What changed in this filing

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Item 9A. Controls and Procedures

2023-02-23 compared with 2022-02-24 · 612 added, 531 removed, 2813 unchanged (29% of the section changed)

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Rule 10b5-1 Plan Elections

Wirth, Chairman of the Board, entered into a pre-arranged stock trading plan in November 2021.

Wirth’s plan provides for the potential exercise of vested stock options and the associated sale of up to 93,000 shares of Chevron common stock between February 2022 and March 2023.

Breber, Vice President and Chief Financial Officer, entered into a pre-arranged stock trading plan in November 2021.

Breber’s plan provides for the potential exercise of vested stock options and the associated sale of up to 18,500 shares of Chevron common stock between February 2022 and January 2023.

Morris, Vice President and Chief Human Resources Officer, and her spouse each entered into pre-arranged stock trading plans in November 2021.

The plans for Ms.

Morris and her spouse provide for the potential exercise of vested stock options and the associated sale of up to 17,300 and 11,300 shares of Chevron common stock, respectively, between February 2022 and January 2023.

Parfitt, Vice President, Midstream, entered into a pre-arranged stock trading plan in November 2021.

Parfitt’s plan provides for the potential exercise of vested stock options and the associated sale of up to 55,500 shares of Chevron common stock between February 2022 and January 2023.

Hewitt Pate, Vice President and General Counsel, entered into a pre-arranged stock trading plan on November 17, 2022.

Pate’s plan provides for the potential exercise of vested stock options and the associated sale of up to 250,742 shares of Chevron common stock between February 20, 2023 and February 8, 2024.

Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

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Wirth 62 Chairman of the Board and Chief Executive Officer (since Feb 2018)

Vice Chairman of the Board (Feb 2017 - Jan 2018) and Executive

Vice President, Midstream and Development (Jan 2016 - Jan 2018)

Chairman of the Board and

Chief Executive Officer

Geagea 62 Executive Vice President and Senior Advisor to Chairman and CEO

(since Aug 2021)

Executive Vice President, Technology, Projects and Services

(Jun 2015 - Aug 2021) Advisor to the Chairman and CEO

Johnson 62 Executive Vice President, Upstream (since Jun 2015)

Worldwide Exploration and Production Activities

Nelson 58 Executive Vice President, Downstream (since Mar 2019)

Breber 58 Vice President and Chief Financial Officer (since Apr 2019)

Executive Vice President, Downstream (Jan 2016 - Mar 2019) Finance;

Nigel Hearne 55 Executive Vice President, Oil, Products & Gas (since Oct 2022)

President, Chevron Eurasia Pacific Exploration & Production (July

2020 - Oct 2022)

President, Chevron Asia Pacific Exploration & Production (Jan 2019

- June 2020 )

Managing Director, Australia Business Unit (July 2016 - Dec 2018)

Upstream - Worldwide Exploration and Production;

Downstream - Worldwide Manufacturing, Marketing, Lubricants, and Chemicals;

Midstream - Worldwide

Nelson 59 Vice Chairman and Executive Vice President, Strategy, Policy & Development (since Feb 2023)

Executive Vice President, Strategy, Policy & Development (Oct

2022 - Feb 2023)

Executive Vice President, Downstream (since Mar 2019 - Sep 2022)

Vice President, Midstream, Strategy and Policy (Feb 2018 - Feb

Vice President, Strategic Planning (Apr 2016 - Jan 2018) Worldwide Manufacturing, Marketing and Lubricants;

Strategy & Sustainability;

Corporate Affairs;

Corporate Business Development

Bonner 48 Vice President (since Aug 2021), Chief Technology Officer and

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Downstream Technology

Breber 57 Vice President and Chief Financial Officer (since Apr 2019)

Executive Vice President, Downstream (Jan 2016 - Mar 2019) Finance

Gustavson 50 Vice President, Lower Carbon Energies (since Aug 2021)

Vice President, Chevron North America Exploration & Production

(Feb 2018 - July 2021) Lower Carbon Solutions

Morris 57 Vice President and Chief Human Resources Officer (since Feb 2019)

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Diversity and Inclusion

Parfitt 57 Vice President, Midstream (since Mar 2019)

President, Supply and Trading (Jun 2013 - Feb 2019) Supply and Trading Activities;

Power and Energy Management

Hewitt Pate 60 Vice President and General Counsel (since Aug 2009) Law, Governance and Compliance

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Executive Compensation

The information required by Item 402 of Regulation S-K and contained under the headings “Executive Compensation,” “CEO Pay Ratio” and “Director Compensation” in the 2022 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 407(e)(4) of Regulation S-K and contained under the heading “Corporate Governance — Board Committees” in the 2022 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 402 of Regulation S-K and contained under the headings “Executive compensation,” “Director compensation” and “CEO pay ratio” in the 2023 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 407(e)(5) of Regulation S-K and contained under the heading “Corporate governance — Management compensation committee report” in the 2023 Proxy Statement is incorporated herein by reference into this Annual Report on Form 10-K.

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The information required by Item 407(a) of Regulation S-K and contained under the heading “Corporate governance — Director independence” in the 2023 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

Principal Accounting Fees and Services

Principal Accountant Fees and Services

The information required by Item 9(e) of Schedule 14A and contained under the heading “Board proposal to ratify PricewaterhouseCoopers LLP as the independent registered public accounting firm for 2023” in the 2023 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

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Financial Table of Contents

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Business Environment and Outlook

Operating Developments

Noteworthy Developments

Results of Operations

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Environmental Matters

Critical Accounting Estimates and Assumption s

Critical Accounting Estimates and Assumptions

New Accounting Standards

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Financial Instruments - Credit Losses

Acquisition of Noble Energy, Inc.

Acquisition of Renewable Energy Group, Inc.

Supplemental Information on Oil and Gas Producing Activities

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

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

Key Financial Results

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2 Income net of tax, also referred to as “earnings” in the discussions that follow.

Refer to the “Results of Operations” section beginning on page 38 for a discussion of financial results by major operating area for the three years ended December 31, 2021.

Refer to the Results of Operations section for a discussion of financial results by major operating area for the three years ended December 31, 2022.

Throughout the document, certain totals and percentages may not sum to their component parts due to rounding.

Business Environment and Outlook

Chevron Corporation is a global energy company with substantial business activities in the following countries:

Angola, Argentina, Australia, Bangladesh, Brazil, Canada, China, Egypt, Equatorial Guinea, Israel, Kazakhstan, Kurdistan Region of Iraq, Mexico, Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait, the Philippines, Republic of Congo, Singapore, South Korea, Thailand, the United Kingdom, the United States, and Venezuela.

The company’s objective is to deliver higher returns, lower carbon and superior shareholder value in any business environment.

Angola, Argentina, Australia, Bangladesh, Brazil, Canada, China, Egypt, Equatorial Guinea, Israel, Kazakhstan, Mexico, Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait, the Philippines, Republic of Congo, Singapore, South Korea, Thailand, the United Kingdom, the United States, and Venezuela.

The company’s objective is to safely deliver higher returns, lower carbon and superior shareholder value in any business environment.

Earnings of the company depend mostly on the profitability of its upstream business segment.

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In the company’s downstream business, crude oil is the largest cost component of refined products.

Periods of sustained lower commodity prices could result in the impairment or write-off of specific assets in future periods and cause the company to adjust operating expenses, including employee reductions, and capital and exploratory expenditures, along with other measures intended to improve financial performance.

Governments, companies, communities, and other stakeholders are increasingly supporting efforts to address climate change, recognizing that individuals and society benefit from access to affordable, reliable, and ever-cleaner energy.

International initiatives and national, regional and state legislation and regulations that aim to directly or indirectly reduce GHG emissions are in various stages of adoption and implementation.

These policies, some of which support the global net zero emissions ambitions of the Paris Agreement, can change the amount of energy consumed, the rate of energy-demand growth, the energy mix, and the relative economics of one fuel versus another.

Implementation of these policies can be dependent on, and can affect the pace of, technological advancements, the granting of necessary permits by governing authorities, the availability of cost-effective, verifiable carbon credits, the availability of suppliers that can meet sustainability and other standards, evolving regulatory requirements affecting ESG standards or other disclosures, and evolving standards for tracking and reporting on emissions and emission reductions and removals.

Beyond the legislative and regulatory landscape, ever changing customer and consumer behavior can also influence energy demand by affecting preferences and use of the company’s products or competitors’ products, now and in the future.

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

Chevron supports the Paris Agreement’s global approach to governments addressing climate change and is committed to taking actions to help lower the carbon intensity of its operations while continuing to meet the need for energy that supports society.

Periods of sustained lower commodity prices could result in the impairment or write-off of specific assets in future periods and cause the company to adjust operating expenses, including employee reductions, and capital expenditures, along with other measures intended to improve financial performance.

Governments, companies, communities, and other stakeholders are increasingly supporting efforts to address climate change.

International initiatives and national, regional and state legislation and regulations that aim to directly or indirectly reduce GHG emissions are in various stages of design, adoption, and implementation.

These policies and programs, some of which support the global net zero emissions ambitions of the Paris Agreement, can change the amount of energy consumed, the rate of energy-demand growth, the energy mix, and the relative economics of one fuel versus another.

Implementation of jurisdiction-specific policies and programs can be dependent on, and can affect the pace of, technological advancements, the granting of necessary permits by governing authorities, the availability of cost-effective, verifiable carbon credits, the availability of suppliers that can meet sustainability and other standards, evolving regulatory or other requirements affecting ESG standards or other disclosures, and evolving standards for tracking and reporting on emissions and emission reductions and removals.

Some of these policies and programs include renewable and low carbon fuel standards, such as the Renewable Fuel Standard program in the U.S.

and California’s Low Carbon Fuel Standard;

programs that price GHG emissions, including

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

California’s Cap-and-Trade Program;

performance standards, including methane-specific regulation such as the U.S.

EPA’s forthcoming New Source Performance Standard and Emissions Guidelines for Existing Sources;

and measures that provide various incentives for lower carbon activities, including carbon capture and storage and the production of hydrogen and sustainable aviation fuel, such as the U.S.

Inflation Reduction Act.

Requirements for these and other similar policies and programs are complex, ever changing, program specific and encompass:

(1) the blending of renewable fuels into transportation fuels;

(2) the purchasing, selling, utilizing and retiring of allowances and carbon credits;

and (3) other emissions reduction measures including efficiency improvements and capturing GHG emissions.

While these compliance policies and programs may have negative impacts on the company now and in the future including, but not limited to, the displacement of hydrocarbon and other products, these policies have also enabled opportunities for Chevron as it grows and aims to further grow its lower carbon businesses.

For example, the acquisition of Renewable Energy Group, Inc.

(REG) in 2022 grew the company’s renewable fuels production capacity and increased the company’s carbon credit generation activities.

Although we expect the company’s costs to comply with these policies and programs to continue to increase, these costs currently do not have a material impact on the company’s financial condition or results of operations.

Significant uncertainty remains as to the pace in which the transition to a lower carbon future will progress, which is dependent, in part, on further advancements and changes in policy, technology, and customer and consumer preferences.

The level of expenditure required to comply with new or potential climate change-related laws and regulations and the amount of additional investments needed in new or existing technology or facilities, such as carbon capture and storage, is difficult to predict with certainty and is expected to vary depending on the actual laws and regulations enacted, available technology options, customer and consumer preferences, the company’s activities, and market conditions.

As discussed below, in 2021, the company announced planned capital spend of approximately $10 billion through 2028 in lower carbon investments.

Although the future is uncertain, many published outlooks conclude that fossil fuels will remain a significant part of an energy system that increasingly incorporates lower carbon sources of supply for many years to come.

Chevron supports the Paris Agreement’s global approach to governments addressing climate change and continues to take actions to help lower the carbon intensity of its operations while continuing to meet the demand for energy.

Chevron believes that broad, market-based mechanisms are the most efficient approach to addressing GHG emission reductions.

Chevron integrates climate change-related issues and the regulatory and other responses to these issues into its strategy and planning, capital investment reviews, and risk management tools and processes, where it believes they are applicable.

They are also factored into the company’s long-range supply, demand, and energy price forecasts.

These forecasts reflect estimates of long-range effects from climate change-related policy actions, such as renewable fuel penetration and energy efficiency standards, and demand response to oil and natural gas prices.

The actual level of expenditure required to comply with new or potential climate change-related laws and regulations and amount of additional investments in new or existing technology or facilities, such as carbon capture and storage, is difficult to predict with certainty and is expected to vary depending on the actual laws and regulations enacted or customer and consumer preference in a jurisdiction, the company’s activities in it, and market conditions.

As discussed in more detail below, the company has announced planned capital spend of $10 billion through 2028 in lower carbon investments.

Although the future is uncertain, many published outlooks conclude that fossil fuels will remain a significant part of an energy system that increasingly incorporates lower carbon sources of supply.

The company will continue to develop oil and gas resources to meet customers’ demand for energy.

These forecasts reflect estimates of long-range effects from climate change-related policy actions, such as electric vehicle and renewable fuel penetration, energy efficiency standards, and demand response to oil and natural gas prices.

The company will continue to develop oil and gas resources to meet customers’ and consumers’ demand for energy.

At the same time, Chevron believes that the future of energy is lower carbon.

The company will continue to maintain flexibility in its portfolio to be responsive to changes in policy, technology, and customer preferences.

Chevron aims to grow its traditional oil and gas business, lower the carbon intensity of its operations and grow lower carbon businesses in renewable fuels, hydrogen, carbon capture and offsets.

The company will continue to maintain flexibility in its portfolio to be responsive to changes in policy, technology, and customer and consumer preferences.

Chevron aims to grow its traditional oil and gas business, lower the carbon intensity of its operations and grow lower carbon businesses in renewable fuels, hydrogen, carbon capture, offsets, and other emerging technologies.

To grow its lower carbon businesses, Chevron plans to target sectors of the economy where emissions are harder to abate or that cannot be easily electrified, while leveraging the company’s capabilities, assets and customer relationships.

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2050 Net Zero Upstream Aspiration Chevron aspires to achieve net zero for upstream production Scope 1 and 2 GHG emissions on an equity basis by 2050.

The company believes accomplishing this aspiration depends on, among other things, partnerships with multiple stakeholders, continuing progress on commercially viable technology, government policy, successful negotiations for carbon capture and storage and nature-based projects, availability of cost-effective, verifiable offsets in the global market, and granting of necessary permits by governing authorities.

The company believes accomplishing this aspiration depends on, among other things, partnerships with multiple stakeholders including customers, continuing progress on commercially viable technology, government policy, successful negotiations for carbon capture and storage and nature-based projects, availability and acceptability of cost-effective, verifiable offsets in the global market, and granting of necessary permits by governing authorities.

2028 Upstream Production GHG Intensity Targets These metrics include Scope 1, direct emissions, and Scope 2, indirect emissions from imported electricity and steam, and are net of emissions from exported electricity and steam.

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• 26 percent reduction in gas production GHG intensity to 24 kg CO 2 e/boe,

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

• 53 percent reduction in methane intensity to 2 kg CO 2 e/boe, and

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This metric encompasses the company’s upstream and downstream business and includes Scope 1 (direct emissions), Scope 2 (indirect emissions from imported electricity and steam), and certain Scope 3 (primarily emissions from use of sold products) emissions.

The company’s PCI target is 71 grams (g) carbon dioxide equivalent (CO e) per megajoules (MJ) by 2028, a greater than five percent reduction from 2016.

Planned Lower-Carbon Capital Spend through 2028 The company increased its planned capital spend to approximately $10 billion through 2028 to advance its lower carbon strategy, which includes approximately $2 billion to lower the carbon intensity of its traditional oil and gas operations, and approximately $8 billion for lower carbon investments in renewable fuels, hydrogen and carbon capture and offsets.

We anticipate setting additional capital spending targets as the company

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

progresses toward its 2050 Upstream production Scope 1 and 2 net zero aspiration and further grows its lower carbon business lines.

Refer to “Risk Factors” in Part I, Item 1A, on pages 20 through 25 for further discussion of greenhouse gas regulation and climate change and the associated risks to Chevron’s business, including the risks impacting Chevron’s lower carbon strategy and its aspirations, targets and plans.

Response to Market Conditions and COVID-19 Commodity prices and demand for most of our products have largely recovered from the impacts of COVID-19 in 2020.

However, some countries face a resurgence of the virus and its variants (e.g., Delta, Omicron) that could impact demand for some of our products (e.g., jet fuel), workforce availability, timing of project start-ups and materials movement and pose a risk to our business and future financial results.

Chevron’s operations have continued with a combination of on-site and at-home work, while monitoring local vaccine and transmission rates.

In refining, the company continued to take steps to maximize diesel and motor gasoline production, given the decline in jet fuel demand.

In TCO, progress continued on FGP/WPMP.

Staffing is at targeted levels and at the end of December 2021, over 90 percent of the TCO workforce on-site was fully vaccinated.

The effective tax rate for the company can change substantially during periods of significant earnings volatility.

This is mainly due to mix effects that are impacted both by the absolute level of earnings or losses and whether they arise in higher or lower tax rate jurisdictions.

The company’s PCI target is 71 grams (g) carbon dioxide equivalent (CO 2 e) per megajoule (MJ) by 2028, a greater than five percent reduction from 2016.

Planned Lower-Carbon Capital Spend through 2028 In 2021, the company established planned capital spend of approximately $10 billion through 2028 to advance its lower carbon strategy, which includes approximately $2 billion to lower the carbon intensity of its traditional oil and gas operations, and approximately $8 billion for lower carbon investments in renewable fuels, hydrogen and carbon capture and offsets.

We anticipate setting additional capital spending targets as the company progresses toward its 2050 upstream production Scope 1 and 2 net zero aspiration and further grows its lower carbon business lines.

During 2021 and 2022, the company spent $4.8 billion in lower carbon investments, including $2.9 billion associated with the acquisition of REG.

Refer to “Risk Factors” in Part I, Item 1A, on pages 20 through 26 for further discussion of GHG regulation and climate change and the associated risks to Chevron’s business, including the risks impacting Chevron’s lower carbon strategy and its aspirations, targets and plans.

Income Taxes The effective tax rate for the company can change substantially during periods of significant earnings volatility.

This is due to the mix effects that are impacted by both the absolute level of earnings or losses and whether they arise in higher or lower tax rate jurisdictions.

As a result, a decline or increase in the effective income tax rate in one period may not be indicative of expected results in future periods.

Note 17 Taxes provides the company’s effective income tax rate for the last three years.

Additional information related to the company’s effective income tax rate is included in Note 17 Taxes to the Consolidated Financial Statements.

The Inflation Reduction Act (IRA), enacted in the United States on August 16, 2022, imposes several new taxes that will be effective in 2023, including a 15 percent minimum tax on book income and a 1 percent excise tax on stock repurchases.

The IRA also implements various incentives for lower carbon activities, including carbon capture and storage and the production of hydrogen and sustainable aviation fuel, and extends the federal biodiesel mixture excise tax credit through December 31, 2024.

We do not currently expect the IRA to have a material impact on our results of operations.

Supply Chain and Inflation Impacts The company is actively managing its contracting, procurement, and supply chain activities to effectively manage costs and facilitate supply chain resiliency and continuity in support of the company’s operational goals.

Third party costs for capital, exploration, and operating expenses can be subject to external factors beyond the company’s control including, but not limited to:

severe weather or civil unrest, delays in construction, global and local supply chain distribution issues, inflation, tariffs or other taxes imposed on goods or services, and market-based prices charged by the industry’s material and service providers.

Chevron utilizes contracts with various pricing mechanisms, which may result in a lag before the company’s costs reflect changes in market trends.

Inflation continued to be a key factor impacting the economy over the last year.

For key oil and gas industry inputs (e.g.

rigs, well services, etc.), markets are likely to remain tight with any upward pressure tied directly to possible increases in activity.

In contrast, inflationary pressures have started to reduce for non-oil and gas specific goods and services as a result of reduced supply chain disruptions and a slowdown in economic activity.

Chevron’s 2023 capital expenditure budget assumes cost inflation that averages in the mid-single digits with certain areas higher, such as in the Permian Basin that assumes low double-digit cost inflation.

Chevron believes it is well positioned to manage its costs for 2023, in large part due to indexed contracts and secured supplies for critical inputs.

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

Refer to the “Cautionary Statements Relevant to Forward-Looking Information” on page 2 and to “Risk Factors” in Part I, Item 1A, on pages 20 through 26 for a discussion of some of the inherent risks that could materially impact the company’s results of operations or financial condition.

The company continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value and to acquire assets or operations complementary to its asset base to help augment the company’s financial performance and value growth.

Other Impacts The company continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value and to acquire assets or operations complementary to its asset base to help augment the company’s financial performance and value growth.

Asset dispositions and restructurings may result in significant gains or losses in future periods.

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Management takes these developments into account in the conduct of daily operations and for business planning.

Comments related to earnings trends for the company’s major business areas are as follows:

The COVID-19 pandemic caused a significant decrease in demand for our products and created disruptions and volatility in the global marketplace beginning late in first quarter 2020.

Demand has largely recovered as of year-end 2022;

however, there continues to be uncertainty around the extent to which the COVID-19 pandemic may impact our future results, which could be material.

Earnings trends for the company’s major business areas are described as follows:

Upstream Earnings for the upstream segment are closely aligned with industry prices for crude oil and natural gas.

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The longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts, the pace of energy transition, and changes in tax, environmental and other applicable laws and regulations.

The company is actively managing its schedule of work, contracting, procurement, and supply chain activities to effectively manage costs and ensure supply chain resiliency and continuity in support of operational goals.

Third party costs for capital, exploration, and operating expenses can be subject to external factors beyond the company’s control including, but not limited to:

severe weather or civil unrest, delays in construction, global and local supply chain distribution issues, the general level of inflation, tariffs or other taxes imposed on goods or services, and market based prices charged by the industry’s material and service providers.

Chevron utilizes contracts with various pricing mechanisms, so there may be a lag before the company’s costs reflect changes in market trends.

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

Prices for goods and services in various sectors have risen over the past year.

A key factor behind this trend is the accelerated demand for goods and transportation as companies restock materials and expand working inventories as a hedge against future disruptions.

Shifts in the labor market continue to create issues for companies seeking to fill positions.

Geographic mismatches between skills required and available labor, reductions in the overall labor supply, and perceptions of working conditions have resulted in tight labor markets.

and international drilling activity continues to accelerate, continued upward market pressure is expected for oil and gas industry inputs (such as rigs and well services).

The pace of economic growth and shifting spending patterns may lead to more cross-industry competition for resources, which could impact the cost of certain non-oil and gas industry goods and services.

The chart above shows the trend in benchmark prices for Brent crude oil, West Texas Intermediate (WTI) crude oil and U.S.

Chevron has interests in Venezuelan assets operated by independent affiliates.

Chevron has been conducting limited activities in Venezuela consistent with the authorization provided pursuant to general licenses issued by the United States government.

In fourth quarter 2022, Chevron received License 41 from the United States government, enabling the company to resume activity in Venezuela subject to certain limitations.

The financial results for Chevron’s business in Venezuela are being recorded as non-equity investments since 2020, where income is only recognized when cash is received and production and reserves are not included in the company's results.

Crude oil liftings in Venezuela commenced in first quarter 2023, which are expected to positively impact the company’s results going forward.

Caspian Pipeline Consortium (CPC), an equity affiliate, operates a 935-mile crude oil export pipeline from the Tengiz Field in Kazakhstan to tanker-loading facilities at Novorossiysk on the Russian coast of the Black Sea, providing the main export route for crude oil production from TCO, Karachaganak and other producing fields in Kazakhstan.

The tanker loading facilities at Novorossiysk consist of three single point mooring facilities, with availability of two or more required to operate at full capacity.

CPC is capable of operating at approximately 70 percent of capacity with one single point mooring facility in service.

Two of the three offshore loading moorings at the CPC marine terminal were taken out of service during August 2022 for equipment repairs identified during normal maintenance.

Repairs were completed in fourth quarter 2022.

Production at TCO was not impacted by this CPC outage given turnaround activity at TCO and at other regional producers that ship through CPC.

However, there is a risk that production from TCO could be curtailed in the future should availability of export facilities be constrained.

Governments (including Russia) have imposed and may impose additional sanctions and other trade laws, restrictions and regulations that could lead to disruption in our ability to produce, transport and/or export crude in the region around Russia and could have an adverse effect on CPC operations and/or the company’s financial position.

The financial impacts of such risks, including presently imposed sanctions, are not currently material for the company;

however, it remains uncertain how long these conditions may last or how severe they may become.

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

Commodity Prices The following chart shows the trend in benchmark prices for Brent crude oil, West Texas Intermediate (WTI) crude oil and U.S.

Henry Hub natural gas.

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The majority of the company’s equity crude production is priced based on the Brent benchmark.

Crude prices increased in 2021 driven by production curtailment by OPEC+ countries and steadily increasing demand for transportation fuels.

Crude prices increased in 2022 driven by geopolitical risk, supply decisions by OPEC+ and continued demand recovery due to the further easing of COVID-19 restrictions.

The company’s average realization for U.S.

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The company’s average realization for international crude oil and natural gas liquids in 2022 was $91 per barrel, up 41 percent from 2021.

Prices for natural gas are more closely aligned with seasonal supply-and-demand and infrastructure conditions in local markets.

In contrast to price movements in the global market for crude oil, prices for natural gas are also impacted by regional supply and demand and infrastructure conditions in local markets.

In the United States, prices at Henry Hub averaged $6.36 per thousand cubic feet (MCF) during 2022, compared with $3.85 per MCF during 2021.

As of mid-February 2023, the Henry Hub spot price was $2.40 per MCF.

Outside the United States, prices for natural gas depend on a wide range of supply, demand and regulatory circumstances.

(See page 43 for the company’s average natural gas realizations for the U.S.).

Outside the United States, prices for natural gas also depend on a wide range of supply, demand and regulatory circumstances.

The company’s long-term contract prices for liquefied natural gas (LNG) are typically linked to crude oil prices.

Most of the equity LNG offtake from the operated Australian LNG projects is committed under binding long-term contracts, with some sold in the Asian spot LNG market.

International natural gas realizations averaged $5.93 per MCF during 2021, compared with $4.59 per MCF during 2020.

(See page 42 for the company’s average natural gas realizations for the U.S.

and international regions.)

The company’s worldwide net oil-equivalent production in 2021 was a record 3.099 million barrels per day.

International natural gas realizations averaged $9.75 per MCF during 2022, compared with $5.93 per MCF during 2021, mainly due to higher LNG prices.

Production The company’s worldwide net oil-equivalent production in 2022 was 3 million barrels per day.

About 27 percent of the company’s net oil-equivalent production in 2022 occurred in OPEC+ member countries of Angola, Equatorial Guinea, Kazakhstan, Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait and Republic of Congo.

The company estimates that its net oil-equivalent production in 2022 will be flat to down 3 percent compared to 2021, assuming a Brent crude oil price of $60 per barrel and excluding the impact of asset sales that may close in 2022.

The company estimates its net oil-equivalent production in 2023, assuming a Brent crude oil price of $80 per barrel, to be flat to up 3 percent compared to 2022.

This estimate is subject to many factors and uncertainties, including quotas or other actions that may be imposed by OPEC+;

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fluctuations in demand for crude oil and natural gas in various markets;

weather conditions that may shut in

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

weather conditions that may shut in production;

civil unrest;

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The company has increased its investment emphasis on short-cycle projects.

In January 2022, Chevron announced its intent to begin the process of exiting from its nonoperated interests in Myanmar.

At December 31, 2021, the carrying value of the company’s assets was approximately $200 million.

Net proved reserves for consolidated companies and affiliated companies totaled 11.3 billion barrels of oil-equivalent at year-end 2021, an increase of 1 percent from year-end 2020.

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

Proved Reserves Net proved reserves for consolidated companies and affiliated companies totaled 11.2 billion barrels of oil-equivalent at year-end 2022, a slight decrease from year-end 2021.

The reserve replacement ratio in 2022 was 97 percent.

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Other factors beyond the company’s control include the general level of inflation and energy costs to operate the company’s refining, marketing and petrochemical assets, and changes in tax, environmental, and other applicable laws and regulations.

Refining margins were higher in 2022 because of recovering demand for refined products, low product inventories, lower industry refining capacity and lower product exports from Russia and China.

Refining utilization was strong in 2022 to keep pace with demand growth.

Although refining margins were elevated and still remain above historical levels, they fell considerably in late 2022.

There are signs that higher refined product prices and concerns over macroeconomic conditions are slowing demand.

The company’s most significant marketing areas are the West Coast and Gulf Coast of the United States and Asia Pacific.

Chevron operates or has significant ownership interests in refineries in each of these areas.

Additionally, the company has a small but growing presence in renewable fuels.

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

Additionally, the company has a growing presence in renewable fuels after acquiring REG.

Refer to the “Results of Operations” section on page 40 for additional discussion of the company’s downstream operations.

All Other consists of worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities and technology companies.

Operating Developments

Key operating developments and other events during 2021 and early 2022 included the following:

Angola Chevron’s affiliate, Cabinda Gulf Oil Company Limited (CABGOC), signed an agreement to extend the Block 0 concession for 20 years, through 2050.

Australia Sanctioned the Jansz-Io compression project, a part of the Gorgon development and an important source of natural gas supply to the Gorgon LNG facility.

Brazil Completed the sale of the company's 37.5 percent nonoperated interest in the Papa-Terra oil field.

Equatorial Guinea Announced the start-up and first LNG cargo from the Alen Gas Monetization Project.

Japan Announced the signing of a binding Sale and Purchase Agreement with Hokkaido Gas Co., Ltd.

for the delivery of about a half million tons of LNG over a period of five years, starting in 2022.

United States Entered FEED for the Ballymore project, which is being developed as a subsea tieback to the existing Blind Faith facility, in the deepwater Gulf of Mexico.

United States Sanctioned the Whale project in the deepwater Gulf of Mexico.

Finland Announced an agreement to acquire Neste Oyj’s Group III base oil business, including its related sales and marketing business, and brand NEXBASE TM .

South Korea Chevron’s 50 percent owned affiliate, GS Caltex, started up an olefins mixed-feed cracker and associated polyethylene unit at its Yeosu refinery ahead of schedule and under budget.

United States Announced the commissioning and start-up of the world’s first commercial-scale ISOALKY™ process unit at the Salt Lake City Refinery.

This proprietary technology uses ionic liquids to produce a high octane gasoline blending component as a cost-effective alternative to conventional alkylation technologies and offers environmental and process safety advantages.

United States Began producing renewable diesel at the El Segundo, California refinery by co-processing bio-feedstock.

United States Announced establishment of its first branded Compressed Natural Gas (CNG) station, as part of its plan to sell RNG through more than 30 CNG stations in California by 2025.

United States Acquired an equity interest in American Natural Gas LLC (now Beyond6, LLC) and its network of 60 compressed natural gas stations across the United States to grow its RNG value chain.

United States Announced the second expansion of its joint venture, Brightmark RNG Holdings LLC, to own projects across the United States to produce and market dairy biomethane, a RNG.

First gas delivery at the Lawnhurst site in New York was announced in November.

United States Announced the launch of Havoline® PRO-RS™ Renewable Full Synthetic Motor Oil made with 25 percent sustainably sourced plant-based oils.

United States Celebrated the opening of the 1,000th ExtraMile Convenience store.

United States Chevron’s 50 percent owned affiliate, CPChem, announced the first commercial sales of their Marlex® Anew™ Circular Polyethylene, which uses advanced recycling technology to process pyrolysis oil, a feedstock made from difficult-to-recycle waste plastics.

United States Announced the signing of definitive transaction agreements to create a joint venture with Bunge North America, Inc., to own and operate soybean processing facilities.

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

United States Announced the launch of Chevron’s $300 million Future Energy Fund II focused on technologies that have the potential to enable affordable, reliable, and ever-cleaner energy for all.

United States Announced plans with partners to develop carbon negative bioenergy in Mendota, California.

United States Announced memorandums of understanding with Toyota Motors North America, Inc.

to explore a strategic alliance to catalyze and lead the development of commercially viable, large-scale businesses in hydrogen;

with Cummins Inc.

to explore a strategic alliance to develop commercially viable business opportunities in hydrogen and other alternative energy sources;

with Delta Air Lines, Inc.

and Google LLC to track sustainable aviation fuel test batch emissions data using cloud-based technology;

and with Progress Rail Locomotive Inc., a Caterpillar company, and BNSF Railway Company to demonstrate hydrogen-fueled locomotives.

United States Acquired all of the publicly held common units representing limited partner interests in Noble Midstream Partners LP not already owned by Chevron and its affiliates.

United States Announced a collaboration agreement with Caterpillar Inc.

to develop hydrogen demonstration projects in transportation and stationary power applications, including prime power.

United States Announced a letter of intent with Gevo, Inc.

to jointly invest in building and operating one or more new facilities that process inedible corn to produce sustainable aviation fuel.

United States Announced agreement on a framework to acquire an equity interest in ACES Delta, LLC that owns the Advanced Clean Energy Storage project.

This project aims to produce, store and transport green hydrogen at utility scale.

United States Announced a framework with Enterprise Product Partners L.P.

to study and evaluate opportunities for carbon dioxide capture, utilization, and storage from their respective business operations in the U.S.

Midcontinent and Gulf Coast.

United States Invested in companies to access lower-carbon technologies, including Baseload Capital AB (low-temperature geothermal and heat power), Starfire Energy (carbon-free ammonia and carbon-free hydrogen), Ocergy, Inc.

(floating offshore and wind turbine technology), Mainspring (lower-carbon generators for electric grids), Raygen (solar-hydro plant with storage), Boomitra (soil carbon offset platform), Natel Energy (hydro-power based technology), Raven SR Inc.

(modular waste-to-green hydrogen and renewable synthetic fuel facilities), Sapphire Technologies (waste energy recovery systems), Hydrogenious LOHC Technologies (liquid organic hydrogen carriers), gr3n SA (plastics recycling technology), Malta Inc.

(thermal energy storage) and Ionomr Innovations Inc.

(ion-exchange membranes and polymers).

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

Noteworthy Developments

Key noteworthy developments and other events during 2022 and early 2023 included the following:

Angola Announced final investment decision for gas development projects at the Quiluma and Maboqueiro (Q&M) fields.

Argentina Received a concession for the development of unconventional hydrocarbon resources in the east area of the El Trapial field for a 35-year period.

Australia Received permits, as part of joint ventures, to assess carbon storage for three blocks totaling nearly 7.8 million acres in offshore Australia.

Canada Invested in Aurora Hydrogen, a company developing emission-free hydrogen production technology.

Egypt Made a significant gas discovery at the Nargis block offshore Egypt in the eastern Mediterranean Sea.

Finland Acquired Neste Oyj’s Group III base oil business, including its related sales and marketing business, and NEXBASE TM brand.

Israel Approved a project to expand the company’s Tamar gas field in offshore Israel.

Namibia Entered Namibia by acquiring an 80 percent working interest in a deepwater oil and gas exploration lease.

Nigeria Extended Agbami and Usan leases to 2042.

Qatar Reached final investment decision with QatarEnergy on Ras Laffan Petrochemicals Complex through the company’s 50 percent owned affiliate, Chevron Phillips Chemical Company LLC (CPChem).

Republic of Congo Extended the Haute Mer production sharing contract to 2040.

United States Completed the sale of the company’s interest in the Eagle Ford Shale in Texas.

United States Approved the Ballymore project in the deepwater U.S.

Gulf of Mexico.

The field is planned to be produced through an existing facility with an allocated capacity of 75,000 barrels of crude oil per day.

United States Completed Project Canary pilot to independently certify operational and environment performance and earned highest certification rating for almost all participating Permian and DJ basins upstream assets, positioning the company to market responsibly sourced natural gas from the certified assets.

United States Acquired a 50 percent stake in an expanded joint venture to develop the Bayou Bend Carbon Capture and Sequestration (CCS) hub, with the goal of the hub becoming one of the first offshore CCS projects in the United States.

United States Formed a joint venture with Bunge North America, Inc.

to develop renewable fuel feedstocks, leveraging Bunge’s expertise in oilseed processing and farmer relationships and Chevron’s expertise in fuels manufacturing and marketing.

United States Acquired REG, becoming the second largest producer of bio-based diesel in the United States.

United States Awarded 34 exploration leases in the Gulf of Mexico.

United States Announced investment in a new joint venture with California Bioenergy LLC to build infrastructure for the company’s dairy biomethane projects in California.

United States Commenced a project expected to increase light crude oil processing capacity to 125,000 barrels per day at the company’s Pasadena, Texas refinery.

United States Reached final investment decision on a major integrated polymer project (Golden Triangle Polymers) in the U.S.

Gulf Coast at its 50 percent owned affiliate, CPChem.

United States Completed construction of a joint venture solar energy project to generate renewable energy for the company’s oil and gas operations in the Permian Basin.

United States Acquired full ownership of Beyond6, LLC and its nationwide network of 55 compressed natural gas stations to grow Chevron’s renewable natural gas value chain.

United States Announced joint venture with Baseload Capital to develop geothermal projects.

United States Announced collaboration with Raven SR Inc.

and Hyzon Motors to produce hydrogen from green waste.

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

United States Announced agreements or investments in companies to access and possibly develop lower carbon technologies, including Iwatani Corporation (hydrogen fueling sites), Carbon Clean Solutions Limited (carbon capture), TAE Technologies (nuclear fusion) and Svante Technology Inc.

(carbon capture).

Common Stock Dividends The 2022 annual dividend was $5.68 per share, making 2022 the 35th consecutive year that the company increased its annual per share dividend payout.

In January 2023, the company’s Board of Directors increased its quarterly dividend by $0.09 per share, approximately six percent, to $1.51 per share payable in March 2023.

Common Stock Repurchase Program The company resumed stock repurchases in third quarter 2021 and purchased $1.4 billion of its common stock in 2021 under its stock repurchase program.

The company currently expects to repurchase $1.25 billion of its common stock during the first quarter of 2022.

Common Stock Repurchase Program The company repurchased $11.25 billion of its common stock in 2022 under its stock repurchase program.

For more information on the common stock repurchase program, see Liquidity and Capital Resources .

Results of Operations

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and international geographic areas of the Upstream and Downstream business segments.

Refer to Note 14 Operating Segments and Geographic Data for a discussion of the company’s “reportable segments.” This section should also be read in conjunction with the discussion in “Business Environment and Outlook” on pages 32 through 37.

Refer to the “Selected Operating Data” table on page 42 for a three-year comparison of production volumes, refined product sales volumes, and refinery inputs.

Refer to the Selected Operating Data for a three-year comparison of production volumes, refined product sales volumes and refinery inputs.

A discussion of variances between 2021 and 2020 can be found in the “Results of Operations” section on pages 39 through 40 of the company’s 2021 Annual Report on Form 10-K filed with the SEC on February 24, 2022.

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

Millions of dollars 2022 2021 2020

Earnings (Loss) $ 12,621 $ 7,319 $ (1,608)

upstream reported earnings of $7.3 billion in 2021, compared with a loss of $1.6 billion in 2020.

The increase was due to higher realizations of $6.9 billion, the absence of 2020 impairments and write-offs of $1.2 billion, higher sales volumes of $760 million, and higher asset sales gains of $640 million.

upstream reported earnings of $12.6 billion in 2022, compared with $7.3 billion in 2021.

The increase was due to higher realizations of $6.6 billion and higher sales volumes of $380 million, partially offset by higher operating expenses of $1.1 billion largely due to an early contract termination at Sabine Pass and lower asset sale gains of $670 million.

The company’s average realization for U.S.

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Net oil-equivalent production in 2022 averaged 1.18 million barrels per day, up 4 percent from 2021.

The increase was due to an additional 162,000 barrels per day of production from the Noble Energy acquisition, partially offset by a 63,000 barrels per day decrease related to the Appalachian asset sale.

The increase was primarily due to net production increases in the Permian Basin.

The net liquids component of oil-equivalent production for 2022 averaged 888,000 barrels per day, up 3 percent from 2021.

Net natural gas production averaged 1.76 billion cubic feet per day in 2022, an increase of 4 percent from 2021.

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

International Upstream

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$ 816 $ 302 $ (285)

International upstream reported earnings of $8.5 billion in 2021, compared with a loss of $825 million in 2020.

The increase was primarily due to higher realizations of $7.6 billion, along with the absence of 2020 impairments and write-offs of $3.6 billion and severance charges of $290 million.

Partially offsetting these increases are higher tax charges of $630 million, the absence of 2020 asset sales gains of $550 million, and higher depreciation expenses of $670 million and lower sales volumes of $540 million.

International upstream reported earnings of $17.7 billion in 2022, compared with $8.5 billion in 2021.

The increase was primarily due to higher realizations of $10.0 billion, lower operating expenses, lower depreciation, depletion and amortization related to end of concessions in Indonesia and Thailand of $1.3 billion and asset sale gains of $220 million.

This was partially offset by lower sales volumes of $1.3 billion (also largely associated with the end of concessions in Indonesia and Thailand) and write-off and impairment charges of $1.1 billion.

Foreign currency effects had a favorable impact on earnings of $514 million between periods.

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International net oil-equivalent production was 1.82 million barrels per day in 2022, down 7 percent from 2021.

The decrease was primarily due to the absence of 69,000 barrels per day following expiration of the Rokan concession in

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

Indonesia, unfavorable entitlement effects, normal field declines and the effect of asset sales, partially offset by 113,000 barrels per day associated with the Noble Energy acquisition and lower production curtailments.

The decrease was primarily due to lower production following expiration of the Erawan concession in Thailand and Rokan concession in Indonesia.

The net liquids component of international oil-equivalent production was 831,000 barrels per day in 2022, a decrease of 13 percent from 2021.

International net natural gas production of 6.02 billion cubic feet per day in 2021 increased 6 percent from 2020.

International net natural gas production of 5.92 billion cubic feet per day in 2022, a decrease of 2 percent from 2021.

Millions of dollars 2022 2021 2020

Earnings (Loss) $ 5,394 $ 2,389 $ (571)

downstream reported earnings of $2.4 billion in 2021, compared with a loss of $571 million in 2020.

The increase was primarily due to higher margins on refined product sales of $1.6 billion, higher earnings from 50 percent-owned CPChem of $1.0 billion and higher sales volumes of $470 million, partially offset by higher operating expenses of $150 million.

Total refined product sales of 1.14 million barrels per day in 2021 increased 14 percent from 2020, mainly due to higher gasoline, jet fuel, and diesel demand as travel restrictions associated with the COVID-19 pandemic continue to ease.

downstream reported earnings of $5.4 billion in 2022, compared with $2.4 billion in 2021.

The increase was primarily due to higher margins on refined product sales of $4.4 billion, partially offset by lower earnings from the 50 percent-owned CPChem of $790 million and higher operating expenses of $790 million, largely due to planned turnarounds.

Total refined product sales of 1.23 million barrels per day in 2022 increased 8 percent from 2021, mainly due to higher renewable fuel sales following the REG acquisition and higher jet fuel demand.

International Downstream

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$ 235 $ 185 $ (152)

International downstream earned $525 million in 2021, compared with $618 million in 2020.

The decrease in earnings was largely due to lower margins on refined product sales of $330 million and higher operating expenses of $100 million, partially offset by a favorable swing in foreign currency effects of $337 million between periods.

Total refined product sales of 1.32 million barrels per day in 2021 were up 8 percent from 2020, mainly due to the second quarter 2020 acquisition of Puma Energy (Australia) Holdings Pty Ltd.

and higher diesel and gasoline demand, partially offset by lower jet fuel demand.

International downstream earned $2.8 billion in 2022, compared with $525 million in 2021.

The increase in earnings was mainly due to higher margins on refined product sales of $2.7 billion and a favorable swing in foreign currency effects of $50 million between periods, partially offset by higher operating expenses of $650 million, largely due to transportation costs.

Total refined product sales of 1.39 million barrels per day in 2022 were up 5 percent from 2021, mainly due to higher jet fuel demand as travel restrictions associated with the COVID-19 pandemic continue to ease.

Millions of dollars 2022 2021 2020

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Net charges in 2022 decreased $133 million from 2021.

The change between periods was mainly due to the absence of 2020 severance, Noble acquisition and mining remediation costs, and lower corporate charges, partially offset by higher employee benefit costs and a loss on early retirement of debt.

Foreign currency effects decreased net charges by $27 million between periods.

The change between periods was mainly due to lower pension settlement expense, loss on early debt retirement and lower interest expense, partially offset by the absence of 2021 favorable tax items and higher interest income.

Foreign currency effects increased net charges by $201 million between periods.

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

Consolidated Statement of Income

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Sales and other operating revenues $ 235,717 $ 155,606 $ 94,471

Sales and other operating revenues increased in 2021 mainly due to higher refined product, crude oil, and natural gas prices and sales volumes .

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

Sales and other operat ing revenues increased in 2022 mainly due to higher refined product, crude oil, and natural gas prices and higher refined product sales volumes.

Millions of dollars 2022 2021 2020

Income (loss) from equity affiliates $ 8,585 $ 5,657 $ (472)

Income from equity affiliates improved in 2021 mainly due to the absence of the full impairment of Petropiar and Petroboscan in Venezuela in 2020, higher upstream-related earnings from Tengizchevroil in Kazakhstan and Angola LNG, and higher downstream-related earnings from CPChem and GS Caltex in Korea.

Income from equity affiliates improved in 2022 mainly due to higher upstream-related earnings from Tengizchevroil in Kazakhstan and Angola LNG and higher downstream-related earnings from GS Caltex in Korea, partially offset by lower earnings from CPChem.

Refer to Note 15 Investments and Advances for a discussion of Chevron’s investments in affiliated companies.

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Other income $ 1,950 $ 1,202 $ 693

Other income increased in 2021 mainly due to a favorable swing in foreign currency effects and higher gains on asset sales, partially offset by losses on the early retirement of debt.

Other income increased in 2022 mainly due to a favorable swing in foreign currency effects, higher interest income and lower charges associated with the early retirement of debt, partially offset by lower gains on asset sales.

Millions of dollars 2022 2021 2020

Purchased crude oil and products $ 145,416 $ 92,249 $ 52,148

Crude oil and product purchases increased in 2021 primarily due to higher crude oil, natural gas, and refined product prices and higher refined product volumes.

Crude oil and product purchases increased in 2022 primarily due to higher crude oil, natural gas, and refined product prices.

Millions of dollars 2022 2021 2020

Operating, selling, general and administrative expenses $ 29,026 $ 24,740 $ 24,536

Operating, selling, general and administrative expenses increased in 2021 primarily due to higher employee benefit and transportation costs partially offset by the absence of 2020 severance accruals.

Operating, selling, general and administrative expenses increased in 2022 primarily due to higher transportation expenses, early contract termination charge at Sabine Pass and costs associated with planned refinery turnarounds.

Millions of dollars 2022 2021 2020

Exploration expense $ 974 $ 549 $ 1,537

Exploration expenses in 2021 decreased primarily due to lower charges for well write-offs .

Exploration expenses in 2022 increased primarily due to higher charges for well write-offs.

Millions of dollars 2022 2021 2020

Depreciation, depletion and amortization $ 16,319 $ 17,925 $ 19,508

Depreciation, depletion and amortization expenses decreased in 2021 primarily due to lower impairment charges, partially offset by higher rates and production .

Depreciation, depletion and amortization expenses decreased in 2022 primarily due to lower rates and lower production, partially offset by higher impairment and write-off charges.

Millions of dollars 2022 2021 2020

Taxes other than on income $ 4,032 $ 3,963 $ 2,839

Taxes other than on income increased in 2021 primarily due to higher regulatory expenses, taxes on production and excise taxes, which was primarily driven by higher refined product sales in Australia.

Taxes other than on income increased in 2022 primarily due to higher taxes on production, partially offset by lower excise taxes.

Millions of dollars 2022 2021 2020

Interest and debt expense $ 516 $ 712 $ 697

Interest and debt expenses increased in 2021 mainly due to interest expense associated with debt acquired in the Noble Energy acquisition.

Interest and debt expenses decreased in 2022 mainly due to lower debt balances.

Millions of dollars 2022 2021 2020

Other components of net periodic benefit costs $ 295 $ 688 $ 880

Other components of net periodic benefit costs decreased in 2021 primarily due to lower interest costs.

Other components of net periodic benefit costs decreased in 2022 primarily due to lower pension settlement costs, as fewer lump-sum pension distributions were made in the current year.

Millions of dollars 2022 2021 2020

Income tax expense (benefit) $ 14,066 $ 5,950 $ (1,892)

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

The increase in income tax expense in 2022 of $8.1 billion is due to the increase in total income before tax for the company of $28.0 billion.

The increase in income before taxes for the company is primarily the result of higher upstream realizations, the absence of 2020 impairments and write-offs, and higher downstream margins.

income before tax increased from a loss of $5.70 billion in 2020 to income of $9.67 billion in 2021.

This $15.37 billion increase in income was primarily driven by higher upstream realizations, higher downstream margins and the absence of 2020 impairments and write-offs.

The increase in income before taxes for the company is primarily the result of higher upstream realizations and downstream margins.

income before tax increased from $9.7 billion in 2021 to $21.0 billion in 2022.

This $11.3 billion increase in income was primarily driven by higher upstream realizations and downstream margins, partially offset by higher operating expenses and lower asset sale gains.

The increase in income had a direct impact on the company’s U.S.

income tax resulting in an increase to tax expense of $3.18 billion between year-over-year periods, from a tax benefit of $1.58 billion in 2020 to a charge of $1.60 billion in 2021.

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

International income before tax increased from a loss of $1.75 billion in 2020 to income of $11.97 billion in 2021.

This $13.72 billion increase in income was primarily driven by higher upstream realizations and the absence of 2020 impairments and write-offs.

The increased income primarily drove the $4.66 billion increase in international income tax expense between year-over-year periods, from a tax benefit of $308 million in 2020 to a charge of $4.35 billion in 2021.

income tax resulting in an increase to tax expense of $2.9 billion between year-over-year periods, from $1.6 billion in 2021 to $4.5 billion in 2022.

International income before tax increased from $12.0 billion in 2021 to $28.7 billion in 2022.

This $16.7 billion increase in income was primarily driven by higher upstream realizations and downstream margins.

The increased income primarily drove the $5.2 billion increase in international income tax expense between year-over-year periods, from $4.3 billion in 2021 to $9.6 billion in 2022.

Refer also to the discussion of the effective income tax rate in Note 17 Taxes .

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

Selected Operating Data 1,2

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Sales of Natural Gas (MMCFPD) 4

4,354 3,986 3,873

Sales of Natural Gas Liquids (MBPD) 276 201 208

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Total Refined Product Sales (MBPD) 1,228 1,139 1,003

Sales of Natural Gas (MMCFPD) 4

Sales of Natural Gas Liquids (MBPD) 27 29 25

Refinery Input (MBPD) 6

Refinery Crude Oil Input (MBPD) 866 903 793

International Downstream

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1,386 1,315 1,221

Sales of Natural Gas (MMCFPD) 4

Sales of Natural Gas Liquids (MBPD) 127 96 74

Refinery Input (MBPD) 576 584 617

Refinery Crude Oil Input (MBPD) 639 576 584

1 Includes company share of equity affiliates.

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International 517 548 566

4 Downstream sales of Natural Gas separately identified from Upstream.

5 Includes net production of synthetic oil:

Canada 45 55 54

Venezuela affiliate — — 3

6 Includes branded and unbranded gasoline.

6 In May 2019, the company acquired the Pasadena Refinery in Pasadena, Texas, which has an operable capacity of 110,000 barrels per day.

7 Includes sales of affiliates (MBPD):

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

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

Liquidity and Capital Resources

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Cash, Cash Equivalents and Marketable Securities Total balances were $17.9 billion and $5.7 billion at December 31, 2022 and 2021, respectively.

Cash provided by operating activities in 2021 was $29.2 billion, compared to $10.6 billion in 2020, primarily due to higher crude oil and natural gas prices.

Cash provided by operating activities in 2022 was $49.6 billion, compared to $29.2 billion in 2021, primarily due to higher upstream realizations and refining margins.

Cash provided by operating activities was net of contributions to employee pension plans of approximately $1.3 billion in 2022 and $1.8 billion in 2021.

Cash provided by investing activities included proceeds and deposits related to asset sales of $1.4 billion in 2021 and $2.9 billion in 2020.

Proceeds and deposits related to asset sales totaled $1.4 billion in each of the last two years.

Returns of investment totaled $1.2 billion and $439 million in 2022 and 2021, respectively.

The returns of investment in 2022 were primarily from Angola LNG.

As of third quarter 2022, Angola LNG distributions were, and are expected to continue to be, largely reflected in cash flow from operations.

Cash flow from financing activities includes proceeds from shares issued for stock options of $5.8 billion in 2022, compared with $1.4 billion in 2021.

Future cash proceeds from option exercises are expected to be lower than in 2022.

Restricted cash of $1.4 billion and $1.2 billion at December 31, 2022 and 2021, respectively, was held in cash and short-term marketable securities and recorded as “Deferred charges and other assets” and “Prepaid expenses and other current assets” on the Consolidated Balance Sheet.

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Debt and Finance Lease Liabilities Total debt and finance lease liabilities were $23.3 billion at December 31, 2022, down from $31.4 billion at year-end 2021.

The $12.9 billion decrease in total debt and finance lease liabilities during 2021 was primarily due to the repayment of long-term notes that matured during the year, the early retirement of long-term notes and the credit facility held by Noble Midstream Partners LP, and the elimination of borrowings under the company’s commercial paper program.

The company completed a tender offer, with the objective of lowering future interest expenses, and redeemed bonds with a book value (including fair market price adjustments) of $3.4 billion in October 2021.

The $8.1 billion decrease in total debt and finance lease liabilities during 2022 was primarily due to the repayment of long-term notes that matured during the year and the early retirement of long-term notes.

The company’s debt and finance lease liabilities due within one year, consisting primarily of the current portion of long-term debt and redeemable long-term obligations, totaled $6.0 billion at December 31, 2022, compared with $8.0 billion at year-end 2021.

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At year-end 2022, settlement of these obligations was not expected to require the use of working capital in 2023, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

The company has an automatic shelf registration statement that expires in August 2023 for an unspecified amount of nonconvertible debt securities issued by Chevron Corporation or CUSA.

The company has access to a commercial paper program as a financing source for working capital or other short-term needs.

The company had no commercial paper outstanding as of December 31, 2022.

The company has an automatic shelf registration statement that expires in August 2023 for an unspecified amount of nonconvertible debt securities issued by Chevron Corporation or Chevron U.S.A.

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

The major debt rating agencies routinely evaluate the company’s debt, and the company’s cost of borrowing can increase or decrease depending on these debt ratings.

The company has outstanding public bonds issued by Chevron Corporation,

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

CUSA, Noble, and Texaco Capital Inc.

The company has outstanding public bonds issued by Chevron Corporation, CUSA, Noble Energy, Inc.

(Noble), and Texaco Capital Inc.

Most of these securities are the obligations of, or guaranteed by, Chevron Corporation and are rated AA- by Standard and Poor’s Corporation and Aa2 by Moody’s Investors Service.

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Total net equity (deficit) $ (76,681) $ (58,902)

Common Stock Repurchase Program The Board of Directors authorized a stock repurchase program in 2019, with a maximum dollar limit of $25 billion and no set term limits.

Common Stock Repurchase Program The Board of Directors authorized a stock repurchase program in 2019, with a maximum dollar limit of $25 billion and no set term limits (the “2019 Program”).

During 2022, the company purchased 69.9 million shares for $11.25 billion under the 2019 Program.

As of December 31, 2022, the company had purchased a total of 131.4 million shares for $18.1 billion, resulting in $6.9 billion remaining under the 2019 Program.

The company currently expects to repurchase $1.25 billion of its common stock during the first quarter of 2022.

Repurchases may be made from time to time in the open market, by block purchases, in privately negotiated transactions, or in such other manner as determined by the company.

The timing of the repurchases and the actual amount repurchased will depend on a variety of factors, including the market price of the company’s shares, general market and economic conditions, and other factors.

The stock repurchase program does not obligate the company to acquire any particular amount of common stock, and it may be suspended or discontinued at any time.

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

Capital and Exploratory Expenditures

Capital and exploratory expenditures by business segment for 2021, 2020 and 2019 are as follows:

2021 2020 2019

The company currently expects to repurchase $3.75 billion of its common stock during the first quarter of 2023 under the 2019 Program and will incur an additional one percent excise tax on such purchases as required by the IRA.

On January 25, 2023, the Board of Directors authorized the repurchase of the company’s shares of common stock in an aggregate amount of $75 billion .

The $75 billion authorization takes effect on April 1, 2023 and does not have a fixed expiration date (the “2023 Program”).

It replaces the Board’s previous repurchase authorization of $25 billion from January 2019, which will terminate on March 31, 2023, after the completion of the company’s repurchases in the first quarter of 2023.

Repurchases of shares of the company’s common stock may be made from time to time in the open market, by block purchases, in privately negotiated transactions or in such other manner as determined by the company.

The timing of the

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

repurchases and the actual amount repurchased will depend on a variety of factors, including the market price of the company’s shares, general market and economic conditions, and other factors.

The stock repurchase program does not obligate the company to acquire any particular amount of common stock and may be suspended or discontinued at any time.

Capital Expenditures Capital expenditures (Capex) primarily includes additions to fixed asset or investment accounts for the company’s consolidated subsidiaries and is disclosed in the Consolidated Statement of Cash Flows.

Capex by business segment for 2022, 2021 and 2020 is as follows:

Year ended December 31

Capex 2022 2021 2020

Millions of dollars U.S.

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All Other 310 25 335 221 20 241 226 13 239

Total $ 6,154 $ 5,566 $ 11,720 $ 6,377 $ 7,122 $ 13,499 $ 10,430 $ 10,564 $ 20,994

Total, Excluding Equity in Affiliates $ 5,787 $ 2,766 $ 8,553 $ 6,053 $ 3,464 $ 9,517 $ 10,062 $ 4,820 $ 14,882

Total reported expenditures for 2021 were $11.7 billion, including $3.2 billion for the company’s share of equity-affiliate expenditures, which did not require cash outlays by the company.

In 2020, expenditures were $13.5 billion, including the company’s share of affiliates’ expenditures of $4.0 billion.

The acquisition of Noble is not included in the company’s capital and exploratory expenditures.

Of the $11.7 billion of expenditures in 2021, 82 percent, or $9.6 billion, related to upstream activities.

Approximately 81 percent was expended for upstream operations in 2020.

International upstream accounted for 51 percent of the worldwide upstream investment in 2021 and 53 percent in 2020.

The company estimates that 2022 organic capital and exploratory expenditures will be approximately $15 billion, including $3.6 billion of spending by affiliates, an increase of over 25 percent from 2021 expenditures.

This includes approximately $800 million in lower carbon spending that aims to reduce the carbon intensity of the company’s operations and grow its lower carbon businesses.

In the upstream business, approximately $8 billion is allocated to currently producing assets, including about $3 billion for Permian Basin unconventional development and approximately $1.5 billion for other shale and tight assets worldwide.

Additionally, $3 billion of the upstream program is planned for major capital projects underway, of which about $2 billion is associated with the FGP/WPMP at the Tengiz field in Kazakhstan.

Finally, approximately $1.5 billion is allocated to exploration, early-stage development projects, midstream activities and carbon reduction opportunities.

Worldwide downstream spending in 2022 is estimated to be $2.3 billion, including capital targeted to grow renewable fuels and products businesses.

Capex $ 8,856 $ 3,118 $ 11,974 $ 5,581 $ 2,475 $ 8,056 $ 5,803 $ 3,119 $ 8,922

Capex for 2022 was $12.0 billion, 49 percent higher than 2021 due to increased upstream spend in the Permian Basin along with higher spend in downstream, largely related to the formation of the Bunge North America, Inc.

(Bunge) joint venture and acquisition of the remaining interest in Beyond6, LLC (Beyond6).

The company estimates that 2023 Capex will be approximately $14 billion.

In the upstream business, Capex is estimated to be $11.5 billion and includes more than $4 billion for Permian Basin development and roughly $2 billion for other shale & tight assets.

More than 20 percent of upstream Capex is planned for projects in the Gulf of Mexico.

Worldwide downstream spending in 2023 is estimated to be $1.9 billion.

Investments in technology businesses and other corporate operations in 2023 are budgeted at $0.6 billion.

The company monitors crude oil market conditions and can adjust future capital outlays should oil price conditions deteriorate.

Noncontrolling Interests The company had noncontrolling interests of $873 million at December 31, 2021 and $1.0 billion at December 31, 2020.

Lower carbon Capex across all segments totals around $2 billion, including approximately $0.5 billion to lower the carbon intensity of Chevron’s traditional operations and about $1 billion to increase renewable fuels production capacity.

Affiliate capital expenditures (Affiliate Capex), which does not require cash outlays by the company, is expected to be $3 billion in 2023.

Nearly half of Affiliate Capex is for Tengizchevroil’s FGP / WPMP Project in Kazakhstan and about a third is for CPChem.

Capital and Exploratory Expenditures Capital and exploratory expenditures (C&E) is a key performance indicator and provides the company’s investment level in its consolidated companies.

This metric includes additions to fixed asset or investment accounts along with exploration expense for its consolidated companies.

Management uses this metric along with Affiliate C&E (as defined below) to manage the allocation of capital across the company’s entire portfolio, funding requirements and ultimately shareholder distributions.

The components of C&E are presented in the following table:

Year ended December 31

Millions of dollars 2022 2021 2020

Capital expenditures $ 11,974 $ 8,056 $ 8,922

Expensed exploration expenditures 488 431 500

Assets acquired through finance leases and other obligations 3 64 53

Payments for other assets and liabilities, net (169) 2 42

Capital and exploratory expenditures (C&E) $ 12,296 $ 8,553 $ 9,517

Affiliate capital and exploratory expenditures (Affiliate C&E) $ 3,366 $ 3,167 $ 3,982

C&E by business segment for 2022, 2021 and 2020 is as follows:

Year ended December 31

C&E 2022 2021 2020

Millions of dollars U.S.

Upstream $ 6,980 $ 3,073 $ 10,053 $ 4,696 $ 2,512 $ 7,208 $ 5,130 $ 2,867 $ 7,997

Downstream 1,702 206 1,908 870 234 1,104 697 584 1,281

All Other 310 25 335 221 20 241 226 13 239

C&E $ 8,992 $ 3,304 $ 12,296 $ 5,787 $ 2,766 $ 8,553 $ 6,053 $ 3,464 $ 9,517

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

C&E for 2022 was $12.3 billion, 44 percent higher than 2021 due to increased upstream spend in the Permian Basin along with higher spend in downstream, largely related to the formation of the Bunge joint venture and acquisition of the remaining interest in Beyond6.

The acquisitions of Renewable Energy Group Inc.

and Noble are not included in the company’s C&E or Capex.

Affiliate Capital and Exploratory Expenditures Equity affiliate capital and exploratory expenditures (Affiliate C&E) is also a key performance indicator that provides the company’s share of investments in its significant equity affiliate companies.

This metric includes additions to fixed asset and investment accounts along with exploration expense in the equity affiliate companies’ financial statements.

Management uses this metric to assess possible funding needs and/or shareholder distribution capacity of the company’s equity affiliate companies.

Together with C&E, management also uses Affiliate C&E to manage allocation of capital across the company’s entire portfolio, funding requirements and ultimately shareholder distributions.

Affiliate C&E, which is the same as Affiliate Capex spend, by business segment for 2022, 2021 and 2020 is as follows:

Year ended December 31

Affiliate C&E 2022 2021 2020

Millions of dollars U.S.

Upstream $ — $ 2,406 $ 2,406 $ 2 $ 2,404 $ 2,406 $ — $ 2,917 $ 2,917

Downstream 768 192 960 365 396 761 324 741 1,065

All Other — — — — — — — — —

Affiliate C&E $ 768 $ 2,598 $ 3,366 $ 367 $ 2,800 $ 3,167 $ 324 $ 3,658 $ 3,982

Affiliate C&E for 2022 was $3.4 billion, 6 percent higher than 2021.

The company monitors market conditions and can adjust future capital outlays should conditions change.

Noncontrolling Interests The company had noncontrolling interests of $960 million at December 31, 2022 and $873 million at December 31, 2021.

Distributions to noncontrolling interests net of contributions totaled $114 million and $36 million in 2022 and 2021, respectively.

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Indemnifications Information related to indemnifications is included in Note 24 Other Contingencies and Commitments under the heading “Indemnifications.”

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Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

Financial Ratios and Metrics

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Interest Coverage Ratio 79.8 29.0 (8.9)

Free Cash Flow The cash provided by operating activities less cash capital expenditures, which represents the cash available to creditors and investors after investing in the business.

Free Cash Flow The cash provided by operating activities less capital expenditures, which represents the cash available to creditors and investors after investing in the business.

Year ended December 31

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Debt Ratio 12.8 % 18.4 % 25.2 %

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

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

Net Debt Ratio Total debt less cash and cash equivalents and marketable securities as a percentage of total debt less cash and cash equivalents and marketable securities, plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage, net of its cash balances.

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The actual impact of future market changes could differ materially due to factors discussed elsewhere in this report, including those set forth under the heading “Risk Factors” in Part I, Item 1A.

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

Derivative Commodity Instruments Chevron is exposed to market risks related to the price volatility of crude oil, refined products, natural gas, natural gas liquids, liquefied natural gas and refinery feedstocks.

The company uses derivative commodity instruments to manage these exposures on a portion of its activity, including firm commitments and anticipated transactions for the purchase, sale and storage of crude oil, refined products, natural gas, natural gas liquids, liquefied natural gas and feedstock for company refineries.

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

Derivative Commodity Instruments Chevron is exposed to market risks related to the price volatility of crude oil, refined products, natural gas liquids, natural gas, liquefied natural gas and refinery feedstocks.

The company uses derivative commodity instruments to manage these exposures on a portion of its activity, including firm commitments and anticipated transactions for the purchase, sale and storage of crude oil, refined products, natural gas liquids, natural gas, liquefied natural gas and feedstock for company refineries.

The company also uses derivative commodity instruments for limited trading purposes.

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Balance at December 31 $ 868 $ 960 $ 1,139

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

The company records asset retirement obligations when there is a legal obligation associated with the retirement of long-lived assets and the liability can be reasonably estimated.

These asset retirement obligations include costs related to environmental issues.

These asset retirement obligations include costs related to

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

environmental issues.

The liability balance of approximately $12.7 billion for asset retirement obligations at year-end 2022 is related primarily to upstream properties.

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Environmental Matters

The company is subject to various international, federal, state and local environmental, health and safety laws, regulations and market-based programs.

The company is subject to various international and U.S.

federal, state and local environmental, health and safety laws, regulations and market-based programs.

These laws, regulations and programs continue to evolve and are expected to increase in both number and complexity over time and govern not only the manner in which the company conducts its operations, but also the products it sells.

For example, international agreements and national, regional, and state legislation and regulatory measures that aim to limit or reduce greenhouse gas (GHG) emissions are currently in various stages of implementation.

Consideration of GHG issues and the responses to those issues through international agreements and national, regional or state legislation or regulations are integrated into the company’s strategy and planning, capital investment reviews and risk management tools and processes, where applicable.

Consideration of environmental issues and the responses to those issues through international agreements and national, regional or state legislation or regulations are integrated into the company’s strategy and planning, capital investment reviews and risk management tools and processes, where applicable.

They are also factored into the company’s long-range supply, demand and energy price forecasts.

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Refer to “Risk Factors” in Part I, Item 1A, on pages 20 through 26 for a discussion of some of the inherent risks of increasingly restrictive environmental and other regulation that could materially impact the company’s results of operations or financial condition.

Refer to Business Environment and Outlook on pages 32 and 33 for a discussion of legislative and regulatory efforts to address climate change.

Most of the costs of complying with existing laws and regulations pertaining to company operations and products are embedded in the normal costs of doing business.

prevent, control, reduce or eliminate releases of hazardous materials or other pollutants into the environment;

However, it is not possible to predict with certainty the amount of additional investments in new or existing technology or facilities or the amounts of increased operating costs to be incurred in the future to prevent, control, reduce or eliminate releases of hazardous materials or other pollutants into the environment;

remediate and restore areas damaged by prior releases of hazardous materials;

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Using definitions and guidelines established by the American Petroleum Institute, Chevron estimated its worldwide environmental spending in 2022 at approximately $2.0 billion for its consolidated companies.

Included in these expenditures were approximately $0.3 billion of environmental capital expenditures and $1.6 billion of costs associated

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

with the prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites, and the decommissioning and restoration of sites.

Included in these expenditures were approximately $0.2 billion of environmental capital expenditures and $1.8 billion of costs associated with the prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites, and the decommissioning and restoration of sites.

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

For 2023, total worldwide environmental capital expenditures are estimated at $0.2 billion.

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the impact of the estimates and assumptions on the company’s financial condition or operating performance is material.

The development and selection of accounting estimates and assumptions, including those deemed “critical,” and the associated disclosures in this discussion have been discussed by management with the Audit Committee of the Board of Directors.

The development and selection of accounting estimates and assumptions, including those deemed “critical,” and the associated disclosures in this discussion have been discussed with the Audit Committee of the Board of Directors.

The areas of accounting and the associated “critical” estimates and assumptions made by the company are as follows:

Oil and Gas Reserves Crude oil and natural gas reserves are estimates of future production that impact certain asset and expense accounts included in the Consolidated Financial Statements.

Oil and Gas Reserves Crude oil, natural gas liquids and natural gas reserves are estimates of future production that impact certain asset and expense accounts included in the Consolidated Financial Statements.

Proved reserves are the estimated quantities of oil and gas that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in the future under existing economic conditions, operating methods and government regulations.

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Variables impacting Chevron’s estimated volumes of crude oil and natural gas reserves include field performance, available technology, commodity prices, and development, production and carbon costs.

The estimates of crude oil and natural gas reserves are important to the timing of expense recognition for costs incurred and to the valuation of certain oil and gas producing assets.

The estimates of crude oil, natural gas liquids and natural gas reserves are important to the timing of expense recognition for costs incurred and to the valuation of certain oil and gas producing assets.

Impacts of oil and gas reserves on Chevron’s Consolidated Financial Statements, using the successful efforts method of accounting, include the following:

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For a further discussion of estimates and assumptions used in impairment assessments, see Impairment of Properties, Plant and Equipment and Investments in Affiliates below.

Refer to Table V , “Reserve Quantity Information,”, for the changes in proved reserve estimates for the three years ended December 31, 2021, and to Table VII , “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” for estimates of proved reserve values for each of the three years ended December 31, 2021.

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

Refer to Table V , “Reserve Quantity Information,” for the changes in proved reserve estimates for each of the three years ended December 31, 2020, 2021 and 2022, and to Table VII , “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” for estimates of proved reserve values for each of the three years ended December 31, 2020, 2021 and 2022.

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

This Oil and Gas Reserves commentary should be read in conjunction with the Properties, Plant and Equipment section of Note 1 Summary of Significant Accounting Policies , which includes a description of the “successful efforts” method of accounting for oil and gas exploration and production activities.

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If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of the carrying value of the asset over its estimated fair value.

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters, such as future commodity prices, operating expenses, carbon costs, production profiles, the pace of the energy transition, and the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas, commodity chemicals and refined products.

However, the impairment reviews and calculations are based on assumptions that are generally consistent with the company’s business plans and long-term investment decisions.

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The company performs impairment assessments when triggering events arise to determine whether any write-down in the carrying value of an asset or asset group is required.

For example, when significant downward revisions to crude oil and natural gas reserves are made for any single field or concession, an impairment review is performed to determine if the carrying value of the asset remains recoverable.

Similarly, a significant downward revision in the company’s crude oil or natural gas price outlook would trigger impairment reviews for impacted upstream assets.

For example, when significant downward revisions to crude oil, natural gas liquids and natural gas reserves are made for any single field or concession, an impairment review is performed to determine if the carrying value of the asset remains recoverable.

Similarly, a significant downward revision in the company’s crude oil, natural gas liquids or natural gas price outlook would trigger impairment reviews for impacted upstream assets.

In addition, impairments could occur due to changes in national, state or local environmental regulations or laws, including those designed to stop or impede the development or production of oil and gas.

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and the related underlying assumptions.

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

The determination of pension plan expense and obligations is based on a number of actuarial assumptions.

Two critical assumptions are the expected long-term rate of return on plan assets and the discount rate applied to pension plan

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

Two critical assumptions are the expected long-term rate of return on plan assets and the discount rate applied to pension plan obligations.

Critical assumptions in determining expense and obligations for OPEB plans, which provide for certain health care and life insurance benefits for qualifying retired employees and which are not funded, are the discount rate and the assumed health care cost-trend rates.

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For the 10 years ended December 31, 2022, actual asset returns averaged 5.7 percent for this plan.

Additionally, with the exception of two years within this 10-year period, actual asset returns for this plan equaled or exceeded 6.5 percent during each year.

Total pension expense for 2021 was $1.2 billion.

Additionally, with the exception of three years within this 10-year period, actual asset returns for this plan equaled or exceeded 6.6 percent during each year.

Total pension expense for 2022 was $763 million.

An increase in the expected long-term return on plan assets or the discount rate would reduce pension plan expense, and vice versa.

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As an indication of the sensitivity of pension liabilities to the discount rate assumption, a 0.25 percent increase in the discount rate applied to the company’s primary U.S.

pension plan, which accounted for about 60 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $425 million, and would have decreased the plan’s underfunded status from approximately $1.2 billion to $800 million.

pension plan, which accounted for about 63 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $239 million, and would have decreased the plan’s underfunded status from approximately $475 million to $236 million.

For the company’s OPEB plans, expense for 2022 was $89 million, and the total liability, all unfunded at the end of 2022, was $1.9 billion.

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An exception to this handling is for income tax matters, for which benefits are recognized only if management determines the tax position is more likely than not (i.e., likelihood greater than 50 percent) to be allowed by the tax jurisdiction.

For additional discussion of income tax uncertainties, refer to Note 24 Other Contingencies and Commitments under the heading Income Taxes .

Refer also to the business segment discussions elsewhere in this section for the effect on earnings from losses associated with certain litigation, environmental remediation and tax matters for the three years ended December 31, 2021.

An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in recording these liabilities is not practicable because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss.

For further information, refer to “Changes in management’s estimates and assumptions may have a material

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

impact on the company’s consolidated financial statements and financial or operational performance in any given period” in “Risk Factors” in Part I, Item 1A, on pages 24 and 25.

For additional discussion of income tax uncertainties, refer to Note 24 Other Contingencies and Commitments under the heading “Income Taxes.” Refer also to the business segment discussions elsewhere in this section for the effect on earnings from losses associated with certain litigation, environmental remediation and tax matters for the three years ended December 31, 2022.

Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents

assumptions and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss.

For further information, refer to “Changes in management’s estimates and assumptions may have a material impact on the company’s consolidated financial statements and financial or operational performance in any given period” in “Risk Factors” in Part I, Item 1A, on pages 25 and 26.

New Accounting Standards

Refer to Note 4 New Accounting Standards for information regarding new accounting standards.

Financial Table of Contents

Quarterly Results

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Dividends per share $ 1.42 $ 1.42 $ 1.42 $ 1.42 $ 1.34 $ 1.34 $ 1.34 $ 1.29

Financial Table of Contents

Management’s Responsibility for Financial Statements

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February 23, 2023

Financial Table of Contents

Report of Independent Registered Public Accounting Firm

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and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Financial Table of Contents

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

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As part of the internal control process related to reserves estimation, the Company maintains a Reserves Advisory Committee (RAC) (the Company’s earth scientists, engineers and RAC are collectively referred to as “management’s specialists”).

The principal considerations for our determination that performing procedures relating to the impact of proved crude oil and natural gas reserves on upstream property, plant, and equipment, 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 crude oil and natural gas reserve volumes, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained related to the data, methods and assumptions used by management and its specialists in developing the estimates of proved crude oil and natural gas reserve volumes.

The principal considerations for our determination that performing procedures relating to the impact of proved crude oil, natural gas liquids and natural gas reserves on upstream property, plant, and equipment, 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 crude oil, natural gas liquids and natural gas reserve volumes, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained related to the data, methods and assumptions used by management and its specialists in developing the estimates of proved crude oil and natural gas reserve volumes.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements.

These procedures included testing the effectiveness of controls relating to management’s estimates of proved crude oil and natural gas reserve volumes.

The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved crude oil and natural gas reserve volumes.

These procedures included testing the effectiveness of controls relating to management’s estimates of proved crude oil, natural gas liquids and natural gas reserve volumes.

The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved crude oil, natural gas liquids 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.

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We have served as the Company’s auditor since 1935.

Consolidated Statement of Income

Consolidated Statement of Income Financial Table of Contents

Millions of dollars, except per-share amounts

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See accompanying Notes to the Consolidated Financial Statements.

Consolidated Statement of Comprehensive Income

Consolidated Statement of Comprehensive Income Financial Table of Contents

Millions of dollars

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Net gain (loss) arising during period ( 1 ) ( 1 ) ( 2 )

Net derivatives loss on hedge transactions ( 6 ) — ( 1 )

Net derivatives gain (loss) on hedge transactions 65 ( 6 ) —

Reclassification to net income ( 80 ) 6 —

Income taxes on derivatives transactions 3 — —

Total ( 12 ) — —

Defined benefit plans

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Other Comprehensive Gain (Loss), Net of Tax 1,091 1,723 ( 622 )

Comprehensive Income 17,412 ( 6,183 ) 1,399

Comprehensive Income (Loss) 36,699 17,412 ( 6,183 )

Comprehensive loss (income) attributable to noncontrolling interests ( 143 ) ( 64 ) 18

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See accompanying Notes to the Consolidated Financial Statements.

Consolidated Balance Sheet

Consolidated Balance Sheet Financial Table of Contents

Millions of dollars, except per-share amounts

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20,456 18,419

Crude oil and petroleum products 4,248 3,576

Crude oil and products 5,866 4,248

Chemicals 515 565

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See accompanying Notes to the Consolidated Financial Statements.

Consolidated Statement of Cash Flows

Consolidated Statement of Cash Flows Financial Table of Contents

Millions of dollars

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Investing Activities

Cash acquired from Noble Energy, Inc.

Acquisition of businesses, net of cash received ( 2,862 ) — 373

Capital expenditures ( 11,974 ) ( 8,056 ) ( 8,922 )

Proceeds and deposits related to asset sales and returns of investment 2,635 1,791 2,968

Net maturities of (investments in) time deposits — — 950

Net sales (purchases) of marketable securities 117 ( 1 ) 35

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See accompanying Notes to the Consolidated Financial Statements.

Consolidated Statement of Equity

Consolidated Statement of Equity Financial Table of Contents

Amounts in millions of dollars

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Treasury stock transactions 84 — — — 84 — 84

Noble acquisition 2

( 520 ) — — 4,629 4,109 779 4,888

Net income (loss) — ( 5,543 ) — — ( 5,543 ) ( 18 ) ( 5,561 )

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Treasury stock transactions 315 — — — 315 — 315

Noble Acquisition 2

( 520 ) — — 4,629 4,109 779 4,888

NBLX acquisition 138 ( 148 ) — 377 367 ( 321 ) 46

Net income (loss) — 15,625 — — 15,625 64 15,689

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Treasury stock transactions 63 — — — 63 — 63

NBLX Acquisition 138 ( 148 ) — 377 367 ( 321 ) 46

Net income (loss) — 35,465 — — 35,465 143 35,608

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Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

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Although the company uses its best estimates and judgments, actual results could differ from these estimates as circumstances change and additional information becomes known.

Prior years’ data have been reclassified in certain cases to conform to the 2022 presentation basis.

Subsidiary and Affiliated Companies The Consolidated Financial Statements include the accounts of controlled subsidiary companies more than 50 percent-owned and any variable interest entities in which the company is the primary beneficiary.

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Where Chevron is a party to master netting arrangements, fair value receivable and payable amounts recognized for derivative instruments executed with the same counterparty are generally offset on the balance sheet.

Inventories Crude oil, petroleum products and chemicals inventories are generally stated at cost, using a last-in, first-out method.

Inventories Crude oil, products and chemicals inventories are generally stated at cost, using a last-in, first-out method.

In the aggregate, these costs are below market.

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Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

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Notes to the Consolidated Financial Statements

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For awards granted under the company’s LTIP beginning in 2017, stock options and stock appreciation rights have graded vesting by which one third of each award vests annually on each January 31 on or after the first anniversary of the grant date.

Special restricted stock unit awards have cliff vesting by which the total award will vest on January 31 on or after the third anniversary of the grant date.

Standard restricted stock unit awards have cliff vesting by which the total award will vest on January 31 on or after the fifth anniversary of the grant date, subject to adjustment upon termination pursuant to the satisfaction of certain criteria.

The company amortizes these awards on a straight-line basis.

Commencing for grants issued in January 2023

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

and after, standard restricted stock units vest ratably on an annual basis over a three-year period.

The company amortizes these awards on a straight-line basis.

Changes in Accumulated Other Comprehensive Losses

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1 All amounts are net of tax.

2 Refer to Note 10 Financial and Derivative Instruments for cash flow hedging.

2 Refer to Note 23 Employee Benefit Plans , for reclassified components, including amortization of actuarial gains or losses, amortization of prior service costs and settlement losses, totaling $ 580 that are included in employee benefit costs for the year ended December 31, 2022.

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All other reclassified amounts were insignificant.

3 Refer to Note 10 Financial and Derivative Instruments for cash flow hedging.

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

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Proceeds and deposits related to asset sales and returns of investment $ 2,635 $ 1,791 $ 2,968

Net maturities (investments) of time deposits consisted of the following gross amounts:

Investments in time deposits $ — $ — $ —

Maturities of time deposits — — 950

Net maturities of (investments in) time deposits $ — $ — $ 950

Net sales (purchases) of marketable securities consisted of the following gross amounts:

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The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash.

“Distributions more (less) than income from equity affiliates,” “Depreciation, depletion and amortization,” “Deferred income tax provision,” and “Dry hole expense,” collectively include approximately $ 4.8 billion in non-cash reductions to properties, plant and equipment in 2020 relating to impairments and other non-cash charges.

“Depreciation, depletion and amortization,” “Deferred income tax provision,” and “Dry hole expense,” collectively include approximately $ 1.1 billion in non-cash reductions to properties, plant and equipment in 2022 relating to impairments and other non-cash charges.

The company did not have any material impairments in 2021.

Refer also to Note 25 Asset Retirement Obligations for a discussion of revisions to the company’s AROs that also did not involve cash receipts or payments for the three years ending December 31, 2022.

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

The major components of “Capital expenditures” and the reconciliation of this amount to the reported capital and exploratory expenditures, including equity affiliates, are presented in the following table.

The components of “Capital expenditures” are presented in the following table:

Year ended December 31

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Capital expenditures $ 11,974 $ 8,056 $ 8,922

Expensed exploration expenditures 431 500 598

Assets acquired through finance leases and other obligations 64 53 181

Payments for other assets and liabilities, net

Capital and exploratory expenditures, excluding equity affiliates

8,553 9,517 14,882

Company’s share of expenditures by equity affiliates

3,167 3,982 6,112

Capital and exploratory expenditures, including equity affiliates

$ 11,720 $ 13,499 $ 20,994

* Excludes non-cash movements of $ 334 in 2022, $ 316 in 2021 and $ 816 in 2020.

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Operating lease arrangements mainly involve land, bareboat charters, terminals, drill ships, drilling rigs, time chartered vessels, office buildings and warehouses, and exploration and production equipment.

Finance leases primarily include facilities, vessels, office buildings, and production equipment.

Finance leases primarily include facilities, vessels and office buildings.

Details of the right-of-use assets and lease liabilities for operating and finance leases, including the balance sheet presentation, are as follows:

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

At December 31, 2022 At December 31, 2021

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* Includes non-cash additions of $ 1,807 and $ 3 in 2022, and $ 1,063 and $ 60 in 2021 for right-of-use assets obtained in exchange for new and modified lease liabilities for operating and finance leases, respectively.

2020 includes $ 566 in operating lease right-of-use assets and $ 566 lease liabilities associated with the Puma acquisition.

2020 also includes $ 124 in operating lease right-of-use assets and $ 148 lease liabilities, and $ 112 in finance lease right-of-use assets and $ 309 lease liabilities associated with the Noble acquisition.

Total lease costs consist of both amounts recognized in the Consolidated Statement of Income during the period and amounts capitalized as part of the cost of another asset.

Total lease costs incurred for operating and finance leases were as follows:

Notes to the Consolidated Financial Statements

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Year-ended December 31

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Additionally, the company has $ 1,570 in future undiscounted cash flows for operating leases not yet commenced.

These leases are primarily for a drill ship and drilling rigs.

These leases are primarily for drill ships and drilling rigs.

The company also has $ 327 in future undiscounted cash flows for a finance lease not yet commenced for production equipment.

For those leasing arrangements where the underlying asset is not yet constructed, the lessor is primarily involved in the design and construction of the asset.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Summarized Financial Data – Chevron U.S.A.

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CUSA and its subsidiaries manage and operate most of Chevron’s U.S.

Assets include those related to the exploration and production of crude oil, natural gas and natural gas liquids and those associated with the refining, marketing, supply and distribution of products derived from petroleum, excluding most of the regulated pipeline operations of Chevron.

Assets include those related to the exploration and production of crude oil, natural gas liquids and natural gas and those associated with the refining, marketing, supply and distribution of products derived from petroleum, excluding most of the regulated pipeline operations of Chevron.

CUSA also holds the company’s investment in the Chevron Phillips Chemical Company LLC joint venture, which is accounted for using the equity method.

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13,315 6,904 ( 2,676 )

Notes to the Consolidated Financial Statements

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At December 31

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Net income attributable to CPChem 1,662 3,684 1,260

Notes to the Consolidated Financial Statements

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At December 31

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Fair Value Measurements

The tables below show the fair value hierarchy for assets and liabilities measured at fair value on a recurring and nonrecurring basis at December 31, 2021 and December 31, 2020.

The tables below show the fair value hierarchy for assets and liabilities measured at fair value on a recurring and nonrecurring basis at December 31, 2022 and 2021.

Marketable Securities The company calculates fair value for its marketable securities based on quoted market prices for identical assets.

The fair values reflect the cash that would have been received if the instruments were sold at December 31, 2022.

Derivatives The company records most of its derivative instruments – other than any commodity derivative contracts that are accounted for as normal purchase and normal sale – on the Consolidated Balance Sheet at fair value, with the offsetting amount to the Consolidated Statement of Income.

Notes to the Consolidated Financial Statements

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amount to the Consolidated Statement of Income.

The company designates certain derivative instruments as cash flow hedges that, if applicable, are reflected in the table below.

Derivatives classified as Level 1 include futures, swaps and options contracts traded in active markets such as the New York Mercantile Exchange.

Derivatives classified as Level 2 include swaps, options and forward contracts principally with financial institutions and other oil and gas companies, the fair values of which are obtained from third-party broker quotes, industry pricing services and exchanges.

Derivatives classified as Level 1 include futures, swaps and options contracts valued using quoted prices from active markets such as the New York Mercantile Exchange.

Derivatives classified as Level 2 include swaps, options and forward contracts, the fair values of which are obtained from third-party broker quotes, industry pricing services and exchanges.

The company obtains multiple sources of pricing information for the Level 2 instruments.

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The company does not materially adjust this information.

Properties, Plant and Equipment The company did not have any individually material impairments in 2021.

The company reported impairments for certain upstream properties in 2020 primarily due to downward revisions to its oil and gas price outlook.

Investments and Advances In 2021, the company did not have any material impairments of investments and advances measured at fair value on a nonrecurring basis.

In 2020, the company fully impaired its investments in Petropiar and Petroboscan in Venezuela.

The impact of these impairments is included in “Income (loss) from equity affiliates” on the Consolidated Statement of Income.

Properties, Plant and Equipment The company did not have any individually material impairments of long-lived assets measured at fair value on a nonrecurring basis to report in 2022 or 2021.

Investments and Advances The company did not have any material impairments of investments and advances measured at fair value on a nonrecurring basis to report in 2022 or 2021.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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Derivatives - not designated 43 33 10 — 72 24 48 —

Derivatives - designated 15 15 — — — — — —

Total liabilities at fair value $ 58 $ 48 $ 10 $ — $ 72 $ 24 $ 48 $ —

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Total nonrecurring assets at fair value $ 87 $ 2 $ — $ 85 $ 959 $ 140 $ — $ — $ 140 $ 446

Notes to the Consolidated Financial Statements

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At year-end 2022, the company had assets measured at fair value Level 3 using unobservable inputs of $ 85 .

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The fair value of corporate bonds is $ 14,571 and classified as Level 1.

The fair value of other long-term debt is $ 835 and classified as Level 2.

The carrying values of short-term financial assets and liabilities on the Consolidated Balance Sheet approximate their fair values.

The fair value of other long-term debt classified as Level 2 is $ 388 .

The carrying values of other short-term financial assets and liabilities on the Consolidated Balance Sheet approximate their fair values.

Fair value remeasurements of other financial instruments at December 31, 2022 and 2021, were not material.

Notes to the Consolidated Financial Statements

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Financial and Derivative Instruments

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Total liabilities at fair value $ 58 $ 72

Notes to the Consolidated Financial Statements

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Consolidated Statement of Income:

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$ ( 867 ) $ ( 795 ) $ 40

All designated cash flow hedges during the year were settled by December 31, 2021.

The impact on sales and other operating revenues from designated hedges in 2021 was immaterial.

The table below represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated Balance Sheet at December 31, 2021 and December 31, 2020.

The amount reclassified from “Accumulated other comprehensive losses” (AOCL) to “Sales and other operating revenues” from designated hedges was $ 80 in 2022, compared with an immaterial amount in the prior year.

At December 31, 2022, before-tax deferred losses in AOCL related to outstanding crude oil price hedging contracts were $ 15 , all of which is expected to be reclassified into earnings during the next 12 months as the hedged crude oil sales are recognized in earnings.

The table below represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated Balance Sheet at December 31, 2022 and 2021.

Consolidated Balance Sheet:

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Derivative Assets - not designated $ 2,591 $ 2,407 $ 184 $ 5 $ 179

Derivative Assets - designated $ 8 $ 8 $ — $ — $ —

Derivative Liabilities - not designated $ 2,450 $ 2,407 $ 43 $ — $ 43

Derivative Liabilities - designated $ 23 $ 8 $ 15 $ — $ 15

At December 31, 2021

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Derivative Liabilities - not designated $ 1,443 $ 1,371 $ 72 $ — $ 72

Notes to the Consolidated Financial Statements

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Derivative assets and liabilities are classified on the Consolidated Balance Sheet as “Accounts and notes receivable”, “Long-term receivables”, “Accounts payable”, and “Deferred credits and other noncurrent obligations”.

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Assets Held for Sale

At December 31, 2021, the company classified $ 768 of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet.

At December 31, 2022, the company classifie d $ 436 of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet.

These assets are associated with upstream operations that are anticipated to be sold in the next 12 months.

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In addition, 597,152 shares remain available for issuance from the 1,600,000 shares of the company’s common stock that were reserved for awards under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan.

Notes to the Consolidated Financial Statements

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Earnings Per Share

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1 million shares of employee-based awards were not included in the 2020 diluted EPS calculation as the result would be anti-dilutive.

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Operating Segments and Geographic Data

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Non-billable costs remain at the corporate level in “All Other.” Earnings by major operating area are presented in the following table:

Notes to the Consolidated Financial Statements

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Year ended December 31

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$ 35,465 $ 15,625 $ ( 5,543 )

Notes to the Consolidated Financial Statements

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Segment Assets Segment assets do not include intercompany investments or receivables.

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International 21,193 18,848

Goodwill 352 —

Total Downstream 53,221 45,224

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United States

506 744 1,064

International

508 759 1,084

Intersegment Elimination — United States

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Total International $ 35,383 $ 32,156 $ 7,610 $ 3,768 $ ( 1,181 )

* Upstream Other line includes amounts previously reported as Noble Midstream equity affiliates.

Descriptions of major affiliates and non-equity investments, including significant differences between the company’s carrying value of its investments and its underlying equity in the net assets of the affiliates, are as follows:

Descriptions of major equity affiliates and non-equity investments, including significant differences between the company’s carrying value of its investments and its underlying equity in the net assets of the affiliates, are as follows:

Tengizchevroil Chevron has a 50 percent equity ownership interest in Tengizchevroil (TCO), which operates the Tengiz and Korolev crude oil fields in Kazakhstan.

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This difference results from Chevron acquiring a portion of its interest in TCO at a value greater than the underlying book value for that portion of TCO’s net assets.

Included in the investment is a loan to TCO to fund the development of the FGP/WPMP with a balance of $ 4,500 .

Included in the investment is a loan to TCO to fund the development of the FGP/WPMP with a principal balance of $ 4,500 .

Petropiar Chevron has a 30 percent interest in Petropiar, a joint stock company which operates the heavy oil Huyapari Field and upgrading project in Venezuela’s Orinoco Belt.

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In 2020, the company fully impaired its investments in the Petroboscan affiliate and, effective July 1, 2020, began accounting for this venture as a non-equity method investment.

The company also has an outstanding long-term loan to Petroboscan of $ 560 , which has been fully provisioned for at year-end 2021.

The company also has an outstanding long-term loan to Petroboscan of $ 560 , which remains fully provisioned for at year-end 2022.

Caspian Pipeline Consortium Chevron has a 15 percent interest in the Caspian Pipeline Consortium, which provides the critical export route for crude oil from both TCO and Karachaganak.

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Chevron Phillips Chemical Company LLC Chevron owns 50 percent of Chevron Phillips Chemical Company LLC.

The other half is owned by Phillips 66.

GS Caltex Corporation Chevron owns 50 percent of GS Caltex Corporation, a joint venture with GS Energy in South Korea.

The joint venture imports, refines and markets petroleum products, petrochemicals and lubricants.

Included in the investment balance is a loan with a principal balance of $ 59 to fund a portion of the Golden Triangle Polymers Project in Orange, Texas, in which Chevron Phillips Chemical Company LLC owns 51 percent.

Notes to the Consolidated Financial Statements

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GS Caltex Corporation Chevron owns 50 percent of GS Caltex Corporation, a joint venture with GS Energy in South Korea.

The joint venture imports, produces and markets petroleum products, petrochemicals and lubricants.

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $ 16,286 , $ 10,796 and $ 6,038 with affiliated companies for 2022, 2021 and 2020, respectively.

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Income before income tax expense*

23,811 15,175 5,682 10,876 6,984 2,550

Net income attributable to affiliates 19,077 12,598 4,704 8,595 5,670 2,034

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Total affiliates’ net equity $ 88,927 $ 80,612 $ 76,805 $ 44,411 $ 40,153 $ 39,639

Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was a minority member of an oil production consortium with Ecuadorian state-owned Petroecuador from 1967 until 1992.

After termination of the consortium and a third-party environmental audit, Ecuador and the consortium parties entered into a settlement agreement specifying Texpet’s remediation obligations.

Following Texpet’s completion of a three -year remediation program, Ecuador certified the remediation as proper and released Texpet and its affiliates from environmental liability.

In May 2003, plaintiffs alleging environmental harm from the consortium’s activities sued Chevron in the Superior Court in Lago Agrio, Ecuador.

In February 2011, that court entered a judgment against Chevron for approximately $ 9,500 plus additional punitive damages.

An appellate panel affirmed, and Ecuador’s National Court of Justice ratified the judgment but nullified the punitive damages, resulting in a judgment of approximately $ 9,500 .

* Chevron’s net income attributable to affiliates is recorded in the company’s before-tax consolidated earnings in accordance with U.S.

Generally Accepted Accounting Principles.

The total income tax expense recorded by the company’s equity affiliates in 2022 was $ 4,734 , with Chevron’s share being $ 2,281 .

In 2003, Chevron was sued in Ecuador for environmental harm allegedly caused by an oil consortium formerly operated by a Texaco subsidiary.

The subsidiary previously had been released from environmental claims by Ecuador after it completed a three-year remediation program, which Ecuador certified.

Nonetheless, in February 2011, the Ecuadorian trial court entered judgment against Chevron for approximately $ 9.5 billion, plus punitive damages.

An appellate panel affirmed, and Ecuador’s National Court of Justice ratified the judgment but nullified the punitive damages.

Ecuador’s highest Constitutional Court rejected Chevron’s final appeal in July 2018.

In February 2011, Chevron sued the Lago Agrio plaintiffs and several of their lawyers and supporters in the U.S.

In 2011, Chevron sued the Ecuadorian plaintiffs and several of their lawyers and cohorts in the U.S.

District Court for the Southern District of New York (SDNY) for violations of the Racketeer Influenced and Corrupt Organizations (RICO) Act and state law.

The SDNY court ruled that the Ecuadorian judgment had been procured through fraud, bribery, and corruption, and prohibited the RICO defendants from seeking to enforce the Ecuadorian judgment in the United States or profiting from their illegal acts.

The Court of Appeals for the Second Circuit affirmed, and the U.S.

Supreme Court denied certiorari in June 2017, rendering final the U.S.

judgment in favor of Chevron.

The Lago Agrio plaintiffs sought to have the Ecuadorian judgment recognized and enforced in Canada, Brazil, and Argentina.

All of those recognition and enforcement actions were dismissed and resolved in Chevron’s favor.

Chevron and Texpet filed an arbitration claim against Ecuador in September 2009 before an arbitral tribunal administered by the Permanent Court of Arbitration in The Hague, under the United States-Ecuador Bilateral Investment Treaty.

In August 2018, the Tribunal issued an award holding that the Ecuadorian judgment was based on environmental claims that Ecuador had settled and released, and that it was procured through fraud, bribery, and corruption.

According to the Tribunal, the Ecuadorian judgment “violates international public policy” and “should not be recognized or enforced by the courts of other States.” The Tribunal ordered Ecuador to remove the status of enforceability from the Ecuadorian judgment and to compensate Chevron for any injuries resulting from the judgment.

The third and final phase of the arbitration, to determine the amount of compensation Ecuador owes to Chevron, is ongoing.

In September 2020, the District Court of The Hague denied Ecuador’s request to set aside the Tribunal’s award, stating that it now is “common ground” between Ecuador and Chevron that the Ecuadorian judgment is fraudulent.

In December 2020, Ecuador appealed the District Court’s decision to The Hague Court of Appeals.

The SDNY ruled that the Ecuadorian judgment had been procured through fraud, bribery, and corruption, and prohibited the defendants from seeking to enforce the judgment in the United States or profiting from their illegal acts.

The Second Circuit affirmed, and the U.S.

Supreme Court denied certiorari in 2017.

The Ecuadorian plaintiffs sought to have the Ecuadorian judgment recognized and enforced in Canada, Brazil, and Argentina, but all of those actions were dismissed in Chevron’s favor.

In 2009, Chevron filed an arbitration claim against Ecuador before an arbitral tribunal administered by the Permanent Court of Arbitration in The Hague, under the United States-Ecuador Bilateral Investment Treaty.

In 2018, the Tribunal ruled that the Ecuadorian judgment was procured through fraud, bribery, and corruption, and was based on environmental claims that Ecuador had already settled and released.

According to the Tribunal, the Ecuadorian judgment “violates international public policy” and “should not be recognized or enforced by the courts of other States.” The Tribunal ordered Ecuador to remove the judgment’s status of enforceability and to compensate Chevron for its injuries.

The arbitration’s final phases, to determine the amount of compensation owed to Chevron and to allocate the arbitration’s costs, remain pending.

In 2020, the District Court of The Hague denied Ecuador’s request to set aside the Tribunal’s award.

Based on Ecuador’s admissions during the litigation, the Court stated that it now is “common ground” between Ecuador and Chevron that the Ecuadorian judgment is fraudulent.

In June 2022, The Hague Court of Appeals dismissed Ecuador’s appeal.

Notes to the Consolidated Financial Statements

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separate proceeding, Ecuador also admitted that the Ecuadorian judgment is fraudulent in a public filing with the Office of the United States Trade Representative in July 2020.

2022, Ecuador appealed to the Dutch Supreme Court.

In a separate proceeding before the Office of the United States Trade Representative, Ecuador also admitted in July 2020 that the Ecuadorian judgment is fraudulent.

Management continues to believe that the Ecuadorian judgment is illegitimate and unenforceable and will vigorously defend against any further attempts to have it recognized or enforced.

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Chevron entities are or were among the codefendants in 23 separate lawsuits brought by 17 U.S.

cities and counties, two U.S.

states, the District of Columbia and a trade group.

cities and counties, three U.S.

states, the District of Columbia, a group of municipalities in Puerto Rico and a trade group.

One of the city lawsuits was dismissed on the merits, and one of the county lawsuits was voluntarily dismissed by the plaintiff.

The lawsuits assert various causes of action, including public nuisance, private nuisance, failure to warn, design defect, product defect, trespass, negligence, impairment of public trust, and violations of consumer protection statutes, based upon the company’s production of oil and gas products and alleged misrepresentations or omissions relating to climate change risks associated with those products.

The lawsuits assert various causes of action, including public nuisance, private nuisance, failure to warn, fraud, conspiracy to commit fraud, design defect, product defect, trespass, negligence, impairment of public trust, violations of consumer protection statutes, violations of a federal antitrust statute, and violations of the RICO Act, based upon, among other things, the company’s production of oil and gas products and alleged misrepresentations or omissions relating to climate change risks associated with those products.

The unprecedented legal theories set forth in these proceedings entail the possibility of damages liability (both compensatory and punitive), injunctive and other forms of equitable relief, including without limitation abatement and disgorgement of profits, civil penalties and liability for fees and costs of suits, that, while we believe remote, could have a material adverse effect on the company’s results of operations and financial condition.

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Notes to the Consolidated Financial Statements

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statutory rate of 21%) 10,432 4,544 ( 1,565 )

Effect of U.S.

tax reform — — 3

Equity affiliate accounting effect ( 1,678 ) ( 890 ) 211

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Effective income tax rate 3

28.3 % 27.5 % 25.4 %

1 Includes one-time tax costs (benefits) associated with changes in uncertain tax positions.

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2021 - $( 624 );

The 2021 increase in income tax expense of $ 7,842 is a result of the year-over-year increase in total income before income tax expense, which is primarily due to higher upstream realizations, the absence of 2020 impairment and write-offs and higher downstream margins.

2020 - $ 0 ).

3 The company’s effective tax rate is reflective of equity income reported on an after-tax basis as part of the “Total Income (Loss) Before Income Tax Expense,” in accordance with U.S.

Generally Accepted Accounting Principles.

Chevron’s share of its equity affiliates’ total income tax expense in 2022 was $ 2,281 .

The 2022 increase in income tax expense of $ 8,116 is a result of the year-over-year increase in total income before income tax expense, which is primarily due to higher upstream realizations and downstream margins.

The company’s effective tax rate changed from 27.5 percent in 2021 to 28.3 percent in 2022.

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Total deferred taxes, net $ 12,626 $ 9,006

Deferred tax liabilities decreased by $ 946 from year-end 2020.

The decrease to Investments and other was driven by a consolidated subsidiary restructuring, partially offset with an increase to Properties, plant and equipment.

Deferred tax liabilities increased by $ 1,513 from year-end 2021, primarily driven by an increase to properties, plant and equipment.

Deferred tax assets decreased by $ 226 from year-end 2021.

This decrease was primarily related to decreases in tax loss carryforwards for various locations, and employee benefits, partially offset by the increase in foreign tax credits.

This decrease was primarily related to decreases in employee benefits and tax loss carryforwards for various locations, partially offset by the increase in foreign tax credits.

The overall valuation allowance relates to deferred tax assets for U.S.

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Notes to the Consolidated Financial Statements

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Total deferred income taxes, net $ 12,626 $ 9,006

Income taxes are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely.

Income taxes, including U.S.

state and foreign withholding taxes, are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely.

The indefinite reinvestment assertion continues to apply for the purpose of determining deferred tax liabilities for U.S.

state and foreign withholding tax purposes.

state and foreign withholding taxes are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely.

Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for possible future remittances totaled approximately $ 51,300 at December 31, 2022.

This amount represents earnings reinvested as part of the company’s ongoing international business.

It is not practicable to estimate the amount of state and foreign taxes that might be payable on the possible remittance of earnings that are intended to be reinvested indefinitely.

It is not practicable to estimate the amount of state and foreign withholding taxes that might be payable on the possible remittance of earnings that are intended to be reinvested indefinitely.

The company does not anticipate incurring significant additional taxes on remittances of earnings that are not indefinitely reinvested.

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Both the outcome of these tax matters and the timing of resolution and/or closure of the tax audits are highly uncertain.

However, it is reasonably possible that developments on tax matters in certain tax jurisdictions may result in significant increases or decreases in the company’s total unrecognized tax benefits within the next 12 months.

Given the number of years that still remain subject to examination and the number of matters being examined in the various tax jurisdictions, the company is unable to estimate the range of possible adjustments to the balance of unrecognized tax benefits.

Of the amount of unrecognized tax benefits the company has identified as of December 31, 2022, it is reasonably possible that developments on tax matters in certain tax jurisdictions may result in decreases of approximately 20 percent within the next 12 months.

On the Consolidated Statement of Income, the company reports interest and penalties related to liabilities for uncertain tax positions as “Income Tax Expense (Benefit).” As of December 31, 2022, accrued expense of $ 112 for anticipated interest

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On the Consolidated Statement of Income, the company reports interest and penalties related to liabilities for uncertain tax positions as “Income tax expense.” As of December 31, 2021, accrual benefit of $( 76 ) for anticipated interest and penalty was included on the Consolidated Balance Sheet, compared with accrual benefit of $( 95 ) as of year-end 2020.

and penalties was included on the Consolidated Balance Sheet, compared with accrued benefit of $( 76 ) as of year-end 2021.

Income tax expense (benefit) associated with interest and penalties was $ 152 , $ 19 and $( 124 ) in 2022, 2021 and 2020, respectively.

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Property and other miscellaneous taxes

3,378 2,248 1,785

Payroll taxes 248 302 235

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2 Net of dry hole expense related to prior years’ expenditures of $ 177 , $ 35 and $ 709 in 2022, 2021 and 2020, respectively.

3 Depreciation expense includes accretion expense of $ 616 , $ 560 and $ 628 in 2021, 2020 and 2019, respectively, and impairments of $ 414 , $ 2,792 and $ 10,797 in 2021, 2020 and 2019, respectively.

3 Depreciation expense includes accretion expense of $ 560 , $ 616 and $ 560 in 2022, 2021 and 2020, respectively, and impairments and write-offs of $ 950 , $ 414 and $ 2,792 in 2022, 2021 and 2020, respectively.

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Total short-term debt $ 1,964 $ 256

1 Weighted-average interest rate at December 31, 2020 was 0.15 %.

1 Inclusive of unamortized premiums of $ 5 at December 31, 2022 and $ 0 at December 31, 2021.

Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date.

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The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate.

Any borrowings under the facility would be unsecured indebtedness at interest rates based on the London Interbank Offered Rate (LIBOR), or Secured Overnight Financing Rate (SOFR) when LIBOR has permanently or indefinitely ceased or is no longer representative, or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating.

Any borrowings under the facility would be unsecured indebtedness at interest rates based on the Secured Overnight Financing Rate (SOFR), or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating.

No borrowings were outstanding under this facility at December 31, 2022.

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Notes due 2024 3.291 2.895 - 3.900

Floating rate notes due 2023 0.617 0.354 - 1.054

Notes due 2025 1.724 0.687 - 3.326

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Notes due 2030 2.236 1,500 1,500

Debentures due 2031 8.625 102 102

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Bank loans due 2023 5.206 4.928 - 5.342

3.400% loan 3

3.400 218 218

Medium-term notes, maturing from 2023 to 2038 6.306 4.283 - 7.900

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Debt due within one year ( 2,694 ) ( 4,946 )

Fair market value adjustment for debt acquired in the Noble Energy acquisition 741 1,690

Fair market value adjustment for debt acquired in the Noble acquisition 664 741

Reclassified from short-term debt 4,050 7,759

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2 Range of interest rates at December 31, 2022.

3 Principal amount to be repaid in installments between 2022 and 2025.

3 For details on finance lease liabilities, see Note 5 Lease Commitments .

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and after 2027 – $ 6,381 .

In addition to the $ 2.6 billion in long-term debt that matured in 2021, the company also completed a tender offer in October 2021, with the objective of lowering future interest expenses, and redeemed bonds with a face value of $ 2.6 billion and a book value of $ 3.4 billion (including the fair market valuation adjustment for debt acquired in the Noble Energy acquisition), which resulted in an after-tax loss on the extinguishment of debt of $ 260 million.

The company also repaid $ 1.1 billion of bank loans associated with the NBLX acquisition during 2021.

In February 2022, the company early-redeemed $ 1.4 billion in notes at face value that were scheduled to mature in March 2022.

In addition to the $ 4.9 billion in long-term debt that matured in 2022, the company also early-redeemed $ 3.0 billion in notes at face value that were scheduled to mature in the second quarter of 2023.

See Note 9 Fair Value Measurements for information concerning the fair value of the company’s long-term debt.

Notes to the Consolidated Financial Statements

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Accounting for Suspended Exploratory Wells

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If either condition is not met or if the company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense.

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The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended December 31, 2022:

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( 73 ) ( 34 ) ( 667 )

— 212 ( 141 )

Ending balance at December 31 $ 1,627 $ 2,109 $ 2,512

* 2020 represents fair value of well costs acquired in the Noble acquisition.

2019 represents property sales.

The following table provides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.

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* Certain projects have multiple wells or fields or both.

Of the $ 2,044 of exploratory well costs capitalized for more than one year at December 31, 2021, $ 1,119 is related to nine projects that had drilling activities underway or firmly planned for the near future.

The $ 925 balance is related to six projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not underway or firmly planned for the near future.

Of the $ 1,554 of exploratory well costs capitalized for more than one year at December 31, 2022, $ 945 is related to seven projects that had drilling activities underway or firmly planned for the near future.

The $ 609 balance is related to five projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not underway or firmly planned for the near future.

Additional drilling was not deemed necessary because the presence of hydrocarbons had already been established, and other activities were in process to enable a future decision on project development.

The projects for the $ 609 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability:

(a) $ 486 ( four projects) – undergoing front-end engineering and design with final investment decision expected within four years ;

(a) $ 194 ( three projects) – undergoing front-end engineering and design with final investment decision expected within four years ;

(b) $ 415 ( two projects) – development alternatives under review.

While progress was being made on all 12 projects, the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations associated with the projects.

More than half of these decisions are expected to occur in the next five years .

More than three-quarters of these decisions are expected to occur in the next five years .

The $ 1,554 of suspended well costs capitalized for a period greater than one year as of December 31, 2022, represents 71 exploratory wells in 12 projects.

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Total $ 1,554 12

Notes to the Consolidated Financial Statements

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Stock Options and Other Share-Based Compensation

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No significant stock-based compensation cost was capitalized at December 31, 2022, or December 31, 2021.

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Cash received in payment for option exercises under all share-based payment arrangements for 2022, 2021 and 2020 was $ 5,835 , $ 1,274 and $ 226 , respectively.

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Cash paid to settle performance shares, restricted stock units and stock appreciation rights was $ 556 , $ 163 and $ 95 for 2022, 2021 and 2020, respectively.

Cash paid in 2021 included $ 4 million for Noble awards paid under change-in-control plan provisions.

Awards under the Chevron Long-Term Incentive Plan (LTIP) may take the form of, but are not limited to, stock options, restricted stock, restricted stock units, stock appreciation rights, performance shares and nonstock grants.

From April 2004 through May 2023, no more than 260 million shares may be issued under the LTIP.

For awards issued on or after May 29, 2013, no more than 50 million of those shares may be in a form other than a stock option, stock appreciation right or award requiring full payment for shares by the award recipient.

On May 25, 2022, stockholders approved the Chevron 2022 Long-Term Incentive Plan (2022 LTIP).

Awards under the 2022 LTIP may take the form of, but are not limited to, stock options, restricted stock, restricted stock units, stock appreciation rights, performance shares and non-stock grants.

From May 2022 through May 2032, no more than 104 million shares may be issued under the 2022 LTIP.

For awards issued on or after May 25, 2022, no more than 48 million of those shares may be issued in the form of full value awards such as share-settled restricted stock, share-settled restricted stock units and other share-settled awards that do not require full payment in cash or property for shares underlying such awards by the award recipient.

For the major types of awards issued before January 1, 2017, the contractual terms vary between three years for the performance shares and restricted stock units, and 10 years for the stock options and stock appreciation rights.

For awards issued after January 1, 2017, contractual terms vary between three years for the performance shares and special restricted stock units, five years for standard restricted stock units and 10 years for the stock options and stock appreciation rights.

Forfeitures for performance shares, restricted stock units, and stock appreciation rights are recognized as they occur.

Forfeitures for stock options are estimated using historical forfeiture data dating back to 1990.

Commencing for grants issued in January 2023 and after, standard restricted stock units vest ratably on an annual basis over a three-year period.

Forfeitures of performance shares, restricted stock units, and stock appreciation rights are recognized as they occur.

Forfeitures of stock options are estimated using historical forfeiture data dating back to 1990.

Noble Share-Based Plans (Noble Plans) When Chevron acquired Noble in October 2020, outstanding stock options granted under various Noble Plans were exchanged for Chevron options.

These awards retained the same provision as the original Noble Plans.

These awards retained the same provisions as the original Noble Plans.

Awards issued may be exercised for up to five years after termination of employment, depending upon the termination type, or the original expiration date, whichever is earlier.

Other awards issued under the Noble Plans included restricted stock awards, restricted stock units, and performance shares, which retained the same provisions as the original Noble Plans.

Upon termination of employment due to change-in-control, all unvested awards issued under the Noble Plans, including stock options, restricted stock awards, restricted stock units and performance shares become vested on the termination date.

If not exercised, awards will expire between 2023 and 2029.

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Exercisable at December 31, 2022 16,421 $ 117.20 5.18 $ 1,178

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2022, 2021 and 2020 was $ 2,369 , $ 152 and $ 92 , respectively.

During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.

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As of December 31, 2022, there was $ 78 of total unrecognized before-tax compensation cost related to nonvested share-based compensation arrangements granted under the plan.

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At December 31, 2022, there were 4,753,266 performance shares outstanding that are payable in cash.

The fair value of the liability recorded for these instruments was $ 683 and was measured using the Monte Carlo simulation method.

The fair value of the liability recorded for these instruments was $ 996 and was measured largely using the Monte Carlo simulation method.

At January 1, 2022, the number of restricted stock units outstanding was equivalent to 4,386,637 shares.

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The fair value of the liability recorded for the vested portion of these instruments was $ 548 , valued at the stock price as of December 31, 2022.

In addition, outstanding stock appreciation rights that were granted under LTIP totaled approximately 3.4 million equivalent shares as of December 31, 2021.

In addition, outstanding stock appreciation rights that were granted under the LTIP totaled 686,573 equivalent shares as of December 31, 2022.

The fair value of the liability recorded for the vested portion of these instruments was $ 50 .

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Plan participants’ contributions — 3 — 3 62 43

Plan amendments 40 38 — — 18 —

Actuarial (gain) loss ( 2,753 ) ( 1,559 ) ( 325 ) ( 364 ) ( 509 ) ( 108 )

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Net amount recognized at December 31 $ ( 1,771 ) $ ( 68 ) $ ( 3,047 ) $ ( 401 ) $ ( 1,938 ) $ ( 2,489 )

For the year ended December 31, 2022, the decrease in benefit obligations was primarily due to actuarial gains caused by higher discount rates used to value the obligations and benefit payments paid to retirees in 2022.

For the year ended December 31, 2021, the decrease in benefit obligations was primarily due to actuarial gains caused by higher discount rates used to value the obligations and large benefit payments paid to retirees in 2021.

For the year ended December 31, 2020, the increase in benefit obligations was primarily due to actuarial losses caused by lower discount rates used to value the obligations.

Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $ 3,446 and $ 4,979 at the end of 2022 and 2021, respectively.

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Chevron has recorded no liability for this guarantee.

Indemnifications In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets that were sold in 1997.

The acquirer of those assets shared in certain environmental remediation costs up to a maximum obligation of $ 200 , which had been reached at December 31, 2009.

Under the indemnification agreement, after reaching the $ 200 obligation, Chevron is solely responsible until April 2022, when the indemnification expires.

The environmental conditions or events that are subject to these indemnities must have arisen prior to the sale of the assets in 1997.

Although the company has provided for known obligations under this indemnity that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized.

The company does not expect these costs will have a material effect on its consolidated financial position or liquidity.

Indemnifications The company often includes standard indemnification provisions in its arrangements with its partners, suppliers and vendors in the ordinary course of business, the terms of which range in duration and sometimes are not limited.

The company may be obligated to indemnify such parties for losses or claims suffered or incurred in connection with its service or other claims made against such parties.

Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain contingent liabilities with respect to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which may relate to suppliers’ financing arrangements.

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2027 – $ 311 ;

Notes to the Consolidated Financial Statements

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after 2027 – $ 1,233 .

A portion of these commitments may ultimately be shared with project partners.

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Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances by the company or other parties.

Such contingencies may exist for various operating, closed and divested sites, including, but not limited to, U.S.

Such contingencies may exist for various operating, closed and divested sites,

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including, but not limited to, U.S.

federal Superfund sites and analogous sites under state laws, refineries, chemical plants, marketing facilities, crude oil fields, and mining sites.

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AROs are primarily recorded for the company’s crude oil and natural gas producing assets.

No significant AROs associated with any legal obligations to retire downstream long-lived assets have been recognized, as indeterminate settlement dates

No significant AROs associated with any legal obligations to retire downstream long-lived assets have been recognized, as indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the associated ARO.

The company performs periodic reviews of its downstream long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation.

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for the asset retirements prevent estimation of the fair value of the associated ARO.

The company performs periodic reviews of its downstream long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation.

The following table indicates the changes to the company’s before-tax asset retirement obligations in 2022, 2021 and 2020:

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The long-term portion of the $ 12,701 balance at the end of 2022 was $ 11,419 .

Revenue from contracts with customers is presented in “Sales and other operating revenue” along with some activity that is accounted for outside the scope of Accounting Standard Codification (ASC) 606, which is not material to this line, on the Consolidated Statement of Income.

Revenue from contracts with customers is presented in “Sales and other operating revenues” along with some activity that is accounted for outside the scope of Accounting Standard Codification (ASC) 606, which is not material to this line, on the Consolidated Statement of Income.

Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another (including buy/sell arrangements) are combined and recorded on a net basis and reported in “Purchased crude oil and products” on the Consolidated Statement of Income.

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Receivables related to revenue from contracts with customers are included in “Accounts and notes receivable, net” on the Consolidated Balance Sheet, net of the allowance for doubtful accounts.

The net balance of these receivables was $ 12,877 and $ 7,631 at December 31, 2021 and December 31, 2020, respectively.

The net balance of these receivables was $ 14,219 and $ 12,877 at December 31, 2022 and 2021, respectively.

Other items included in “Accounts and notes receivable, net” represent amounts due from partners for their share of joint venture operating and project costs and amounts due from others, primarily related to derivatives, leases, buy/sell arrangements and product exchanges, which are accounted for outside the scope of ASC 606 .

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Earnings in 2020 included after-tax gains of approximately $ 765 relating to the sale of certain properties, of which approximately $ 30 and $ 735 related to downstream and upstream assets, respectively.

Earnings in 2022 included after-tax charges of approximately $ 1,075 for impairments and other asset write-offs and $ 600 for an early contract termination in upstream, and $ 271 for pension settlement costs.

Earnings in 2021 included after-tax charges of approximately $ 519 for pension settlement costs, $ 260 for early retirement of debt, $ 120 relating to upstream remediation and $ 110 relating to downstream legal reserves.

Earnings in 2020 included after-tax charges of approximately $ 4,800 for impairments and other asset write-offs related to upstream.

Earnings in 2019 included after-tax charges of approximately $ 10,400 for impairments and other asset write-offs related to upstream.

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* Includes $ 253 , $ 180 and $( 152 ) in 2022, 2021 and 2020, respectively, for the company’s share of equity affiliates’ foreign currency effects.

The company has $ 4,385 in goodwill on the Consolidated Balance Sheet, all of which is in the upstream segment and primarily related to the 2005 acquisition of Unocal.

The company has $ 4,722 in goodwill on the Consolidated Balance Sheet, of which $ 4,370 is in the upstream segment primarily related to the 2005 acquisition of Unocal and $ 352 is in the downstream segment.

The company tested this goodwill for impairment during 2022, and no impairment was required.

Financial Instruments - Credit Losses

Chevron’s expected credit loss allowance balance was $ 745 million as of December 31, 2021 and $ 671 million as of December 31, 2020, with a majority of the allowance relating to non-trade receivable balances.

Chevron’s expected credit loss allowance balance was $ 1.0 billion as of December 31, 2022 and $ 745 million as of December 31, 2021, with a majority of the allowance relating to non-trade receivable balances.

The majority of the company’s receivable balance is concentrated in trade receivables, with a balance of $ 18.2 billion as of December 31, 2022, which reflects the company’s diversified sources of revenues and is dispersed across the company’s broad worldwide customer base.

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Loans to equity affiliates and non-equity investees are also considered non-trade and associated allowances of $ 560 million are included within “Investments and Advances” on the Consolidated Balance Sheet at both December 31, 2022 and December 31, 2021.

Acquisition of Noble Energy, Inc.

On October 5, 2020, the company acquired Noble Energy, Inc., an independent oil and gas exploration and production company.

Noble’s principal upstream operations are in the United States, the Eastern Mediterranean and West Africa.

Noble’s operations also include an integrated midstream business in the United States.

The acquisition of Noble provides the company with low-cost proved reserves, attractive undeveloped resources and cash-generating assets.

The aggregate purchase price of Noble was $ 4,109 , with approximately 58 million shares of Chevron common stock issued as consideration in the transaction, representing approximately 3 percent of shares of Chevron common stock outstanding immediately after the acquisition.

As part of the transaction, the company recognized long-term debt and finance leases with a fair value of $ 9,231 .

Acquisition of Renewable Energy Group, Inc.

On June 13, 2022, the company acquired Renewable Energy Group, Inc.

(REG), an independent company focused on converting natural fats, oils and greases into advanced biofuels.

REG utilizes a global integrated production, procurement, distribution and logistics network to operate 11 biorefineries in the U.S.

Ten biorefineries produce biodiesel and one produces renewable diesel.

The acquisition combines REG’s growing renewable fuels production and leading feedstock capabilities with Chevron’s large manufacturing, distribution and commercial marketing position.

Chevron acquired outstanding shares of REG in an all-cash transaction valued at $ 3.15 billion, or $ 61.50 per share.

As part of the transaction, the company recognized long-term debt and finance leases with a fair value of $ 590 million.

The acquisition was accounted for as a business combination under ASC 805, which requires assets acquired and liabilities assumed to be measured at their acquisition date fair values.

Provisional fair value measurements were made for acquired assets and liabilities, and adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as information necessary to complete the analysis is obtained.

Oil and gas properties were valued using a discounted cash flow approach that incorporated internally generated price assumptions and production profiles together

Tangible and intangible assets were valued using a combination of replacement cost approach and discounted cash flows that incorporated internally generated price assumptions and production profiles together with appropriate operating and capital cost assumptions.

Debt assumed in the

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with appropriate operating cost and development cost assumptions.

Debt assumed in the acquisition was valued based on observable market prices for Noble’s debt.

As a result of measuring the assets acquired and the liabilities assumed at fair value, there was no goodwill or bargain purchase recognized.

acquisition was valued based on observable market prices for REG’s debt.

As a result of measuring the assets acquired and the liabilities assumed at fair value, the company recognized $ 293 million of goodwill.

The following table summarizes the values assigned to assets acquired and liabilities assumed:

At October 5, 2020

At June 13, 2022

(Millions of dollars)

Current assets $ 1,584

Investments and long-term receivables 1,282

Properties (includes $ 14,935 for oil and gas properties)

Properties, plant and equipment

Deferred tax 92

Other assets 374

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Long-term debt and finance leases 590

Deferred income taxes 2,355

Other liabilities 75

Total liabilities assumed 966

Noncontrolling interest and redeemable noncontrolling interest 779

Net assets acquired $ 2,862

The following unaudited pro forma summary presents the results of operations as if the acquisition of Noble had occurred January 1, 2019:

Year ended December 31

Sales and other operating revenues $ 96,980 $ 144,303

Net income $ ( 9,890 ) $ 1,412

The pro forma summary uses estimates and assumptions based on information available at the time.

Management believes the estimates and assumptions to be reasonable;

however, actual results may differ significantly from this pro forma financial information.

The pro forma information does not reflect any synergistic savings that might be achieved from combining the operations and is not intended to reflect the actual results that would have occurred had the companies actually been combined during the periods presented.

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Purchase Price $ 3,155

Pro forma financial information is not disclosed as the acquisition was deemed not to have a material impact on the company’s results of operations.

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In accordance with FASB and SEC disclosure requirements for oil and gas producing activities, this section provides supplemental information on oil and gas exploration and producing activities of the company in seven separate tables.

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Property acquisitions 2

Proved - Noble 3,463 — 438 7,945 — — 11,846 — —

Proved - Other 98 — 15 53 — — 166 — —

Unproved - Noble 2,845 2 113 129 — — 3,089 — —

Unproved - Other 13 16 — — — — 29 — —

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Property acquisitions 2

Proved 81 34 — 93 — — 208 — —

Unproved 68 150 — 17 1 — 236 — —

Proved - Noble 3,463 — 438 7,945 — — 11,846 — —

Proved - Other 23 — 2 56 — — 81 — —

Unproved - Noble 2,845 2 113 129 — — 3,089 — —

Unproved - Other 35 — 10 — — — 45 — —

Total property acquisitions 6,366 2 563 8,130 — — 15,061 — —

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3 Includes $186, $298 and $897 of costs incurred on major capital projects prior to assignment of proved reserves for consolidated companies in 2022, 2021, and 2020, respectively.

4 Reconciliation of consolidated and affiliated companies total cost incurred to Upstream capital and exploratory (C&E) expenditures - $ billions:

4 Reconciliation of consolidated companies total cost incurred to Upstream Capex - $ billions:

2022 2021 2020

Total cost incurred $ 9.8 $ 26.6 $ 17.2

Noble acquisition — (14.9) — See Note 29 for additional information

Non-oil and gas activities 0.2 — 0.3 (Primarily;

LNG and transportation activities.)

Total cost incurred by Consolidated Companies $ 9.8 $ 7.4 $ 23.5

Noble acquisition — — (14.9)

Expensed exploration costs (0.5) (0.4) (0.5) (Geological and geophysical and other exploration costs)

Non-oil and gas activities 0.6 0.2 — (Primarily LNG and transportation activities)

ARO reduction/(build) (0.3) (0.4) (0.8)

Upstream C&E $ 9.6 $ 10.9 $ 17.8 Reference page 45 Upstream total

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Upstream Capex $ 9.6 $ 6.8 $ 7.5 Reference page 46 Upstream Capex

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proved reserves, and changes in estimated discounted future net cash flows.

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Net Capitalized Costs $ 35,914 $ 12,696 $ 12,377 $ 17,566 $ 34,891 $ 1,747 $ 115,191 $ 24,281 $ 1,078

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Table III - Results of Operations for Oil and Gas Producing Activities 1

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Income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits.

Interest income and expense are excluded from the results reported in Table III and from the net income amounts on page 75.

Interest income and expense are excluded from the results reported in Table III and from the upstream net income amounts on page 76.

Consolidated Companies Affiliated Companies

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3 Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses.

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Table III - Results of Operations for Oil and Gas Producing Activities 1 , continued

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2 Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel.

3 2020 and 2019 unit prices have been conformed to current presentation.

3 2020 unit prices have been conformed to current presentation.

Crude and NGL realizations were previously combined and disclosed as liquids.

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Table V Proved Reserve Quantity Information *

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Total Proved Reserves 4,423 574 1,088 30,864 4,604 471 1,038 30,908 4,722 597 828 29,922

*Throughout Table V, some totals and percentages may not exactly agree with the sum of their component parts because of rounding.

* Reserve quantities include natural gas projected to be consumed in operations of 2,737, 2,505 and 2,490 billions of cubic feet and equivalent synthetic oil projected to be consumed in operations of 28, 17 and 21 millions of barrels as of December 31, 2022, 2021 and 2020, respectively.

Reserves Governance The company has adopted a comprehensive reserves and resources classification system modeled after a system developed and approved by a number of organizations, including the Society of Petroleum Engineers, the World Petroleum Congress and the American Association of Petroleum Geologists.

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Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.

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Proved reserves are estimated by company asset teams composed of earth scientists and engineers.

As part of the internal control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired by the Manager of Global Reserves, an organization that is separate from the upstream operating organization.

The Manager of Global Reserves has more than 30 years of experience working in the oil and gas industry and holds both undergraduate and graduate degrees in geoscience.

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and maintain the Chevron Corporation Reserves Manual , which provides standardized procedures used corporatewide for classifying and reporting hydrocarbon reserves.

During the year, the RAC is represented in meetings with each of the company’s upstream business units to review and discuss reserve changes recommended by the various asset teams.

During the year, the RAC is represented in meetings with each of the company’s business units to review and discuss reserve changes recommended by the various asset teams.

Major changes are also reviewed with the company’s senior leadership team including the Chief Executive Officer and the Chief Financial Officer.

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Quantity at January 1 3,860

Revisions 131

Improved recovery 15

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Quantity at December 31 3,907

In 2021, revisions include an increase of 202 million BOE in Australia, primarily from the approval of the Jansz Io Compression project (Gorgon and Jansz Io make up the Gorgon Project).

In the United States, there was a net increase of 192 million BOE primarily from the Midland and Delaware basins, where 105 million BOE was attributed to improved commodity price environment, and performance revisions, and 91 million BOE associated with the Anchor Project in the Gulf of Mexico due to improved commodity price.

In Bangladesh, there was an increase of 30 million BOE, primarily from

Supplemental Information on Oil and Gas Producing Activities - Unaudited

the approval of the Bibiyana Optimization Project and entitlement effects.

These increases were partially offset by a decrease of 339 million BOE in Kazakhstan, primarily at TCO, which includes entitlement effects, changes in field operating assumptions, reservoir model changes and changes to the FGP/WPMP schedule.

In 2021, extensions and discoveries of 630 million BOE in the United States were primarily due to the increase of activity and planned development of new locations in shale and tight assets in the Midland and Delaware basins.

In 2022, revisions include an increase of 257 million BOE in Israel, due to new wells and performance revisions in the Leviathan and Tamar fields.

This increase was largely offset by decreases of 145 million BOE from the United States primarily from portfolio optimizations in the Midland and Delaware basins, 69 million BOE in Kazakhstan primarily at TCO as higher prices reduced entitlement (Entitlement effects) and changes in operating assumptions reduced estimated

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undeveloped reserves, and 31 million BOE in Nigeria due to lower expected offtake of natural gas relative to contracted volumes.

In 2022, extensions and discoveries of 578 million BOE in the United States were primarily due to the increase of activity and planned development of new locations in shale and tight assets in the Midland, Delaware and DJ basins.

In Other Americas, 34 million BOE of extensions and discoveries were from shale and tight assets in Argentina and Canada.

The difference in 2022 extensions and discoveries of 122 million BOE, between the net quantities of proved reserves of 754 million BOE as reflected on pages 107 to 109 and net quantities of proved undeveloped reserves of 632 million BOE, is primarily due to proved extensions and discoveries that were not recognized as proved undeveloped reserves in the prior year and were recognized directly as proved developed reserves in 2022.

Purchases of 36 million BOE in 2021 are from the acquisition of various properties in the Midland and Delaware basins in the United States.

Transfers to proved developed reserves in 2021 include 245 million BOE in the United States, primarily from the Midland, Delaware and DJ basin developments and 125 million BOE in Equatorial Guinea, Canada, and other international locations.

Purchases of 61 million BOE in 2022 are primarily from the acquisition of various properties in the Midland and Delaware basins in the United States.

Transfers to proved developed reserves in 2022 include 309 million BOE in the United States, primarily from the Midland, Delaware and DJ basin developments, 207 million BOE in Australia, and 141 million BOE in Kazakhstan, Angola, Canada, Argentina and other international locations.

These transfers are the consequence of development expenditures on completing wells and facilities.

During 2022, investments totaling approximately $7.5 billion in oil and gas producing activities and about $0.1 billion in non-oil and gas producing activities were expended to advance the development of proved undeveloped reserves.

The United States accounted for about $2.8 billion related primarily to various development activities in the Midland and Delaware basins and the Gulf of Mexico.

In Asia, expenditures during the year totaled approximately $2.5 billion, primarily related to development projects of TCO in Kazakhstan.

The United States accounted for about $3.7 billion primarily related to various development activities in the Midland and Delaware basins and the Gulf of Mexico.

In Asia, expenditures during the year totaled approximately $2.6 billion, primarily related to development projects for TCO in Kazakhstan.

An additional $0.2 billion were spent on development activities in Australia.

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In Australia, approximately 235 million BOE remain undeveloped for five years or more related to the Gorgon and Wheatstone Projects.

Further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with operating constraints and infrastructure optimization.

Further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with operating constraints, reservoir depletion and infrastructure optimization.

In Africa, approximately 167 million BOE have remained undeveloped for five years or more, primarily due to facility constraints at various fields and infrastructure associated with the Escravos gas projects in Nigeria.

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Apart from acquisitions, the company’s ability to add proved reserves can be affected by events and circumstances that are outside the company’s control, such as delays in government permitting, partner approvals of development plans, changes in oil and gas prices, OPEC constraints, geopolitical uncertainties, and civil unrest.

Supplemental Information on Oil and Gas Producing Activities - Unaudited

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At December 31, 2022, proved reserves for the company were 11.2 billion BOE.

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Noteworthy changes in crude oil, condensate and synthetic oil proved reserves for 2020 through 2022 are discussed below and shown in the table on the following page:

Revisions In 2019, portfolio optimizations, where future drilling in various fields in the Midland and Delaware basins is being targeted away from reservoirs with higher gas-to-oil ratios and lower execution efficiencies, and planned divestments in the Appalachian basin, were primarily responsible for the 153 million barrels decrease in the United States.

Operational issues with the Petropiar upgrader in Venezuela resulted in a decrease in reserves of synthetic oil of 126 million barrels and an increase of crude oil and condensate reserves of 105 million barrels.

Reservoir management and entitlement effects were mainly responsible for the 75 million barrels increase at TCO in Kazakhstan.

Improved field performance at various fields, including Moho-Bilondo in the Republic of Congo, Mafumeira in Angola, and Sonam in Nigeria, were responsible for the 42 million barrels increase in Africa.

In 2020, capital reductions and commodity price effects in the Midland and Delaware basins and Anchor in the Gulf of Mexico, were primarily responsible for the 279 million barrels decrease in the United States.

Revisions In 2020, capital reductions and commodity price effects in the Midland and Delaware basins and Anchor in the Gulf of Mexico were primarily responsible for the 279 million barrels decrease in the United States.

Reserves in Venezuela affiliates decreased by 149 million barrels, primarily due to impairments and accounting methodology change.

Entitlement effects and performance revisions in TCO were primarily responsible for the 180 million barrels increase.

Entitlement effects primarily contributed to an increase of 77 million barrels synthetic oil at the Athabasca Oil Sands in Canada and 74 million barrels at multiple locations in Asia.

Entitlement effects primarily contributed to an increase of 77 million barrels of synthetic oil at the Athabasca Oil Sands in Canada and 74 million barrels at multiple locations in Asia.

In 2021, the 206 million barrels increase in United States was primarily in the Gulf of Mexico and the Midland and Delaware basins.

The higher commodity price environment led to the increase of 126 million barrels in the Gulf of Mexico primarily from Anchor and a 68 million barrels increase in Midland and Delaware basins due to higher planned development activity.

The higher commodity price environment led to the increase of 126 million barrels in the Gulf of Mexico primarily from Anchor and a 68 million barrels increase in the Midland and Delaware basins due to higher planned development activity.

In TCO, entitlement effects and technical changes in field operating assumptions, reservoir model, and project schedule were primarily responsible for the 208 million barrels decrease in Kazakhstan.

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In the Other Americas, performance revisions and price effects, mainly in Canada and Argentina, were primarily responsible for the 41 million barrels increase.

Extensions and Discoveries In 2019, portfolio optimizations, where future drilling in various fields in the Midland and Delaware basins is being targeted towards liquids-rich reservoirs with higher execution efficiencies, and extensions and discoveries in the deepwater fields in the Gulf of Mexico, were primarily responsible for the 394 million barrels increase in the United States.

Extensions and discoveries in Loma Campana in Argentina were primarily responsible for the 39 million barrels increase in Other Americas.

In 2020, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 105 million barrels increase in the United States.

In 2022, entitlement effects primarily contributed to a decrease of 49 million barrels of synthetic oil at the Athabasca Oil Sands project in Canada.

In TCO, entitlement effects and changes in operating assumptions were primarily responsible for the 35 million barrels decrease in Kazakhstan.

Extensions and Discoveries In 2020, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 105 million barrels increase in the United States.

In 2021, extensions and discoveries in the Midland and Delaware basins, and at the Whale Project in the Gulf of Mexico, were primarily responsible for the 349 million barrels increase in the United States.

In 2022, extensions and discoveries in the Midland, Delaware and DJ basins, and approval of the Ballymore Project in the Gulf of Mexico, were primarily responsible for the 264 million barrels increase in the United States.

In Other Americas, the 32 million barrels of extensions and discoveries were from Argentina and Canada.

Purchases In 2020, the acquisition of Noble assets contributed 227 million barrels in the DJ basin, Midland and Delaware basins in the United States.

Sales In 2019, sales of 69 million barrels in Europe were in the United Kingdom and Denmark.

In 2020, sales of 99 million barrels in Asia were in Azerbaijan.

In 2022, the company exercised its option to acquire additional land acreage in the Athabasca Oil Sands project in Canada contributing 168 million barrels in synthetic oil.

The extension of deepwater licenses in Nigeria and the Republic of Congo contributed 36 million barrels in Africa.

Sales In 2020, sales of 99 million barrels in Asia were in Azerbaijan.

In 2021, sales of 32 million barrels in the United States were in the Midland and Delaware basins.

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

Net Proved Reserves of Crude Oil, Condensate and Synthetic Oil

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2 Reserves associated with Canada.

3 Ending reserve balances in Africa were 4, 3 and 3 and in South America were 0, 0 and 156 in 2021, 2020 and 2019, respectively.

3 Reserves associated with Africa.

4 Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to page E-8 for the definition of a PSC).

PSC-related reserve quantities are 6 percent, 7 percent and 9 percent for consolidated companies for 2022, 2021 and 2020, respectively.

5 Reserve quantities include synthetic oil projected to be consumed in operations of 28, 17 and 21 millions of barrels as of December 31, 2022, 2021 and 2020, respectively.

Noteworthy changes in natural gas liquids proved reserves for 2020 through 2022 are discussed below and shown in the table on the following page:

Revisions In 2019, portfolio optimizations and low price realizations in various fields in the Midland and Delaware basins and planned divestments in the Appalachian basin were mainly responsible for the 120 million barrels decrease in the United States.

In 2020, capital reductions and commodity price effects in various fields in Midland and Delaware basins were primarily responsible for the 71 million barrels decrease in the United States.

Revisions In 2020, capital reductions and commodity price effects in various fields in Midland and Delaware basins were primarily responsible for the 71 million barrels decrease in the United States.

In 2021, higher commodity prices resulting in the increase of planned development activity in the Midland and Delaware basins were primarily responsible for the 107 million barrels increase in the United States.

Extensions and Discoveries In 2019, extensions and discoveries in the Midland and Delaware basins and deepwater fields in the Gulf of Mexico were primarily responsible for the 140 million barrels increase in the United States.

In 2020, extensions and discoveries in various fields in Midland and Delaware basins were primarily responsible for the 60 million barrels increase in the United States.

Extensions and Discoveries In 2020, extensions and discoveries in various fields in Midland and Delaware basins were primarily responsible for the 60 million barrels increase in the United States.

In 2021, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 190 million barrels increase in the United States.

In 2022, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 163 million barrels increase in the United States.

Purchases In 2020, the acquisition of Noble assets contributed 198 million barrels primarily in the DJ basin, Midland and Delaware basins and Eagle Ford shale in the United States.

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Sales In 2022, sales of 35 million barrels in the United States were primarily from the divestment of the Eagle Ford shale assets and some properties in the Midland and Delaware basins.

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

Net Proved Reserves of Natural Gas Liquids

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2 Reserves associated with Africa.

3 Year-end reserve quantities related to production-sharing contracts (PSC) (refer to page E-7 for the definition of a PSC) are not material for 2021, 2020 and 2019, respectively.

Noteworthy changes in natural gas proved reserves for 2019 through 2021 are discussed below and shown in the table above:

Revisions In 2019, strong performances at Wheatstone and the greater Gorgon areas were mainly responsible for 1.7 TCF increase in Australia.

At TCO in Kazakhstan, reservoir management and entitlement effects were mainly responsible for 223 BCF increase.

Portfolio optimizations and low price realizations in various fields of the Midland and Delaware basins and planned divestments in the Appalachian basin were mainly responsible for the 2.6 TCF decrease in the United States.

In 2020, the demotion of Jansz Io compression project reserves and lower field performance, partially offset by positive revisions at Gorgon, were mainly responsible for the net 2.5 TCF decrease in Australia.

3 Year-end reserve quantities related to PSC are not material for 2022, 2021 and 2020, respectively.

Noteworthy changes in natural gas proved reserves for 2020 through 2022 are discussed below and shown in the table on the following page:

Revisions In 2020, the demotion of Jansz Io compression project reserves and lower field performance, partially offset by positive revisions at Gorgon, were mainly responsible for the net 2.5 TCF decrease in Australia.

Capital reductions and commodity price effects in various fields of the Midland and Delaware basins were mainly responsible for the 509 BCF decrease in the United States.

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In TCO, entitlement effects and technical changes in field operating assumptions, reservoir model, and project schedule were primarily responsible for the 179 BCF decrease.

Extensions and Discoveries In 2019, extensions and discoveries of 1.0 TCF in the United States were primarily in the Midland and Delaware basins.

In 2020, extensions and discoveries of 385 BCF in the United States were primarily in the Midland and Delaware basins.

In 2022, the performance of the Leviathan and Tamar fields in Israel and the Bibiyana and Jalalabad fields in Bangladesh were mainly responsible for the 1.8 TCF increase in Asia.

In Australia, the 377 BCF decrease was mainly due to updated reservoir characterization of the Wheatstone field.

In TCO, entitlement effects and changes in operating assumptions were primarily responsible for the 285 BCF decrease.

Extensions and Discoveries In 2020, extensions and discoveries of 385 BCF in the United States were primarily in the Midland and Delaware basins.

In 2021, extensions and discoveries of 1.4 TCF in the United States were primarily in the Midland and Delaware basins.

Supplemental Information on Oil and Gas Producing Activities - Unaudited

In 2022, extensions and discoveries of 1.6 TCF in the United States were primarily in the Midland and Delaware basins.

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

Purchases In 2020, the acquisition of Noble assets contributed 5.4 TCF in Israel in Asia, 1.5 TCF in the DJ basin, Midland and Delaware basins and Eagle Ford Shale in the United States and 441 BCF in Equatorial Guinea in Africa.

Sales In 2019, sales of 240 BCF in Europe were in the United Kingdom and Denmark.

In 2020, sales of 1.3 TCF were primarily in the Appalachian basin in the United States and 264 BCF primarily in Azerbaijan in Asia.

Sales In 2020, sales of 1.3 TCF were primarily in the Appalachian basin in the United States and 264 BCF primarily in Azerbaijan in Asia.

In 2022, sales of 243 BCF in the United States were primarily in the Eagle Ford shale and Midland and Delaware basins.

Net Proved Reserves of Natural Gas

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1 Ending reserve balances in North America and South America were 407, 347 and 234 and 138, 108 and 95 in 2022, 2021 and 2020, respectively.

2 Ending reserve balances in Africa and South America were 893, 898 and 802 and 0, 0 and 64 in 2021, 2020 and 2019, respectively.

2 Reserves associated with Africa.

3 Total “as sold” volumes are 2,600, 2,599 and 2,447 for 2022, 2021 and 2020, respectively.

4 Includes reserve quantities related to production-sharing contracts (PSC) (refer to page E-7 for the definition of a PSC).

4 Includes reserve quantities related to PSC.

PSC-related reserve quantities are 8 percent, 8 percent and 10 percent for consolidated companies for 2022, 2021 and 2020, respectively.

Supplemental Information on Oil and Gas Producing Activities - Unaudited

5 Reserve quantities include natural gas projected to be consumed in operations of 2,737, 2,505 and 2,490 billions of cubic feet as of December 31, 2022, 2021 and 2020, respectively.

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

Table VI - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves

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$ 17,490 $ 4,046 $ 2,361 $ 8,808 $ 15,526 $ 212 $ 48,443 $ 9,849 $ 245 $ 58,537

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

Table VII - Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves

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3.1 Restated Certificate of Incorporation of Chevron Corporation, dated May 30, 2008, filed as Exhibit 3.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, and incorporated herein by reference.

3.2 By-Laws of Chevron Corporation, as amended and restated on September 30, 2020 filed as Exhibit 3.1 to Chevron Corporation ’ s Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, and incorporated herein by reference.

3.2 By-Laws of Chevron Corporation, as amended and restated December 7 , 202 2 , filed as Exhibit 3.

2 to Chevron Corporation’s Current Report on Form 8-K filed December 8, 2022 , and incorporated herein by reference.

4.1 Indenture, dated as of June 15, 1995, filed as Exhibit 4.1 to Chevron Corporation’s Amendment Number 1 to Registration Statement on Form S-3 filed June 14, 1995, and incorporated herein by reference.

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Wirth, filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, and incorporated herein by reference.

10.21+ 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed May 27, 2022, and incorporated herein by reference.

10.22+ Form of Performance Share Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.

10.23+ Form of Standard Restricted Stock Unit Award Agreement (stock settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.2 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.

10.24+ Form of Standard Restricted Stock Unit Award Agreement (cash settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.3 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.

10.25+ Form of Special Restricted Stock Unit Award Agreement (share settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.4 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.

10.26+ Form of Special Restricted Stock Unit Award Agreement (cash settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.5 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.

10.27+ Form of Non-Qualified Stock Options Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.6 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.

10.28+ Form of Stock Appreciation Right Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.7 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.

10.29+ Letter Agreement, dated May 25, 2022, by and between Chevron Corporation and Joseph C.

Geagea, filed as Exhibit 10.1 to Chevron Corporation's Current Report on Form 8-K filed May 27, 2022, and incorporated herein by reference.

10.30+* General Release and Separation Agreement, dated February 15, 2023, by and between Chevron Corporation and James W.

Subsidiaries of Chevron Corporation (page E-1).

22.1 Subsidiary Issuer of Guaranteed Securities, filed as Exhibit 22.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31 , 202 1 , and incorporated herein by reference.

22.1* Subsidiary Issuer of Guaranteed Securities.

Consent of PricewaterhouseCoopers LLP (page E-2).

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99.1* Definitions of Selected Energy and Financial Terms (pages E-7 through E-10).

99.2 Report of Netherland, Sewell & Associates, Inc.

, filed as Exhibit 99.3 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2020, and incorporated herein by reference.

iXBRL Schema Document.

iXBRL Calculation Linkbase Document.

iXBRL Definition Linkbase Document.

iXBRL Label Linkbase Document.

iXBRL Presentation Linkbase Document.

99.2 Report of Netherland, Sewell & Associates, Inc., filed as Exhibit 99.3 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2020, and incorporated herein by reference.

101* Interactive data files (formatted as Inline XBRL).

Cover Page Interactive Data File (contained in Exhibit 101).

Attached as Exhibit 101 to this report are documents formatted in iXBRL (Inline Extensible Business Reporting Language).

The financial information contained in the iXBRL-related documents is “unaudited” or “unreviewed.”

___________________________________________

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A copy of any such instrument will be furnished to the Securities and Exchange Commission upon request.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 24th day of February, 2022.

Chevron Corporation

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and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 24th day of February, 2022.

Principal Executive Officer

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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