwise indicated, references to earnings (loss), Upstream, Downstream, Chemical and Corporate and Financing earnings (loss), and earnings (loss) per share are ExxonMobil’s share after excluding amounts attributable to noncontrolling interests.

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

FORWARD-LOOKING STATEMENTS

Outlooks, projections, goals, targets, descriptions of strategic plans and objectives, and other statements of future events or conditions in this release are forward-looking statements.

Actual future results, including energy demand growth and mix;

Similarly, emission-reduction roadmaps are dependent on future market factors, such as continued technological progress and policy support, and also represent forward-looking statements.

Actual future results, including future energy demand and mix;

financial and operating performance;

realized price and margins;

dividends and shareholder returns, including the timing and amounts of share repurchases;

volume growth;

project plans, timing, costs, and capacities;

capital expenditures including environmental expenditures;

cost reductions;

emission intensity reductions;

the impact of new technologies;

capital expenditures, including lower-emissions and environmental expenditures;

cost reductions and structural cost savings;

integration benefits;

emission intensity and absolute emissions reductions;

achievement of ambitions to reach Scope 1 and Scope 2 net-zero from operated assets by 2050, to reduce methane emissions and flaring, or to complete major asset emission reduction roadmaps;

implementation and outcomes of carbon capture and storage projects and infrastructure, renewable fuel projects, blue hydrogen projects, and other technology efforts;

the impact of new technologies on society and industry;

capital expenditures and mix;

investment returns;

accounting 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, 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 conditions that impact prices and differentials;

accounting and financial reporting effects resulting from market or regulatory developments and ExxonMobil’s responsive actions, including potential impairment charges;

and the outcome of litigation and tax contingencies, 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 or economic conditions that impact demand, prices and differentials;

policy and consumer support for lower-emission products and technologies in different jurisdictions;

the impact of company actions to protect the health and safety of employees, vendors, customers, and communities;

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the ability to access short- and long-term debt markets on a timely and affordable basis;

the severity, length and ultimate impact of COVID-19 and government responses on people and economies;

the severity, length and ultimate impact of COVID-19 variants and government responses on people and economies;

reservoir performance;

the outcome of exploration projects and timely completion of development and construction projects;

changes in law, taxes, or regulation including environmental regulations, and timely granting of governmental permits;

regulatory actions targeting public companies in the oil and gas industry;

changes in local, national, or international law, taxes, regulation or policies affecting our business, including environmental regulations and timely granting of governmental permits;

war, trade agreements and patterns, shipping blockades or harassment, and other political or security disturbances;

the pace of regional and global economic recovery from the pandemic and the occurrence and severity of future outbreaks;

opportunities for and regulatory approval of potential investments or divestments;

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Risk Factors.

Energy demand models are forward-looking by nature and aim to replicate system dynamics of the global energy system, requiring simplifications.

The reference to any scenario in this report, including any potential net-zero scenarios, does not imply ExxonMobil views any particular scenario as likely to occur.

In addition, energy demand scenarios require assumptions on a variety of parameters.

As such, the outcome of any given scenario using an energy demand model comes with a high degree of uncertainty.

For example, the IEA describes its NZE scenario as extremely challenging, requiring unprecedented innovation, unprecedented international cooperation and sustained support and participation from consumers.

Third-party scenarios discussed in this report reflect the modeling assumptions and outputs of their respective authors, not ExxonMobil, and their use by ExxonMobil is not an endorsement by ExxonMobil of their underlying assumptions, likelihood or probability.

Investment decisions are made on the basis of ExxonMobil’s separate planning process, but may be secondarily tested for robustness or resiliency against different assumptions, including against various scenarios.

Any use of the modeling of a third-party organization within this report does not constitute or imply an endorsement by ExxonMobil of any or all of the positions or activities of such organization.

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 and manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a wide variety of specialty products.

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 biofuels.

ExxonMobil's operating segments are Upstream, Downstream, and Chemical.

Where applicable ExxonMobil voluntarily discloses additional U.S., Non-U.S.

and regional splits to help investors better understand the company's operations.

In January 2022, the Corporation announced that effective April 2022 it is streamlining its business structure by combining the Chemical and Downstream businesses.

The company will be organized along three businesses – Upstream, Product Solutions, and Low Carbon Solutions, aligning along market-focused value chains.

Product Solutions will consist of Energy Products, Specialty Products and Chemical Products.

Low Carbon Solutions will continue to be included in Corporate and Financing.

The businesses will be supported by a combined technology organization, and other centralized service-delivery groups, building on the establishment of a worldwide major projects organization in 2019.

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

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, Downstream and Chemical segments, generally reduces the Corporation’s risk from changes in commodity prices.

The company’s integrated business model, with significant investments in Upstream, Downstream and Chemical 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 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.

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, and chemical products are based on corporate plan assumptions developed annually by major region and are utilized for investment evaluation purposes.

The foundation for the assumptions supporting the corporate plan is the 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, including price differentials, refinery and chemical margins, volumes, development and operating costs, including greenhouse gas emission prices, and foreign currency exchange rates are based on corporate 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 major investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.

BUSINESS ENVIRONMENT AND RISK ASSESSMENT

BUSINESS ENVIRONMENT

Long-Term Business Outlook

Given the uncertainty around the near-term impacts of COVID-19 on economic growth, energy demand and energy supply, and lack of precedent, the Company is considering 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 used to help inform our long-term business strategies and investment plans.

ExxonMobil’s business planning is underpinned by a deep understanding of long-term energy fundamentals.

These fundamentals include energy supply and demand trends, the scale and variety of energy needs worldwide;

capability, practicality and affordability of energy alternatives including low-carbon solutions;

greenhouse gas emission-reduction technologies;

and supportive government policies.

The company’s Energy Outlook (Outlook) considers these fundamentals to form the basis for the company’s long-term business planning, investment decisions, and research programs.

The Outlook reflects the company’s view of global energy demand and supply through 2050.

It is a projection based on current trends in technology, government policies, consumer preferences, geopolitics, and economic development.

In addition, ExxonMobil considers a range of scenarios - including remote scenarios - to help inform perspective of the future and enhance strategic thinking over time.

Included in the range of these scenarios are the Intergovernmental Panel on Climate Change Lower 2°C and the International Energy Agency's Net Zero Emissions (IEA NZE) by 2050 scenario.

To effectively evaluate the pace of change, ExxonMobil uses many scenarios to help identify signposts that provide leading indicators of future developments and allow for timely adjustments to the Outlook.

The IEA describes the IEA NZE as extremely challenging, requiring all stakeholders – governments, businesses, investors and citizens – to take action this year and every year after so that the goal does not slip out of reach.

The scenario assumes unprecedented and sustained energy efficiency gains, innovation and technology transfer, lower-emission investments, and globally coordinated greenhouse gas reduction policy.

The IEA acknowledges that society is not on the IEA NZE pathway.

By 2050, the world’s population is projected at around 9.7 billion people, or about 2 billion more than in 2019.

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.

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 125 percent by 2050 compared to 2019.

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.

Even with significant efficiency gains, global energy demand is projected to rise by almost 15 percent from 2019 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 Organisation for Economic Co-operation and Development (OECD)).

As expanding prosperity helps drive 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 emissions per unit of economic output over time.

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 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.

Global electricity demand is expected to increase approximately 50 percent from 2018 to 2040, with developing countries likely to account for about 85 percent of the increase.

Under our Outlook, global electricity demand is expected to increase almost 75 percent from 2019 to 2050, with developing countries likely to account for about 80 percent of the increase.

Consistent with this projection, power generation is expected to remain the largest and fastest growing major segment of global primary energy demand, supported by a wide variety of energy sources.

The share of coal fired generation is likely to decline substantially and approach 20 percent of the world’s electricity in 2040, versus nearly 40 percent in 2018, in part as a result of policies to improve air quality as well as reduce greenhouse gas emissions to address the risks related to climate change.

From 2018 to 2040, the amount of electricity supplied using natural gas, nuclear power, and renewables is likely to nearly double, accounting for the entire growth in electricity supplies and offsetting the reduction of coal.

Electricity from wind and solar is likely to increase about 400 percent, helping total renewables (including other sources, e.g.

The share of coal-fired generation is expected to decline substantially and approach 15 percent of the world’s electricity in 2050, versus nearly 35 percent in 2019, in part as a result of policies to improve air quality as well as reduce greenhouse gas emissions to address risks related to climate change.

From 2019 to 2050, the amount of electricity supplied using natural gas, nuclear power, and renewables is expected to more than double, accounting for the entire growth in electricity supplies and offsetting the reduction of coal.

Electricity from wind and solar is expected to increase more than 600 percent, helping total renewables (including other sources, e.g.

hydropower) to account for about 80 percent of the increase in electricity supplies worldwide through 2050.

Total renewables will likely reach about 50 percent of global electricity supplies by 2040.

Total renewables are expected to reach about 50 percent of global electricity supplies by 2050.

Natural gas and nuclear are also expected to increase shares over the period to 2050, reaching more than 25 percent and about 10 percent of global electricity supplies, respectively, by 2050.

Supplies of electricity by energy type will reflect significant differences across regions reflecting a wide range of factors including the cost and availability of various energy supplies and policy developments.

Energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by about 20 percent from 2018 to 2040.

Transportation energy demand is likely to account for over 60 percent of the growth in liquid fuels demand worldwide over this period.

Light-duty vehicle demand for liquid fuels is projected to peak prior to 2025 and then decline to levels seen in the early-2010s by 2040 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 60 percent.

By 2040, light-duty vehicles are expected to account for about 20 percent of global liquid fuels demand.

During the same time period, nearly all the world’s commercial transportation fleets are likely to continue to run on liquid fuels, which are widely available and offer practical advantages in providing a large quantity of energy in small volumes.

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

Under our Outlook, energy for transportation - including cars, trucks, ships, trains and airplanes - is expected to increase by almost 25 percent from 2019 to 2050.

Transportation energy demand is expected to account for over 40 percent of the growth in liquid fuels demand worldwide over this period.

Light-duty vehicle demand for liquid fuels is projected to peak by around 2025 and then decline to levels seen in the early-2000s by 2050 as the impact of better fuel economy and significant growth in electric cars, led by China, Europe, and the United States, work to offset growth in the worldwide car fleet of about 75 percent.

By 2050, light-duty vehicles are expected to account for around 15 percent of global liquid fuels demand.

During the same time period, nearly all the world’s commercial transportation fleets are expected to continue to run on liquid fuels, including biofuels, which are widely available and offer practical advantages in providing a large quantity of energy in small volumes.

Liquid fuels provide the largest share of global energy supplies today reflecting broad-based availability, affordability, ease of transportation, and fitness as a practical solution to meet a wide variety of needs.

By 2050, global demand for liquid fuels is projected to grow to approximately 114 million barrels of oil equivalent per day, an increase of about 14 percent from 2019.

The non-OECD share of global liquid fuels demand is expected to increase to about 65 percent by 2040, as liquid fuels demand in the OECD is likely to decline by close to 15 percent.

The non-OECD share of global liquid fuels demand is expected to increase to nearly 70 percent by 2050, as liquid fuels demand in the OECD is expected to decline by more than 20 percent.

Much of the global liquid fuels demand today is met by crude production from traditional conventional sources;

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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 2019 to 2050, meeting about 55 percent of global energy demand growth.

Global natural gas demand is expected to rise about 25 percent from 2018 to 2040, with about half of that increase coming from the Asia Pacific region.

Global natural gas demand is expected to rise nearly 35 percent from 2019 to 2050, with more than half 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.

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Oil is expected to remain the largest source of energy with its share remaining close to 30 percent in 2050.

Coal is currently the second largest source of energy, but it is likely to lose that position to natural gas in the next few years.

The share of natural gas is expected to reach more than 25 percent by 2040, while the share of coal falls to about two thirds of the natural gas share.

Coal is currently the second largest source of energy, but it is expected to lose that position to natural gas in the next few years.

The share of natural gas is expected to reach more than 25 percent by 2050, while the share of coal falls to about half that of natural gas.

Nuclear power is projected to grow 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 likely to exceed 15 percent of global energy by 2040, with biomass, hydro and geothermal contributing a combined share of more than 10 percent.

Total energy supplied from wind, solar and biofuels is expected to increase rapidly, growing over 350 percent from 2018 to 2040, when they will likely be just over 6 percent of the world energy mix.

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.

Total renewable energy is expected to exceed 20 percent of global energy by 2050, with biomass, hydro and geothermal contributing a combined share of more than 10 percent.

Total energy supplied from wind, solar and biofuels is expected to increase rapidly, growing over 420 percent from 2019 to 2050, when they are projected to be about 10 percent of the world energy mix.

To meet this projected demand under our Outlook, 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 2040 will be significant – even if demand remains flat.

The investments to develop and supply resources to meet global demand through 2050 will be significant.

This reflects a fundamental aspect of the oil and natural gas business as the International Energy Agency (IEA) describes in its World Energy Outlook 2021.

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.

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.

For many years, the Corporation has taken into account policies established to reduce energy-related greenhouse gas emissions in its long-term 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 aggregation of Nationally Determined Contributions (NDCs), which were submitted by signatories to the United Nations Framework Convention on Climate Change (UNFCCC) 2015 Paris Agreement.

Our Outlook seeks to identify potential impacts of climate related 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.

Our Energy Outlook reflects an environment with increasingly stringent climate policies and is consistent with the global aggregation of Nationally Determined Contributions (NDCs), as available at the end of 2020, which were submitted by signatories to the United Nations Framework Convention on Climate Change (UNFCCC) 2015 Paris Agreement.

Our Energy Outlook seeks to identify potential impacts of climate-related 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, and, as applicable, use 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 CO 2 emissions is assumed to reach about $80 per tonne in 2040 in OECD nations.

For purposes of the Energy Outlook, a proxy cost on energy-related CO2 emissions is assumed to reach about $100 per metric ton in 2050 in 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 provide in preparation for COP 26 in Glasgow in November 2021 as well as other policy developments in light of net 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.

The Corporation continues to monitor the updates to the NDCs that nations provided around COP 26 in Glasgow in November 2021 as well as other policy developments in light of net-zero ambitions recently formulated by some nations.

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

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, and energy-efficiency process technology that can help achieve the Paris Agreement objectives.

In early 2021 ExxonMobil announced the creation of a new business, ExxonMobil Low Carbon Solutions, to commercialize low-carbon technologies.

The business will initially focus on carbon capture and storage (CCS), one of the critical technologies required to achieve the climate objectives outlined in the Paris Agreement.

In addition to CCS, the business will also leverage ExxonMobil’s significant experience in the production of hydrogen which, when coupled with CCS, is likely 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.

The information provided in the Outlook includes ExxonMobil’s internal estimates and projections based upon internal data and analyses as well as publicly available information from external sources including the International Energy Agency.

Leading the Drive to Net Zero

The company plans to play a leading role in the energy transition by leveraging its core capabilities to meet society’s needs for products essential for modern life, while addressing the challenge of climate change.

The Corporation announced its ambition to achieve net-zero emissions from its operated assets by 2050 (Scope 1 and 2 greenhouse gas emissions) and is taking a comprehensive approach centered on developing detailed emission-reduction roadmaps for major operated assets.

The company’s roadmap approach identifies greenhouse gas emission-reduction opportunities and the investment and future policy needs required to achieve net-zero.

The roadmaps are tailored to account for facility configuration and maintenance schedules, and they will be updated as technologies and policies evolve.

Net-zero roadmaps for major assets, covering about 90% of the company’s greenhouse gas emissions, are scheduled to be completed by year-end 2022, and the remainder in 2023.

Our strategy uses our advantages in scale, integration, technology and people to build globally competitive businesses that lead industry in earnings and cash flow growth across a broad range of scenarios.

The company’s plans to reduce greenhouse gas emissions through 2030 compared to 2016 levels support its net-zero ambition.

The plans are expected to result in a 20-30% reduction in corporate-wide greenhouse gas intensity, including reductions of 40-50% in upstream intensity, 70-80% in methane intensity and 60-70% in flaring intensity.

These plans include actions that are expected to reduce absolute corporate-wide greenhouse gas emissions by approximately 20%, including an estimated 70% reduction in methane emissions, 60% reduction in flaring emissions and 30% reduction in upstream emissions.

ExxonMobil established its Low Carbon Solutions business in early 2021, leveraging its unique combination of capabilities such as geophysics expertise and complex project management, to establish a new business in carbon capture and storage, hydrogen, and biofuels to accelerate emission reductions for customers and in its existing businesses.

The Corporation plans to invest in initiatives to lower greenhouse gas emissions.

A significant focus is on scaling up carbon capture and storage, hydrogen, and biofuels.

Stronger policy further accelerates development and deployment of lower-emission technologies, and would provide ExxonMobil additional investment opportunities to reduce greenhouse gas emissions.

The company's robust research and development process, continued evaluation of emerging technologies, and global collaborations will be key to identifying and growing lower-emission opportunities.

During the start-up phase, the Low Carbon Solutions business will be reflected in Corporate and Financing.

Recent Business Environment

In early 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.

Demand for petroleum and petrochemical products has continued to recover through 2021, with the Corporation's financial results benefiting from stronger prices and margins, notably prices for crude oil and natural gas as well as Chemical product margins.

The rate and pace of recovery, however, has varied across geographies and business lines, with Downstream margins only reaching the lower end of the 10-year range late in 2021 and jet demand continuing to lag.

The Corporation continues to closely monitor industry and economic conditions amid this uneven global recovery from the COVID-19 pandemic which has brought unprecedented uncertainties to near-term economic outlooks.

The general rate of inflation across major countries of operation experienced a brief decline in the initial stage of the COVID-19 pandemic.

However inflation rates increased in 2021 across major economies, with some regions experiencing multi-decade highs, largely reflecting overall imbalances between supply and demand recoveries from the pandemic.

The underlying factors include, but are not limited to, global supply chain disruptions, shipping bottlenecks, labor market constraints, and side effects from monetary and fiscal expansions.

The global economic recovery remains uneven, with uncertainties remaining.

Prices for services and materials continue to evolve in response to fast-changing commodity markets, industry activities, as well as government policies, impacting operating and capital costs.

The Corporation closely monitors market trends and works to mitigate cost impacts in all price environments through its economies of scale in global procurement, efficient project management practices, and general productivity improvements.

Organizational changes implemented over the past several years enabled the Corporation to realize nearly $5 billion of structural cost savings 1 versus 2019, leveraging increased operational efficiencies and reduced overhead costs.

Included in these savings is the completion of the workforce reduction programs, announced in late 2020 and early 2021, 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.

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.

These strategies are underpinned by a relentless focus on operational excellence, development of our employees, and investment in the communities within which we operate.

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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, the proportion of our global production from unconventional and deepwater resources, as well as LNG currently contributes nearly half of global production, and is generally expected to grow in the next few years.

About half of the Corporation's global production comes from unconventional, deepwater and LNG resources.

This proportion is generally expected to grow over the next few years.

The Upstream capital program continues to prioritize low cost-of-supply opportunities.

In addition to continued development of Guyana, Brazil, and the Permian Basin, ExxonMobil has a strong pipeline of development projects.

Most notable are our LNG developments in Mozambique, Papua New Guinea, and the Golden Pass LNG facility.

The Corporation anticipates several projects will come online over the next few years providing additional production capacity.

8 unchanged sentences

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.

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, alternative energy sources, 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, 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.

Significant progress was made on key new developments in Guyana and in the Permian basin during 2020.

In Guyana, exploration success continued with three additional discoveries increasing the estimated recoverable resource to nearly 9 billion oil-equivalent barrels on the Stabroek block.

In the Permian, despite economic curtailments and reduced capital investment, production volumes averaged 367 thousand oil-equivalent barrels per day in 2020, a 35 percent year-on-year production increase which exceeded expectations, while development and operating costs were significantly reduced.

Also in the Permian, we started up the Delaware basin central processing and stabilization facility which enhances the company’s integration advantages by collecting and processing oil and natural gas for delivery to Gulf Coast markets.

ExxonMobil’s Downstream is a large, diversified business with global logistics, trading, refining, and marketing.

The Corporation has a well-established presence in the Americas, Europe, and growing Asia Pacific region.

Downstream strategies competitively position the business across a range of market conditions.

These strategies focus on providing quality, differentiated, and valued products and services to customers, targeting best in class operations performance, capitalizing on integration across all ExxonMobil businesses, maximizing value from advantaged technology, and selectively investing for resilient, advantaged returns.

ExxonMobil’s operating results, as noted in Item 2.

Properties, reflect 21 refineries, located in 14 countries, with distillation capacity of 4.8 million barrels per day (MBD) and lubricant base stock manufacturing capacity of 129 thousand barrels per day.

ExxonMobil’s fuels 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 .

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

Fuels demand in 2020 was significantly impacted by the COVID-19 pandemic.

During the second quarter downturn, global demand for gasoline, diesel, 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.

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 packaging demand, and industry supply disruptions through the second half 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.

To manage the risks associated with price, ExxonMobil tests the resiliency of its annual plans and major investments across a range of price scenarios.

Key Recent Events

Significant progress was made on key new developments in Guyana, Brazil, the Permian Basin, and Mozambique during 2021.

Exploration success continued with additional discoveries increasing the estimated recoverable resource on the Stabroek block.

The Liza Unity floating production, storage and offloading vessel arrived in Guyanese waters in late 2021 and started production in February 2022.

In Payara, the third project, development drilling activities started in late 2021 and it remains on schedule for 2024 start-up.

Yellowtail is the fourth and largest world-class development project and is expected to achieve first oil in 2025, following issuance of the production license.

Production volumes averaged about 460 thousand oil-equivalent barrels per day (koebd) in 2021, nearly 100 koebd year-on-year production increase which exceeded expectations.

The Corporation was successful in increasing drilling performance and continuing to improve capital efficiency.

In December, ExxonMobil announced plans to achieve net-zero greenhouse gas emissions (Scope 1 and 2) by 2030 from our unconventional operations in the Permian Basin.

ExxonMobil announced its Final Investment Decision for the Bacalhau Phase 1 development in June 2021 with start-up planned for 2024.

The Area 4 Coral South Floating LNG (FLNG) development continues as planned, targeting start-up in 2022, making Mozambique an LNG exporter.

The Coral Sul FLNG vessel began tow to field in November 2021.

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.

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.

Upstream Financial Results

2021 2020 2019

1 unchanged sentence

Earnings (loss) (U.S.

Net income (loss) attributable to ExxonMobil (U.S.

GAAP) (22,440) 14,340 20,840

United States 3,663 (19,385) 536

12,112 (645) 13,906

(millions of dollars)

Total 15,775 (20,030) 14,442

Identified Items (1)

United States (263) (17,092) —

1 unchanged sentence

Total (543) (19,694) 4,434

Upstream results were a loss of $20,030 million, down $34,472 million from 2019.

• Lower realizations reduced earnings by $11.2 billion.

• Unfavorable volume and mix effects decreased earnings by $300 million.

• All other items decreased earnings by $23 billion, as impairments of $19.4 billion and the absence of the $3.7 billion gain from the 2019 Norway non-operated divestment were partly offset by lower expenses of $1 billion.

Upstream results were a loss of $19,385 million and included asset impairments of $17.1 billion.

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.

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.

Upstream earnings were $536 million and included asset impairments of $146 million.

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.

Earnings (loss) excluding Identified Items (1)

United States 3,926 (2,293) 536

12,392 1,957 9,472

Total 16,318 (336) 10,008

2021 Upstream Earnings Factor Analysis

(millions of dollars)

Price – Higher realizations increased earnings by $14,960 million.

Volume – 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 impairments of dry gas assets;

2021 $(543) million loss as a result of impairments of $(752) million and contractual provisions of $(250) million, partly offset by a $459 million gain from the U.K.

Central and Northern North Sea divestment.

(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

2020 Upstream Earnings Factor Analysis

(millions of dollars)

Price – Lower realizations reduced earnings by $11,210 million.

Volume – Unfavorable volume and mix effects decreased earnings by $300 million.

Other – All other items increased earnings by $1,170 million, primarily driven by lower expenses of $960 million.

Identified Items (1) – 2019 $4,434 million gain primarily the $3,700 million gain from the Norway non-operated divestment;

2020 $(19,694) million loss primarily impairments of dry gas assets.

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

Upstream Operational Results

2021 2020 2019

Production of crude oil, natural gas liquids, bitumen and synthetic oil

Net production (thousands of barrels daily)

United States 721 685 646

Canada/Other Americas 560 536 467

Europe 22 30 108

Africa 248 312 372

Asia 695 742 748

Australia/Oceania 43 44 45

Worldwide 2,289 2,349 2,386

Natural gas production available for sale

Net production (millions of cubic feet daily)

United States 2,746 2,691 2,778

Canada/Other Americas 195 277 258

Europe 808 789 1,457

Africa 43 9 7

Asia 3,465 3,486 3,575

Australia/Oceania 1,280 1,219 1,319

Worldwide 8,537 8,471 9,394

(thousands of oil-equivalent barrels daily)

Oil-equivalent production (2)

3,712 3,761 3,952

(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

Liquids production – 2.3 million barrels per day decreased 60 thousand barrels per day reflecting higher demand and growth, more than offset by entitlements, decline, and divestments.

Natural gas production available for sale – 8.5 billion cubic feet per day increased 66 million cubic feet per day from 2020, reflecting higher demand, partly offset by divestments and Groningen production limit.

Liquids production – 2.3 million barrels per day decreased 37 thousand barrels per day reflecting the impacts of government mandates, divestments, and lower demand, partly offset by growth and lower downtime.

Natural gas production available for sale – 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.

Upstream Additional Information

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Divestments (24) (151)

Growth / Other 12 116

Demand / Growth / Other 65 12

Current Year 3,712 3,761

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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.

Demand, 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

ExxonMobil’s Downstream continues to be one of the largest, most integrated businesses among international oil companies (IOC), with significant positions across the full value chain including logistics, trading, refining, and marketing.

The Corporation has a well-established presence in the Americas, Europe, and Asia Pacific.

Downstream strategies competitively position the business across a range of market conditions.

These strategies focus on providing high-value and lower-emission products that customers need to power global mobility;

leveraging strong operations performance;

capitalizing on integration across all ExxonMobil businesses;

maximizing value from advantaged technology and a robust pipeline of lower-emission opportunities;

and improving portfolio competitiveness and resilience with advantaged investments and divestments.

With its large manufacturing footprint, ExxonMobil’s Downstream earnings are closely tied to industry refining margins.

Refining margins improved steadily throughout 2021, recovering from historic lows in 2020 driven by COVID-19 pandemic demand impacts.

By the end of 2021, refining margins had recovered to the bottom of the 10-year historical band from 2010 to 2019.

Demand for gasoline and diesel had essentially recovered to normal levels by the end of 2021, while jet fuel demand remained below historical levels reflecting continued COVID-19 restrictions.

Refining margins are anticipated to further improve in the near term as the recovery in international travel increases demand for jet fuel, and strong chemical demand persists for products essential to modern life.

With improving market conditions, we restarted projects in Beaumont, Texas and Singapore to further strengthen the portfolio by increasing production of high-value fuels and lubricants.

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).

ExxonMobil’s 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 continues to grow fuels product sales in new markets near major production assets with continued progress in the Mexico and Indonesia markets.

Similarly, the lubricants business continues to grow, especially in Asia Pacific and the industrial sector, leveraging world class brands and integration with basestocks refining capability.

Through the Mobil brands, such as Mobil 1, ExxonMobil is the worldwide leader in synthetic motor oils.

The Downstream business is characterized by periods of margin volatility resulting from short-term and long-term supply and demand fluctuations.

Proposed carbon policy and other climate-related regulations in many countries have the potential to increase industry volatility, both favorably and unfavorably.

ExxonMobil continually evaluates the Downstream portfolio during all phases of the business cycle, which has resulted in numerous asset divestments and terminal conversions over the past decade to strengthen overall profitability and resiliency.

When investing in the Downstream, ExxonMobil remains focused on projects resilient across a broad range of market conditions to support capturing value when opportunities emerge.

Key Recent Events

Lower-emission fuels :

ExxonMobil announced plans for more than 40 thousand barrels per day of lower-emission fuels by 2025, including a new renewable diesel unit at the Strathcona refinery, and purchase agreements with Global Clean Energy in the U.S.

and Biojet AS in Norway.

Terminal conversions :

ExxonMobil converted the Slagen, Norway and Altona, Australia refineries into product import terminals capable of serving existing markets.

Additionally, Refining New Zealand announced conversion of its refinery (in which ExxonMobil owns a 17% minority share) to a product import terminal in 2022.

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

Downstream Financial Results

2021 2020 2019

(millions of dollars)

Earnings (loss) (U.S.

United States 1,314 (852) 1,717

1 unchanged sentence

Total 2,105 (1,077) 2,323

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.

Downstream results were a loss of $852 million, compared to earnings of $1,717 million in the prior year.

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.

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.

Downstream earnings were $1,717 million, compared to $2,962 million in the prior year.

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.

Identified Items (1)

United States 4 (4) —

Total 4 (859) (9)

Earnings (loss) excluding Identified Items (1)

United States 1,310 (848) 1,717

Total 2,101 (218) 2,332

2021 Downstream Earnings Factor Analysis

(millions of dollars)

Margins – Increased earnings by $1,920 million as industry refining conditions improved.

Volume – Increased earnings by $100 million reflecting demand recovery and favorable mix.

Other – Increased earnings by $300 million due to lower expenses of $560 million, partly offset by unfavorable foreign exchange and LIFO impacts.

Identified Items (1) – 2020 $(859) million loss 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.

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

2020 Downstream Earnings Factor Analysis

(millions of dollars)

Margins – Decreased earnings by $3,820 million including the impact of weaker industry refining conditions.

Volume – Increased earnings by $370 million as manufacturing/yield improvement impacts were partly offset by weaker demand.

Other – Increased earnings by $900 million due to lower expenses of $1,290 million, partly offset by unfavorable LIFO inventory impacts of $410 million.

Identified Items (1) – 2020 $(859) million loss 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.

Downstream Operational Results

2021 2020 2019

Refinery throughput (thousands of barrels daily)

United States 1,623 1,549 1,532

Canada 379 340 353

Europe 1,210 1,173 1,317

Asia Pacific 571 553 598

Other 162 158 181

Worldwide 3,945 3,773 3,981

Petroleum product sales (2)

United States 2,257 2,154 2,292

Canada 448 418 476

Europe 1,340 1,253 1,479

Asia Pacific 653 651 738

Other 464 419 467

Worldwide 5,162 4,895 5,452

Gasoline, naphthas 2,158 1,994 2,220

Heating oils, kerosene, diesel oils 1,749 1,751 1,867

Aviation fuels 220 213 406

Heavy fuels 269 249 270

Specialty petroleum products 766 688 689

Worldwide 5,162 4,895 5,452

(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.

ExxonMobil helps meet society’s evolving needs by providing a wide range of innovative, valuable product solutions in an efficient and responsible manner.

This is enabled by ExxonMobil’s proprietary technology combined with industry-leading scale and integration.

These competitive advantages are underpinned by operational excellence, advantaged investments, and cost discipline.

In 2021, while many markets continued to be negatively impacted by COVID-19, demand for chemical products remained resilient in several key segments including food packaging, hygiene and medical.

Overall chemical industry margins improved compared to 2020 due to continued strong packaging demand and industry supply disruptions.

We were uniquely positioned to capture value from the market in 2021 due to our integration, enabling nimble feed and product optimization, and our advantaged global supply and logistics.

These, along with our outstanding reliability performance and continued structural cost savings, delivered record annual earnings.

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.

ExxonMobil’s integration with refining, together with our high-value performance products and unique project execution capability, enhances our ability to generate returns on investments across a range of market environments.

In 2021, ExxonMobil completed construction of our joint venture ethane cracker and associated derivative units near Corpus Christi, Texas.

The project started up in late 2021 below budget and ahead of schedule.

With improving market conditions, we also restarted other U.S.

Gulf Coast growth projects, including projects in Baytown, Texas and Baton Rouge, Louisiana that will support the growing demand for high-value chemicals products.

Key Recent Events

China investment :

ExxonMobil reached final investment decision to proceed with a multi-billion dollar chemical complex in the Dayawan Petrochemical Industrial Park in Huizhou, Guangdong Province in China.

The facility will help meet expected demand growth for performance chemical products in China.

Advanced recycling :

The Corporation is progressing construction of one of North America’s largest plastic waste advanced recycling facilities in Baytown, Texas, which is expected to start operations in 2022.

In addition, plans are underway for up to 500,000 metric tons annually of advanced recycling capacity to be added across multiple sites by 2026.

These investments enabled commercial volumes of certified circular polymers to be made available to the market in 2021.

Materia acquisition :

ExxonMobil acquired Materia, Inc., a technology company that has pioneered the development of a Nobel prize-winning technology for manufacturing a new class of materials.

The innovative materials can be used in a number of applications, including wind turbine blades, electric vehicle parts, sustainable construction, and anticorrosive coatings.

Santoprene divestment :

ExxonMobil Chemical Company sold its global Santoprene business to Celanese.

The sale included two manufacturing sites, one in the United States and one in the United Kingdom.

Chemical Financial Results

2021 2020 2019

(millions of dollars)

Earnings (loss) (U.S.

United States 4,502 1,277 206

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Total 7,796 1,963 592

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.

Chemical earnings were $1,277 million in 2020, compared with $206 million in the prior year.

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.

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.

Chemical earnings were $206 million in 2019, compared with $1,642 million in the prior year.

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

Identified Items (1)

United States 494 (90) —

Total 630 (114) 2

Earnings (loss) excluding Identified Items (1)

United States 4,008 1,367 206

3,158 710 384

Total 7,166 2,077 590

(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 Chemical Earnings Factor Analysis

(millions of dollars)

Margins – Stronger margins increased earnings by $4,480 million driven by resilient demand and industry supply constraints.

Volume – Higher volumes increased earnings by $250 million on record production supported by exceptional reliability.

Other – All other items increased earnings by $360 million primarily as a result of favorable foreign exchange, lower expenses, and favorable LIFO impacts.

Identified Items (1) – 2020 $(114) million loss primarily as a result of impairments;

2021 $630 million gain as a result of the Santoprene divestment.

2020 Chemical Earnings Factor Analysis

(millions of dollars)

Margins – Stronger margins increased earnings by $930 million.

Volume – Lower volumes decreased earnings by $150 million.

Other – All other items increased earnings by $710 million primarily as a result of lower expenses.

Identified Items (1) – 2020 $(114) million loss primarily as a result of impairments.

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

Chemical Operational Results

2021 2020 2019

Chemical prime product sales (2)

(thousands of metric tons)

United States 9,724 9,010 9,127

16,608 16,439 17,389

Worldwide 26,332 25,449 26,516

(2) Data reported net of purchases/sales contracts with the same counterparty.

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

Corporate and Financing

Corporate and Financing is comprised of corporate activities that support 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 are included in Corporate and Financing as the business continues to mature through commercialization and deployment of technology.

Corporate and Financing Financial Results

2021 2020 2019

(millions of dollars)

Earnings (loss) (U.S.

GAAP) (2,636) (3,296) (3,017)

Identified Items (1)

(64) (361) 308

Earnings (loss) excluding Identified Items (1)

(2,572) (2,935) (3,325)

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

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.

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.

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

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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 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 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.

Total cash and cash equivalents were $4.4 billion at the end of 2020, up $1.3 billion from the prior year.

The major sources of funds in 2020 were the adjustment for the noncash provision of $46.0 billion, 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 2019 were net income including noncontrolling interests of $14.8 billion, the adjustment for the noncash provision of $19.0 billion for depreciation and depletion, a net debt increase of $8.7 billion, and proceeds from asset sales of $3.7 billion.

The major uses of funds included spending for additions to property, plant and equipment of $24.4 billion, dividends to shareholders of $14.7 billion, and additional investments and advances of $3.9 billion.

The Corporation has access to significant capacity of long-term and short-term liquidity.

Commercial paper continues to provide 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.

On December 31, 2020, the Corporation had unused short-term committed lines of credit of $11.3 billion and no unused long-term lines of credit.

In addition to cash balances, commercial paper continues to provide 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 balance sheet in 2021, reducing debt by nearly $20 billion and ending the year with $47.7 billion in total debt.

On December 31, 2021, the Corporation had undrawn short-term committed lines of credit of $10.7 billion and undrawn long-term lines of credit of $0.6 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 eventually to produce at declining rates for the remainder of their economic life.

After a period of production at plateau rates, it is the nature of oil and gas fields to eventually produce at declining rates for the remainder of their economic life.

Decline rates can vary widely by individual field due to a number of factors, including, but not limited to, the type of reservoir, fluid properties, recovery mechanisms, work activity, and age of the field.

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Capital and exploration expenditures in 2021 were $16.6 billion, reflecting the Corporation’s continued active investment program.

The Corporation is prioritizing opportunities to hold 2021 capital spending in a range of $16 billion to $19 billion.

The Corporation plans to invest in the range of $21 billion to $24 billion in 2022.

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

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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.

In light of commodity price volatility, and depending on the pace of demand 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.

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Acquisitions may be made with cash, shares of the Corporation’s common stock, or both.

ExxonMobil closely monitors the potential impacts of Brexit and Interbank Offered Rate (IBOR) reforms, including LIBOR, under a number of scenarios and has taken steps to mitigate their potential impact.

Accordingly, ExxonMobil does not believe these events represent a material risk to the Corporation’s consolidated results of operations or financial condition.

ExxonMobil closely monitors the potential impact of Interbank Offered Rate (IBOR) reform, including LIBOR, under a number of scenarios and has taken steps to mitigate the potential impact.

Accordingly, ExxonMobil does not believe this event represents a material risk to the Corporation’s consolidated results of operations or financial condition.

Cash Flow from Operating Activities

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 an increase of $1.0 billion in 2020.

Changes in operational working capital, excluding cash and debt, increased cash in 2021 by $4.2 billion.

Cash provided by operating activities totaled $14.7 billion in 2020, $15.0 billion lower than 2019.

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Changes in operational working capital, excluding cash and debt, decreased cash in 2020 by $1.7 billion.

Cash provided by operating activities totaled $29.7 billion in 2019, $6.3 billion lower than 2018.

The major source of funds was net income including noncontrolling interests of $14.8 billion, a decrease of $6.6 billion.

The noncash provision for depreciation and depletion was $19.0 billion, up $0.3 billion from the prior year.

The adjustment for the net gain on asset sales was $1.7 billion, a decrease of $0.3 billion.

The adjustment for dividends received less than equity in current earnings of equity companies was a reduction of $0.9 billion, compared to a reduction of $1.7 billion in 2018.

Changes in operational working capital, excluding cash and debt, increased cash in 2019 by $0.9 billion.

Cash Flow from Investing Activities

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Spending for property, plant and equipment of $12.1 billion decreased $5.2 billion from 2020.

Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments of $1.0 billion compared to $3.7 billion in 2019.

Additional investments and advances were $1.0 billion higher in 2020, while proceeds from other investing activities including collection of advances increased by $1.2 billion.

Cash used in investing activities netted to $23.1 billion in 2019, $6.6 billion higher than 2018.

Spending for property, plant and equipment of $24.4 billion increased $4.8 billion from 2018.

Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments of $3.7 billion compared to $4.1 billion in 2018.

Proceeds from asset sales and returns of investments of $3.2 billion compared to $1.0 billion in 2020.

Additional investments and advances were $2.0 billion lower in 2021, while proceeds from other investing activities including collection of advances decreased by $1.2 billion.

Cash used in investing activities netted to $18.5 billion in 2020, $4.6 billion lower than 2019.

Spending for property, plant and equipment of $17.3 billion decreased $7.1 billion from 2019.

Proceeds from asset sales and returns of investments of $1.0 billion compared to $3.7 billion in 2019.

Additional investments and advances were $1.0 billion higher in 2020, while proceeds from other investing activities including collection of advances increased by $1.2 billion.

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Cash Flow from Financing Activities

Cash used in financing activities was $35.4 billion in 2021, $40.7 billion higher than 2020.

Dividend payments on common shares 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 stronger 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.

In 2022, the Corporation initiated a share repurchase program of up to $10 billion over 12 to 24 months.

Cash flow from financing activities was $5.3 billion in 2020, $11.9 billion higher than 2019.

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ExxonMobil share of equity decreased $34.5 billion to $157.2 billion.

The reduction to equity for losses was $22.4 billion and the reduction for distributions to ExxonMobil shareholders was $14.9 billion, all in the form of dividends.

The reduction to equity for losses was $22.4 billion and the reduction for distributions to ExxonMobil shareholders of $14.9 billion, all in the form of dividends.

Foreign exchange translation effects of $1.8 billion for the weaker U.S.

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Shares outstanding decreased from 4,234 million to 4,233 million at the end of 2020.

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 OPERATIONS

Set forth below is information about 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-

2026 and Beyond

(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)

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 excludes 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.

Contractual Obligations

The Corporation has contractual obligations involving commitments to third parties that impact its liquidity and capital resource needs.

These contractual obligations are primarily for leases, debt, asset retirement obligations, pension and other postretirement benefits, take-or-pay and unconditional purchase obligations, and firm capital commitments.

See Notes 9, 11, 14 and 17 for information related to asset retirement obligations, leases, long-term debt and pensions, respectively.

In addition, the Corporation also enters into commodity purchase obligations (volumetric commitments but no fixed or minimum price) which are resold shortly after purchase, either in an active, highly liquid market or under long-term, unconditional sales contracts with similar pricing terms.

Examples include long-term, noncancelable LNG and natural gas purchase commitments and commitments to purchase refinery products at market prices.

Inclusion of such commitments would not be meaningful in assessing liquidity and cash flow, because these 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”.

(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.

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.

These commitments are not meaningful in assessing liquidity and cash flow, because the purchases will be offset in the same periods by cash received from the related sales transactions.

Take-or-pay obligations are noncancelable, long-term commitments for goods and services.

Unconditional purchase obligations are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services.

The obligations mainly pertain to pipeline, manufacturing supply and terminal agreements.

(6) Firm capital commitments represent legally binding payment obligations to third parties where agreements specifying all significant terms have been executed for the construction and purchase of fixed assets 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 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.

These obligations mainly pertain to pipeline, manufacturing supply and terminal agreements.

The total obligation at year-end 2021 for take-or-pay and unconditional purchase obligations was $30,031 million.

Cash payments expected in 2022 and 2023 are $4,004 million and $3,560 million, respectively.

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

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Financial Strength

On December 31, 2020, the Corporation had total unused short-term committed lines of credit of $11.3 billion (Note 6) and no unused long-term lines of credit (Note 14).

On December 31, 2021, the Corporation had total unused short-term committed lines of credit of $10.7 billion (Note 6) and total unused long-term committed lines of credit of $0.6 billion (Note 14).

The table below shows the Corporation’s consolidated debt to capital ratios.

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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 full range of market conditions, and enables the Corporation to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.

The Corporation’s financial position gives it the opportunity to access the world’s capital markets across a range of market conditions, and enables the Corporation to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.

Industry conditions in 2020 led to lower realized prices for the Corporation’s products which resulted in substantially lower earnings and operating cash flow in comparison to 2019.

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.

The Corporation ended 2020 with $67.6 billion in total debt.

Stronger prices and margins improved the Corporation's financial results in 2021.

The Corporation reduced debt by $19.9 billion and ended the year with $47.7 billion in total debt.

Litigation and Other Contingencies

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Capex in 2021 was $16.6 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 opportunities to hold 2021 capital spending in a range of $16 billion to $19 billion.

The Corporation plans to invest in the range of $21 billion to $24 billion in 2022.

Included in the 2022 capital spend range is $8.3 billion of firm capital commitments.

An additional $10.7 billion of firm capital commitments have been made for years 2023 and beyond.

Actual spending could vary depending on the progress of individual projects and property acquisitions.

Upstream spending of $14.4 billion in 2020 was down 39 percent from 2019 in response to market conditions.

Upstream spending of $12.3 billion in 2021 was down 15 percent from 2020, primarily in the U.S.

Permian Basin.

Investments in 2021 included the U.S.

Permian Basin and key development projects in Guyana.

Permian Basin and key development projects in Guyana and Brazil.

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.

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Total 40,591 22,793 38,468

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 31 percent compared to 17 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 $33.0 billion in 2021 increased $4.5 billion.

Total taxes on the Corporation’s income statement were $22.8 billion in 2020, a decrease of $15.7 billion from 2019.

Income tax expense, both current and deferred, was a benefit of $5.6 billion compared to $5.3 billion expense in 2019.

The relative benefit is driven by asset impairments recorded in 2020.

The relative benefit was driven by asset impairments recorded 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 17 percent compared to 34 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 billion in 2020 decreased $4.8 billion.

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

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Using definitions and guidelines established by the American Petroleum Institute, ExxonMobil’s 2021 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $4.6 billion, of which $3.4 billion were included in expenses with the remainder in capital expenditures.

The total cost for such activities is expected to increase to approximately $4.9 billion in 2021 and 2022.

Capital expenditures are expected to account for approximately 25 percent of the total.

The total cost for such activities is expected to increase to approximately $5.3 billion in 2022, with capital expenditures expected to account for approximately 30 percent of the total.

Costs for 2023 are anticipated to be higher as the Low Carbon Solutions business matures and the Corporation progresses its emission-reduction plans.

Environmental Liabilities

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Consolidated company provisions made in 2021 for environmental liabilities were $146 million ($263 million in 2020) and the balance sheet reflects liabilities of $807 million as of December 31, 2021, and $902 million as of December 31, 2020.

MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES

Worldwide Average Realizations (1)

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The impacts of these price fluctuations on earnings from Upstream, Downstream and Chemical operations have varied.

In the Upstream, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $475 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives.

For the year 2022, 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 $155 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives.

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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.

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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/chemical complexes.

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.

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The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses 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.

In addition, the Corporation uses commodity-based contracts, including derivatives, to manage commodity price risk and to generate returns from trading.

The Corporation’s commodity derivatives are not accounted for under hedge accounting.

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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;

manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a wide variety of specialty products;

and pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen and biofuels.

The preparation of financial statements in conformity with U.S.

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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, among other factors.

The estimation of proved reserves is controlled by the Corporation through long-standing approval guidelines.

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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, 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.

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.

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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 be used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves.

The straight-line method is used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves.

For example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the Corporation uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life.

To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes.

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

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;

• 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.

The Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year.

This process is aligned with the requirements of ASC 360 and ASC 932, and relies, in part, on the Corporation’s planning and budgeting cycle.

Because the lifespans of the vast majority of the Corporation’s major assets are measured in decades, the future cash flows of these assets are predominantly based on long-term oil and natural gas commodity prices and industry margins, and development and production costs.

Significant reductions in the Corporation’s view of oil or natural gas commodity prices or margin ranges, especially the longer-term prices and margins, and changes in the development plans, including decisions to defer, reduce, or eliminate planned capital spending, can be an indicator of potential impairment.

Other events or changes in circumstances, including indicators outlined in ASC 360, can be indicators of potential impairment as well.

In general, the Corporation does not view temporarily low prices or margins as an indication of impairment.

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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 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 these major assets, the Corporation expects that oil and gas prices will experience significant volatility, and 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 OPERATIONS

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.

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’s planning and budgeting cycle.

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, and consequently these assets will experience periods of higher earnings and periods of lower earnings, or even losses.

Energy Outlook and Cash Flow Assessment.

The annual planning and budgeting process, known as the Corporate Plan, is the mechanism by which resources (capital, operating expenses, and people) are allocated across the Corporation.

The foundation for the assumptions supporting the Corporate Plan is the 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, and economic development.

Reflective of the existing global policy environment, the Energy Outlook does not project the degree of required 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 Energy 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 planning and budgeting process, 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, and foreign currency exchange rates.

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.

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.

An asset group is impaired if its estimated undiscounted cash flows are less than the asset’s carrying value.

The greenhouse gas emission prices reflect existing or anticipated policy actions that countries or localities may take in support of Paris Accord pledges.

While third-party scenarios, such as the International Energy Agency Net Zero Emissions by 2050, may be used to test the resiliency of the Corporation's businesses or strategies, they are not used as a basis for developing future cash flows for impairment assessments.

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 amount by which the carrying value exceeds fair value.

The assessment of fair value requires the use of Level 3 inputs and assumptions that are based upon the views of a likely market participant.

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, commodity prices which are consistent with the average of third-party industry experts and government agencies, drilling and development costs, and discount rates ranging from 6 percent to 8 percent which are reflective of the characteristics of the asset group.

Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, throughput and product sales volumes, commodity prices which are consistent with the average of third-party industry experts and government agencies, refining and chemical margins, drilling and development costs, operating costs and discount rates which are reflective of the characteristics of the asset group.

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

Other Impairment Estimates.

Unproved properties are assessed periodically to determine whether they have been impaired.

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Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.

In 2020, the Corporation identified a number of situations where events or changes in circumstances indicated that the carrying value of certain long-lived assets may not be recoverable.

Those situations primarily related to the annual review and approval of the Corporation's business and strategic plan.

As part of the planning process, the Corporation assessed its full portfolio 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 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, after-tax charges of $18.4 billion in Upstream to reduce the carrying value of those assets to fair value.

Other after-tax impairment charges in 2020 include $0.5 billion in Upstream and $0.3 billion in Downstream.

As a result of these impairments, the Corporation expects lower 2021 depreciation 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.

Factors which could put further assets at risk of impairment in the future include reductions in the Corporation’s price outlooks, changes in the allocation of capital, and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural gas price increases.

However, due to the inherent difficulty in predicting future commodity prices, 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 of goodwill and equity company impairments, see Note 3 and Note 7 to the financial statements, respectively.

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

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 in equity companies 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 2021, 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 performed impairment assessments.

After-tax impairment charges of $1.0 billion, including impairments of suspended wells, were recognized during the year 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 U.S., 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 $1.1 billion, $0.6 billion and $0.2 billion were recognized in Upstream, Downstream and Chemical, respectively.

These charges include impairments of property, plant and equipment, goodwill and equity method investments.

In 2019, after-tax impairment charges were $0.2 billion.

Factors which could put further assets at risk of impairment in the future include reductions in the Corporation’s price or margin outlooks, changes in the allocation of capital or development plans, reduced long-term demand for the Corporation's products, and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural gas price or margin increases.

However, due to the inherent difficulty in predicting future commodity prices or margins, and the relationship between industry prices and costs, it is not practicable to reasonably estimate the existence or range of any potential future impairment charges related to the Corporation’s long-lived assets.

For further information regarding impairments in 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 incurs retirement obligations for certain assets.

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.

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and inflation rates.

Asset retirement obligations are disclosed in Note 9 to the financial statements.

Asset retirement obligations are disclosed in Note 9.

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 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.

The facts and circumstances that support continued capitalization of suspended wells at year-end are disclosed in Note 10 to the financial statements.

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.

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

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A worldwide reduction of 0.5 percent in the long-term rate of return on assets would increase annual pension expense by approximately $190 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 Contingencies

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.

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 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.

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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 reserve is established for the difference between a position taken or expected to be taken in an income tax return and the amount recognized in the financial statements.

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.

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.

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, Principal 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.

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PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2021, as stated in their report included in the Financial Section of this report.

Chief Executive Officer Andrew P.

Senior Vice President

(Principal Financial Officer) David S.

Chief Executive Officer Kathryn A.

Senior Vice President and

Chief Financial Officer Len M.

Vice President and Controller

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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

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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 matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate 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 matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.

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

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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 oil and natural gas reserve volumes and the assumptions applied to the data related to future development costs and production costs, as applicable.

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 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.

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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's relationship with the specialists was assessed.

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 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.

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

94 unchanged sentences

in excess of/(less than) net payments

498 109 1,070

Other long-term obligation provisions

14 unchanged sentences

Additions to property, plant and equipment ( 12,076 ) ( 17,282 ) ( 24,361 )

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 3,176 999 3,692

Additional investments and advances ( 2,817 ) ( 4,857 ) ( 3,905 )

4 unchanged sentences

Reductions in long-term debt ( 8 ) ( 8 ) ( 1 )

Additions to short-term debt (1)

12,687 35,396 18,967

Reductions in short-term debt (1)

( 29,396 ) ( 28,742 ) ( 18,367 )

Additions/(reductions) in commercial paper, and debt with

11 unchanged sentences

Cash and cash equivalents at end of year 6,802 4,364 3,089

(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.

12 unchanged sentences

Dividends - common shares — ( 14,652 ) — — ( 14,652 ) ( 192 ) ( 14,844 )

Cumulative effect of accounting change — 71 ( 39 ) — 32 15 47

Other comprehensive income — — 71 — 71 154 225

6 unchanged sentences

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

6 unchanged sentences

Dividends - common shares — ( 14,924 ) — — ( 14,924 ) ( 224 ) ( 15,148 )

Cumulative effect of accounting change — ( 93 ) — — ( 93 ) ( 1 ) ( 94 )

Other comprehensive income — — 2,941 — 2,941 228 3,169

18 unchanged sentences

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 and manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a wide variety of specialty products.

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 biofuels.

The preparation of financial statements in conformity with U.S.

1 unchanged sentence

Actual results could differ from these estimates.

Prior years’ data has been reclassified in certain cases to conform to the 2020 presentation basis.

Prior years’ data have been reclassified in certain cases to conform to the 2021 presentation basis.

Summary of Accounting Policies

8 unchanged sentences

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.

Investments in equity companies are assessed for possible impairment when events or changes in circumstances indicate that the carrying value of an investment may not be recoverable.

If evidence of an other than temporary loss in fair value below carrying amount is determined, an impairment is recognized.

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.

62 unchanged sentences

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.

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.

9 unchanged sentences

• 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, industry margins, and development and production costs.

Other events or changes in circumstances, 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.

4 unchanged sentences

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 and levels of prosperity.

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.

The demand side is largely a function of general economic activities, alternative energy sources and levels of prosperity.

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.

1 unchanged sentence

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’s planning and budgeting cycle.

Energy Outlook and Cash Flow Assessment.

The annual planning and budgeting process, known as the Corporate Plan, is the mechanism by which resources (capital, operating expenses, and people) are allocated across the Corporation.

As future policies and technology advancements emerge, they will be incorporated into the Energy Outlook, and the Corporation’s business plans will be updated accordingly.

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 assumptions which are 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.

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.

The greenhouse gas emission prices reflect existing or anticipated policy actions that countries or localities may take in support of Paris Accord pledges.

Cash flow estimates for impairment testing exclude the effects of derivative instruments.

An asset group is impaired if its estimated undiscounted cash flows are less than the asset’s carrying value.

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 amount by which the carrying value exceeds fair value.

Fair value is based on market prices if an active market exists for the asset group, or discounted cash flows using a discount rate commensurate with the risk.

The assessment of fair value is based upon the views of a likely market participant.

Other Impairments Related to Property, Plant and Equipment.

Unproved properties are assessed periodically to determine whether they have been impaired.

1 unchanged sentence

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.

Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.

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.

10 unchanged sentences

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.

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.

3 unchanged sentences

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

The Corporation is exposed to credit losses primarily through sales of petroleum products, crude oil, natural gas liquids and natural gas, as well as loans 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 assessment of the counterparty’s credit worthiness, contract terms, country of operation, and other risks.

The Corporation can require prepayment or collateral to mitigate certain credit risks.

The Corporation groups financial assets into portfolios that share similar risk characteristics for purposes of determining the allowance for credit losses and assesses if a significant change in the risk of credit loss has occurred.

Among the quantitative and qualitative factors considered are historical financial data, current conditions, industry and country risk, current credit ratings and the quality of third-party guarantees secured from the counterparty.

Financial assets are written off in whole, or in part, when practical recovery efforts have been exhausted 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.

The Corporation recognizes a credit allowance for off-balance sheet credit exposures as a liability 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

Restructuring Activities

The programs were completed by the end of 2021 and included both voluntary and involuntary employee separations as well as reductions in contractors.

In 2021, the Corporation recorded before-tax charges of $ 58 million, consisting primarily of employee separation costs, associated with announced workforce reduction programs in Singapore and Europe.

These costs are captured in “Selling, general and administrative expenses” on the Consolidated Statement of Income and reported within Corporate and Financing.

The Corporation does not expect any further charges related to the previously disclosed workforce reduction programs.

The following table summarizes the reserves and charges related to the workforce reduction programs announced in late 2020 and early 2021.

These are recorded in “Accounts payable and accrued liabilities” on the Consolidated Balance Sheet and do not include charges related to employee reductions associated with any portfolio changes or other projects.

(millions of dollars)

Balance at December 31, 2019

34 56 413 — 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 ) — — ( 5 )

Other 2 ( 3 ) 3 — 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

Beginning Balance 403 —

Additions/adjustments 58 450

Payments made ( 384 ) ( 47 )

Ending Balance 77 403

The cash outflows associated with the remaining liability balance of $ 77 million at December 31, 2021 will occur over the next few years, mainly in the form of monthly payments.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5 unchanged sentences

Crude oil, products and merchandise as of year-end 2021 and 2020 consist of the following:

Dec 31, 2021 Dec 31, 2020

(millions of dollars)

4 unchanged sentences

Total 14,519 14,169

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.

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 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.

Charges related to goodwill impairments in 2020 are included in “Depreciation and depletion” on the Consolidated Statement of Income .

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10 unchanged sentences

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

2 unchanged sentences

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

1 unchanged sentence

Balance as of December 31, 2021 ( 11,499 ) ( 2,265 ) ( 13,764 )

(1) Cumulative Foreign Exchange Translation Adjustment includes net investment hedge gain/(loss) of $( 355 ) million, net of taxes.

(1) Cumulative Foreign Exchange Translation Adjustment includes net investment hedge gain/(loss) net of taxes of $ 329 million and $( 355 ) million in 2021 and 2020, respectively.

Amounts Reclassified Out of Accumulated Other

4 unchanged sentences

Other income)

( 14 ) — ( 196 )

Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs

14 unchanged sentences

Highly liquid investments with maturities of three months or less when acquired are classified as cash equivalents.

For 2020, 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-tax amounts from the sale of non-operated upstream assets in Norway and upstream asset transactions in the U.S.

For 2021, the “Net (gain)/loss on asset sales” on the Consolidated Statement of Cash Flows 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.

The United Kingdom Central and Northern North Sea assets were sold to Neo Energy, resulting in a before-tax gain of $ 0.4 billion and cash proceeds of $ 0.7 billion in 2021.

The Santoprene business, including two chemical manufacturing sites in Pensacola, Florida and Newport, Wales, was sold to Celanese, resulting in a before-tax gain of $ 0.8 billion and cash proceeds of $ 1.1 billion in 2021.

For 2019, the “Net (gain)/loss on asset sales” line includes before-tax 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.

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.

2021 2020 2019

6 unchanged sentences

Additional Working Capital Information

Dec 31, 2021 Dec 31, 2020

(millions of dollars)

30 unchanged sentences

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.

Impairments related to upstream equity investments of $ 0.2 billion and $ 0.6 billion in 2021 and 2020, respectively, are included in “Income from equity affiliates” or “Other income” on the Consolidated Statement of Income.

2021 2020 2019

19 unchanged sentences

BEB Erdgas und Erdoel GmbH & Co.

Cameroon Oil Transportation Company S.A.

Caspian Pipeline Consortium - Kazakhstan 8

Caspian Pipeline Consortium 8

CORAL FLNG, S.A.

Cross Timbers Energy, LLC 50

GasTerra B.V.

Golden Pass LNG Terminal LLC 30

26 unchanged sentences

Investments 31,225 29,772

Advances, net of allowances of $ 31 million in 2020

Advances, net of allowances of $ 34 million and $ 31 million

Total equity method company investments and advances 39,551 38,584

11 unchanged sentences

Total 495,062 216,552 505,322 227,553

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, the Corporation identified a number of situations where events or changes in circumstances indicated that the carrying value of certain long-lived assets may not be recoverable.

Those situations primarily related to the annual review and approval of the Corporation's business and strategic plan.

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.

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 to fair value.

Before-tax impairment charges of $ 1.2 billion, including impairments of suspended wells, were recognized during the year largely as a result of changes to Upstream development plans.

The impairment of these assets resulted in before-tax charges of $ 24.4 billion in Upstream.

Other before-tax impairment charges in 2020 included $ 0.9 billion in Upstream, $ 0.5 billion in Downstream, and $ 0.1 billion in Chemical.

In 2019, before-tax impairment charges were $ 0.1 billion.

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 are based upon the views of a likely market participant.

Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, commodity prices which were consistent with the average of third-party industry experts and government agencies, drilling and development costs, and discount rates ranging from 6 percent to 8 percent which are reflective of the characteristics of the asset group.

In 2019 and 2018, the before-tax impairment charges were $ 0.1 billion and $ 0.7 billion, respectively.

Accumulated depreciation and depletion totaled $ 278,510 million at the end of 2021 and $ 277,769 million at the end of 2020.

Interest capitalized in 2020, 2019 and 2018 was $ 665 million, $ 731 million and $ 652 million, respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2 unchanged sentences

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.

In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, discount rates, and inflation rates.

Asset retirement obligations incurred in the current period were Level 3 fair value measurements.

15 unchanged sentences

Balance at December 31 10,630 11,247 11,280

The long-term Asset Retirement Obligations were $ 10,558 million and $ 10,279 million at December 31, 2020, and 2019, respectively, and are included in “Other long-term obligations.”

The long-term Asset Retirement Obligations were $ 9,985 million and $ 10,558 million at December 31, 2021, and 2020, respectively, and are included in “Other long-term obligations” on the Consolidated Balance Sheet.

Estimated cash payments in 2022 and 2023 are $ 645 million and $ 648 million, respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

37 unchanged sentences

(millions of dollars)

– Kaombo Split Hub

10 2006 Evaluating development plan to tie into planned production facilities.

– La Invernada

2 unchanged sentences

327 1994 - 2015 Evaluating development plans to tie into existing LNG facilities.

– Bacalhau Phase 1

284 2018 Continuing discussions with the government regarding development plan.

– Hibernia North

26 2019 Awaiting capacity in existing/planned infrastructure.

– Kurdistan Pirmam

109 2015 Evaluating commercialization alternatives, while waiting for government approval to enter Gas Holding Period.

138 2019 - 2020 Continuing discussions with the government regarding development plan.

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

9 unchanged sentences

3 2001 Evaluating/progressing development plan for tieback to existing/planned infrastructure.

79 2002 - 2006 Development activity under way, while continuing discussions with the government regarding development plan.

67 2009 - 2016 Evaluating development plan for tieback to existing production facilities.

32 2009 Awaiting capacity in existing/planned infrastructure.

41 2014 Evaluating development plan for tieback to existing production facilities.

Papua New Guinea

1 unchanged sentence

246 2017 Evaluating/progressing development plans.

116 2012 - 2018 Evaluating/progressing development plans.

– Neptun Deep

14 unchanged sentences

The Corporation’s activities as a lessor are not significant.

Operating Leases

Drilling Rigs and Related

Equipment Other Total Finance

(millions of dollars)

Operating Leases Finance Leases

Lease Cost 2021 2020 2019 2021 2020 2019

Operating lease cost 297 1,256 1,553

Short-term and other (net of sublease rental income) 530 1,083 1,613

Amortization of right of use assets 143

Interest on lease liabilities 169

Total 827 2,339 3,166 312

Operating Leases

Drilling Rigs and Related

Equipment Other Total Finance

(millions of dollars)

Lease Cost 2019

Operating lease cost 1,542 1,553 1,434

2 unchanged sentences

Interest on lease liabilities 158 169 133

Total 1,164 2,312 3,476 254

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Operating Leases

Drilling Rigs and Related

Equipment Other Total Finance

(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

2,893 3,166 3,476 291 312 254

(1) Includes $ 681 million, $ 827 million and $ 1,164 million for drilling rigs and related equipment operating leases in 2021, 2020 and 2019, respectively.

Operating Leases Finance Leases

Balance Sheet December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020

(millions of dollars)

Balance Sheet December 31, 2019

Right of use assets

10 unchanged sentences

Total lease liability (2)

5,190 5,162 2,007 1,921

Weighted average remaining lease term (years) 10 11 20 20

Weighted average discount rate (percent) 2.3 % 2.9 % 7.7 % 8.9 %

(2) Includes $ 935 million and $ 832 million for drilling rigs and related equipment operating leases in 2021 and 2020, respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Operating Leases

Drilling Rigs and Related

Equipment Other Total Finance

(millions of dollars)

Operating Leases Finance Leases

Maturity Analysis of Lease Liabilities December 31, 2021

2021 259 1,031 1,290 268

2022 256 817 1,073 259

2023 97 482 579 252

(millions of dollars)

2022 1,456 262

5 unchanged sentences

In addition to the lease liabilities in the table immediately above, at December 31, 2021, undiscounted commitments for leases not yet commenced totaled $ 962 million for operating leases and $ 4,960 million for finance leases.

Estimated cash payments for operating and finance leases not yet commenced are $ 310 million and $ 415 million for 2022 and 2023 respectively.

The finance leases relate to floating production storage and offloading vessels, LNG transportation vessels, 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.

Operating Leases

Drilling Rigs and Related

Equipment Other Total Finance

(millions of dollars)

Operating Leases Finance Leases

Other Information 2021 2020 2019 2021 2020 2019

Cash paid for amounts included in the measurement of lease liabilities

Cash flows from operating activities 1,159 1,159 31

Cash flows from investing activities 283 283

Cash flows from financing activities 94

Noncash right of use assets recorded in exchange for lease liabilities 552 183 735 108

Operating Leases

Drilling Rigs and Related

Equipment Other Total Finance

(millions of dollars)

Other Information 2019

Cash paid for amounts included in the measurement of lease liabilities

4 unchanged sentences

For January 1 adoption of ASC 842

445 2,818 3,263

In exchange for lease liabilities during the period 1,405 735 3,663 200 108 422

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

14 unchanged sentences

The estimated fair value of financial instruments at December 31, 2021 and December 31, 2020, and the related hierarchy level for the fair value measurement is as follows:

At December 31, 2020

December 31, 2021

(millions of dollars)

14 unchanged sentences

— — 902 902 — — 58 960

At December 31, 2019

December 31, 2020

(millions of dollars)

28 unchanged sentences

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, 2021 and December 31, 2020, the Corporation had $ 641 million and $ 504 million of collateral under master netting arrangements not offset against the derivatives on the Consolidated Balance Sheet, primarily related to initial margin requirements.

5 unchanged sentences

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, 2020 and 2019, or results of operations for the years ended 2020, 2019 and 2018.

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, 2021 and 2020, or results of operations for 2021, 2020 and 2019.

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.

16 unchanged sentences

These amounts exclude that portion of long-term debt, totaling $ 2,392 million, which matures within one year and is included in current liabilities.

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.

On December 17, 2021, the Corporation irrevocably deposited sufficient cash with the Trustee to fund the redemption of its 2.397 % notes due 2022.

After the deposit of the funds, the Corporation was released from its obligation and the debt was extinguished.

The amounts of long-term debt, excluding finance lease obligations, maturing in each of the four years after December 31, 2022, in millions of dollars, are:

3 unchanged sentences

and 2026 – $ 3,575 .

At December 31, 2020, the Corporation had no unused long-term lines of credit.

At December 31, 2021, the Corporation's unused long-term lines of credit were $ 0.6 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.

4 unchanged sentences

Summarized long-term debt at year-end 2021 and 2020 are shown in the table below:

Dec 31, 2021 Dec 31, 2020

(millions of dollars)

2 unchanged sentences

1.902 % notes due 2022

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

26 unchanged sentences

6.375 % senior notes due 2038

Mobil Corporation

8.625 % debentures due 2021

Industrial revenue bonds due 2022-2051 0.028 % 2,244 2,461

5 unchanged sentences

(1) Average effective interest rate for debt and average imputed interest rate for finance leases at December 31, 2021.

(2) Includes premiums of $ 148 million in 2020.

(2) Includes premiums of $ 131 million in 2021 and $ 148 million in 2020.

(3) Includes premiums of $ 82 million in 2021 and $ 87 million in 2020.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

17 unchanged sentences

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, 2021.

44 unchanged sentences

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.

The Corporation has previously provided disclosure regarding (i) claims being pursued by the Corporation against the Venezuelan National Oil Company in connection with a 2007 Venezuelan nationalization decree, and (ii) claims being pursued by the Corporation against the Nigerian National Petroleum Corporation in connection with a dispute involving crude oil lifting entitlements which was originally subject to arbitration in 2011.

Both matters remain ongoing but, as previously disclosed, the Corporation does not expect the ultimate resolution of either matter to have a material effect upon the Corporation’s operations or financial condition.

In the interest of disclosure simplification, the Corporation will no longer include specific disclosure of these matters in its annual or quarterly reports unless future developments alter the foregoing conclusions.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

19 unchanged sentences

Accumulated benefit obligation at December 31 15,781 17,502 27,373 30,952 — —

(1) Actuarial loss/(gain) primarily reflects changes in discount rates, partially offset by lower long-term rates of compensation.

(1) Actuarial loss/(gain) primarily reflects changes in discount rates, lower long-term rates of compensation and a lower health care cost trend rate.

(2) Benefit payments for funded and unfunded plans.

100 unchanged sentences

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.

Studies are periodically conducted to establish the preferred target asset allocation percentages.

The target asset allocation for the U.S.

benefit plans and the major non-U.S.

plans is 30 percent equity securities and 70 percent debt securities.

The fixed income funds are largely invested in investment grade corporate and government debt securities with interest rate sensitivity designed to approximate the interest rate sensitivity of plan liabilities.

Target asset allocations for benefit plans are reviewed periodically and set based on considerations such as risk, diversification, liquidity and funding level.

The target asset allocations for the major benefit plans range from 10 to 30 percent in equity securities and the remainder in fixed income securities.

The equity for the U.S.

and certain non-U.S.

plans include a small allocation to private equity partnerships that primarily focus on early-stage venture capital of 4 percent and 2 percent, respectively.

plans include allocations to private equity partnerships that primarily focus on early-stage venture capital of less than 5 percent.

The fair value measurement levels are accounting terms that refer to different methods of valuing assets.

76 unchanged sentences

Equity securities

88 (1) — — — 88

48 (1) — — — 48

Debt securities

4 unchanged sentences

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.

38 unchanged sentences

Earnings after income tax include transfers at estimated market prices.

In the Corporate and financing segment, interest revenue relates to interest earned on cash deposits and marketable securities.

In Corporate and Financing, interest revenue relates to interest earned on cash deposits and marketable securities.

Interest expense includes non-debt-related interest expense of $ 103 million in 2021, $ 148 million in 2020 and $ 105 million in 2019.

5 unchanged sentences

Earnings (loss) after income tax 3,663 12,112 1,314 791 4,502 3,294 ( 2,636 ) 23,040

Effect of asset impairments - noncash

( 17,138 ) ( 2,287 ) ( 15 ) ( 609 ) ( 100 ) ( 69 ) ( 35 ) ( 20,253 )

Earnings of equity companies included above 288 5,535 122 74 ( 139 ) 1,131 ( 354 ) 6,657

9 unchanged sentences

As of December 31, 2020

Earnings after income tax 536 13,906 1,717 606 206 386 ( 3,017 ) 14,340

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

9 unchanged sentences

As of December 31, 2019

Earnings after income tax 1,739 12,340 2,962 3,048 1,642 1,709 ( 2,600 ) 20,840

Earnings (loss) 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

17 unchanged sentences

Canada 22,166 13,093 19,735

United Kingdom 11,055 17,479 18,702

Singapore 15,031 9,442 12,128

United Kingdom 14,759 11,055 17,479

France 13,236 8,676 12,740

17 unchanged sentences

Papua New Guinea 7,534 7,803 8,057

Nigeria 6,345 7,640 8,421

United Arab Emirates 5,392 5,381 5,262

Nigeria 5,235 6,345 7,640

Guyana 4,892 3,547 2,542

Brazil 4,337 3,281 3,338

Russia 4,055 4,616 5,135

38 unchanged sentences

371 ( 603 ) ( 144 )

Enactment-date effects of U.S.

tax reform — — ( 291 )

( 705 ) ( 206 ) ( 216 )

27 unchanged sentences

Net deferred tax liabilities 15,715 14,006

In 2020, asset valuation allowances of $ 2,731 million increased by $ 807 million and included net provisions of $ 762 million and foreign currency effects of $ 41 million.

In 2021, asset valuation allowances of $ 2,634 million decreased by $ 97 million and included net provisions of $ 41 million and foreign currency effects of $ 137 million.

Balance sheet classification 2021 2020

7 unchanged sentences

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.

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.

10 unchanged sentences

Balance at December 31 9,130 8,764 8,844

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The gross unrecognized tax benefit balances are predominantly related to tax positions that would reduce the Corporation’s effective tax rate if the positions are favorably resolved.

Unfavorable resolution of these tax positions generally would not increase the effective tax rate.

1 unchanged sentence

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 tax positions since such timing is not entirely within the control of the Corporation.

It is difficult to predict the timing of resolution for these tax positions since the timing is not entirely within the control of the Corporation.

In the United States, the Corporation has various ongoing U.S.

2 unchanged sentences

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.

These positions are reflected in the unrecognized tax benefits table.

On February 24, 2020, the Corporation received an adverse ruling on this suit.

2 unchanged sentences

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.

The Corporation and the government have appealed the District Court's rulings to the U.S.

Court of Appeals for the Fifth Circuit (Fifth Circuit).

Proceedings in the Fifth Circuit are continuing.

Unfavorable resolution of all positions at issue with the IRS 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 or decrease by 10 percent in the next 12 months.

It is reasonably possible that the total amount of unrecognized tax benefits could increase by up to 10 percent or decrease by up to 70 percent in the next 12 months.

Such a decrease would result primarily from final resolution of the U.S.

federal income tax litigation within this timeframe.

The following table summarizes the tax years that remain subject to examination by major tax jurisdiction:

10 unchanged sentences

Nigeria 2006 — 2021

Norway 2010 — 2020

Papua New Guinea 2008 — 2021

3 unchanged sentences

The Corporation classifies interest on income tax-related balances as interest expense or interest income and classifies tax-related penalties as operating expense.

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.

The related interest payable balances were $ 61 million and $ 71 million at December 31, 2020, and 2019, respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Restructuring Activities

The programs, which are expected to be substantially completed 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, 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.

The Corporation estimates additional charges of up to $ 200 million in 2021 related to planned workforce reduction programs.

The following table summarizes the reserves and charges related to the workforce reduction programs, which are recorded in “Accounts payable and accrued liabilities.”

(millions of dollars)

Balance at January 1 —

Additions/adjustments 450

Payments made ( 47 )

Balance at December 31 403

For 2021 and 2019 the Corporation's net interest expense was $ 0 million on income tax reserves.

For 2020, the Corporation's net interest expense was a credit of $ 6 million.

The related interest payable balances were $ 61 million at both December 31, 2021 and 2020 .

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)

The results of operations for producing activities shown below do not include earnings from other activities that ExxonMobil includes in the Upstream function, such as oil and gas transportation operations, LNG liquefaction and transportation operations, coal and power operations, technical service agreements, other nonoperating activities and adjustments for noncontrolling interests.

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 $(1,380) million in 2021, $274 million in 2020 and $3,502 million in 2019.

134 unchanged sentences

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 2020 were $11,254 million, down $7,986 million from 2019, 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 lower acquisition costs of unproved properties.

Total consolidated costs incurred in 2021 were $9,877 million, down $1,377 million from 2020, due primarily to lower development costs, partially offset by higher acquisition costs of unproved properties.

In 2020, costs were $11,254 million, down $7,986 million from 2019, due primarily to lower development costs including lower asset retirement obligation cost estimates mainly in Angola.

Total equity company costs incurred in 2021 were $1,451 million, down $561 million from 2020, due primarily to lower development costs.

50 unchanged sentences

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.

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.

8 unchanged sentences

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 2020 that were associated with production sharing contract arrangements was 15 percent of liquids, 14 percent of natural gas and 15 percent on an oil-equivalent basis (natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million barrels).

The percentage of total proved reserves (consolidated subsidiaries plus equity companies) at year-end 2021 that were associated with production sharing contract arrangements was 12 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.

1 unchanged sentence

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 Information due to volumes consumed or flared and inventory changes.

The natural gas quantities differ from the quantities of natural gas delivered for sale by the producing function as reported in the Upstream Operational Results due to volumes consumed or flared and inventory changes.

The changes between 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 billion oil-equivalent barrels (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

138 unchanged sentences

(billions of cubic feet) (millions of oil-equivalent barrels)

Net proved developed and undeveloped

reserves of consolidated subsidiaries

Net proved developed and undeveloped reserves of consolidated subsidiaries

January 1, 2019

9 unchanged sentences

Attributable to noncontrolling interests 256

Proportional interest in proved reserves

of equity companies

Proportional interest in proved reserves of equity companies

January 1, 2019

10 unchanged sentences

19,239 1,466 1,202 1,285 16,887 7,001 47,080 22,445

Net proved developed and undeveloped

reserves of consolidated subsidiaries

Net proved developed and undeveloped reserves of consolidated subsidiaries

January 1, 2020

9 unchanged sentences

Attributable to noncontrolling interests 84

Proportional interest in proved reserves

of equity companies

Proportional interest in proved reserves of equity companies

January 1, 2020

17 unchanged sentences

(billions of cubic feet) (millions of oil-equivalent barrels)

Net proved developed and undeveloped

reserves of consolidated subsidiaries

Net proved developed and undeveloped reserves of consolidated subsidiaries

January 1, 2021

9 unchanged sentences

Attributable to noncontrolling interests 124

Proportional interest in proved reserves

of equity companies

Proportional interest in proved reserves of equity companies

January 1, 2021

135 unchanged sentences

106,104 37,572 143,676

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

(1,252) 4 (1,248)

Changes in value of previous-year reserves due to:

46 unchanged sentences

115,880 37,939 153,819

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.

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

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

5 unchanged sentences

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).*

Extended Provisions for Restricted Stock Unit Agreements – Settlement in 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).*

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).*

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).*

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).*

2018 and 2019 Earnings Bonus Unit instruments, as revised 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 March 31, 2021).*

ExxonMobil Supplemental Pension Plan (incorporated by reference to Exhibit 10(iii)(c.2) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2021).*

ExxonMobil Additional Payments Plan (incorporated by reference to Exhibit 10(iii)(c.3) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2021).*

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).*

7 unchanged sentences

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 Principal Financial Officer.

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

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

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

19 unchanged sentences

Woods) (Principal Executive Officer)

/s/ MICHAEL J.

ANGELAKIS Director

AVERY Director

5 unchanged sentences

FRAZIER Director

/s/ GREGORY J.

GOFF Director

HIETALA Director

/s/ JOSEPH L.

2 unchanged sentences

KANDARIAN Director

/s/ DOUGLAS R.

OBERHELMAN Director

/s/ SAMUEL J.

PALMISANO Director

/s/ WILLIAM C.

WELDON Director

/s/ WAN ZULKIFLEE Director

(Wan Zulkiflee)

/s/ ANDREW P.

SWIGER Senior Vice President

Swiger) (Principal Financial Officer)

ROSENTHAL Vice President and Controller

Rosenthal) (Principal Accounting Officer)

/s/ ALEXANDER A.

KARSNER Director

(Alexander A.

/s/ JEFFREY W.

UBBEN Director

/s/ KATHRYN A.

MIKELLS Senior Vice President and Chief Financial Officer

Mikells) (Principal Financial Officer)

FOX Vice President and Controller

Fox) (Principal Accounting Officer)

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 9A. Controls and Procedures