What changed in this filing

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Item 9A. Controls and Procedures

2025-02-21 compared with 2024-02-26 · 652 added, 598 removed, 3121 unchanged (29% of the section changed)

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Based on the results of this evaluation, the company’s management concluded that internal control over financial reporting was effective as of December 31, 2024.

The company excluded PDC Energy, Inc.

(PDC) from our assessment of internal control over financial reporting as of December 31, 2023 because it was acquired by the company in a business combination during 2023.

Total assets and total

revenues of PDC, a wholly-owned subsidiary, represent five percent and one percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2023.

The effectiveness of the company’s internal control over financial reporting as of December 31, 2024, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein.

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Wirth , Chairman of the Board and Chief Executive Officer , entered into a pre-arranged stock trading plan on November 6, 2024 .

Wirth’s plan provides for the potential exercise of vested stock options and the associated sale of up to 404,500 shares of Chevron common stock between February 27, 2024 and January 28, 2025.

Hewitt Pate , Vice President and General Counsel , entered into a pre-arranged stock trading plan on November 27, 2023 .

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 27, 2024 and February 7, 2025.

Knowles , Vice President and Controller , entered into a pre-arranged stock trading plan on November 27, 2023 .

Knowles’ plan provides for the potential exercise of vested stock options and the associated sale of up to 17,534 shares of Chevron common stock between February 27, 2024 and November 30, 2024.

These trading plans were entered into during an open insider trading window and are each intended to satisfy the affirmative defense of Rule 10b5-1(c) under the Securities Exchange Act of 1934, as amended, and Chevron’s policies regarding transactions in Chevron securities.

Wirth’s plan provides for the potential exercise of vested stock options and the associated sale of up to 320,700 shares of Chevron common stock between February 26, 2025, and February 28, 2026 .

The trading plan was entered into during an open insider trading window and is intended to satisfy the affirmative defense of Rule 10b5-1(c) under the Securities Exchange Act of 1934, as amended, and Chevron’s policies regarding transactions in Chevron securities.

Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

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Chief Executive Officer

59 Vice President and Chief Financial Officer (since Apr 2019)

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

Bonner 50 Vice President (since Aug 2021);

Chief Financial Officer (since Mar 2024)

President and Chief Technology Officer, Chevron Technical Center (Feb 2021 - Dec 2023)

General Director, Tengizchevroil (Dec 2018 - Jan 2021)

Investor Relations

Nelson 61 Vice Chairman (since Feb 2023);

Executive Vice President, Oil, Products & Gas (since Oct 2024)

Executive Vice President, Strategy, Policy & Development (Oct

2022 - Sept 2023)

2022 - Sep 2023)

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

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

Strategy & Sustainability;

Corporate Affairs;

Corporate Business Development;

Procurement/Supply Chain Management;

Information Technology

Nigel Hearne 56 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) Upstream - Worldwide Exploration and Production;

Upstream - Worldwide Exploration and Production;

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

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Health, Safety and Environment;

49 Vice President (since Aug 2021)

President and Chief Technology Officer, Chevron Technical Center (Feb 2021 - Dec 2023)

General Director, Tengizchevroil (Dec 2018 - Jan 2021)

Investor Relations

Supply Chain Management

Gustavson 52 Vice President, Lower Carbon Energies (since Aug 2021)

Vice President, Midcontinent (Feb 2018 - July 2021) Lower Carbon Solutions

Vice President, Midcontinent (Feb 2018 - Jul 2021) Lower Carbon Solutions

Balaji Krishnamurthy 48 Vice President (since Oct 2022);

Vice President, Chevron Technical Center (since Jan 2024)

Vice President, Strategy & Sustainability (Oct 2022 - Sept 2023)

President, Chevron Canada Limited (June 2021 - Sept 2022)

Vice President, Strategy & Sustainability (Oct 2022 - Sep 2023)

President, Chevron Canada Limited (Jun 2021 - Sep 2022)

General Manager, Corporate Transformation and Integration Management (Dec 2019 - May 2021)

Deputy Managing Director, Eurasia Business Unit (June 2018 - Dec 2019)

Global Reserves;

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Capital Projects;

Downstream Technology

Morris 58 Vice President and Chief Human Resources Officer (since Feb 2019) Human Resources;

Diversity and Inclusion

Technology Strategy Execution and Performance;

Information Technology;

Environmental Management;

Hewitt Pate 62 Vice President and General Counsel (since Aug 2009) Law, Governance and Compliance

* Effective March 1, 2024, Ms.

Bonner will assume the position of Vice President and Chief Financial Officer.

The information about directors required by Item 401(a), (d), (e) and (f) of Regulation S-K and contained under the heading “Election of Directors” in the Notice of the 2025 Annual Meeting of Stockholders and 2025 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act in connection with the company’s 2025 Annual Meeting (the 2025 Proxy Statement), is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 405 of Regulation S-K and contained under the heading “Delinquent Section 16(a) Reports” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 406 of Regulation S-K and contained under the heading “Business Conduct and Ethics Code” in the 2025 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

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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 2025 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 2024 Proxy Statement is incorporated herein 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 2025 Proxy Statement is incorporated herein by reference into this

Annual Report on Form 10-K.

Pursuant to the rules and regulations of the SEC under the Exchange Act, the information under such caption incorporated by reference from the 2025 Proxy Statement shall not be deemed to be “soliciting material,” or to be “filed” with the Commission, or subject to Regulation 14A or 14C or the liabilities of Section 18 of the Exchange Act, nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933.

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Summarized Financial Data - Tengizchevroil LLP

Summarized Financial Data - Chevron Phillips

Chemical Company LLC

Restructuring and Reorganization Costs

Fair Value Measurements

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Chevron Corporation is a global energy company with direct and indirect subsidiaries and affiliates that conduct substantial business activities in the following countries:

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.

Angola, Argentina, Australia, Bangladesh, Brazil, Canada, China, Egypt, Equatorial Guinea, Israel, Kazakhstan, Mexico, Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait, the Philippines, 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.

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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.

Some governments, companies, communities and other stakeholders are 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, reporting, marketing and advertising relating to emissions and emission reductions and removals.

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 and acceptability of cost-effective, verifiable carbon credits;

the availability of suppliers that can meet our sustainability-related standards;

evolving regulatory or other requirements affecting ESG standards or disclosures and evolving standards and regulations for tracking, reporting, marketing and advertising relating to 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.

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California’s Cap-and-Trade Program;

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

EPA’s Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources;

performance standards, including methane-specific regulations such as the United States Environmental Protection Agency (U.S.

EPA) Standards of Performance for New, Reconstructed, and Modified Sources 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.

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These compliance policies and programs have had and may continue to have negative impacts on the company now and in the future including, but not limited to, the displacement of hydrocarbon and other products and/or the impairment of assets.

These policies have also enabled opportunities for Chevron in 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.

These policies have also enabled opportunities for Chevron in its lower carbon business lines.

For example, Renewable Energy Group, Inc.

(REG) produces most of Chevron’s renewable fuels offering and generates a substantial amount of 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.

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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 oil and gas business, lower the carbon intensity of its operations and grow lower carbon businesses in renewable fuels, carbon capture and offsets, hydrogen 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, partnerships and customer relationships.

The company’s oil and gas business may increase or decrease depending upon regulatory or market forces, among other factors.

In 2021, Chevron announced the following aspirations and targets that are aligned with its lower carbon strategy:

Chevron aims to grow its oil and gas business, lower the carbon intensity of its operations and grow new businesses in renewable fuels, carbon capture and offsets, hydrogen, power generation for data centers, and emerging technologies.

To grow its new 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, partnerships and customer relationships.

The company’s oil and gas business may increase or decrease depending upon market, economic, legislative and regulatory forces, among other factors.

In 2021, Chevron announced aspirations and targets that align with its strategy, as noted below.

Chevron uses emissions intensity targets, which enable the company to assess, quantify and transparently communicate its own carbon performance in a standardized way.

Chevron regularly evaluates its aspirations, targets and goals and expects to change or eliminate some of its aspirations, targets and goals for various reasons, including market conditions;

its strategy or portfolio;

and financial, operational, policy, reputational, legal and other factors.

The company’s ability to achieve any aspiration, target or goal is subject to numerous risks and contingencies, many of which are outside of Chevron’s control.

Examples of such risks and contingencies include:

(1) sufficient and substantial advances in technology, including the continuing progress of commercially viable technologies and low- or non-carbon-based energy sources;

(2) laws, governmental regulation, policies, and other enabling actions, including those regarding subsidies, tax and other incentives as well as the granting of necessary permits by governing authorities;

(3) the availability and acceptability of cost-effective, verifiable carbon credits;

(4) the availability of suppliers that can meet our

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

sustainability-related standards;

(5) evolving regulatory requirements, including changes to IPCC’s Global Warming Potentials and the U.S.

EPA Greenhouse Gas Reporting Program, affecting ESG standards or disclosures;

(6) evolving standards for tracking and reporting on emissions and emission reductions and removals;

(7) customers’ and consumers’ preferences and use of the company’s products or substitute products;

(8) actions taken by the company’s competitors in response to legislation and regulations;

and (9) successful negotiations for carbon capture and storage and nature-based solutions with customers, suppliers, partners and governments.

Please refer to “Risk Factors” in Part I, Item 1A, on pages 23 through 27 for further discussion of GHG regulation and climate change and the associated risks to Chevron’s business, including the risks impacting Chevron’s strategy, aspirations, targets and disclosures related to environmental, social, and governance matters.

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 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.

The company believes accomplishing this aspiration depends on, among other things, sufficient and substantial advances in technology, including the continuing progress of commercially viable technologies and low- or non-carbon-based energy sources;

enabling policies and other actions by governing authorities, including those regarding subsidies, tax and other incentives as well as the granting of necessary permits;

successful negotiations for carbon capture and storage and nature-based solutions with customers, suppliers, partners and governments;

market conditions;

and the availability and acceptability of cost-effective, verifiable carbon credits.

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

The 2028 GHG emissions intensity targets on an equity ownership basis include:

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

• Oil production GHG intensity of 24 kilograms (kg) carbon dioxide equivalent per barrel of oil-equivalent (CO 2 e/boe),

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• Flaring GHG intensity of 3 kg CO 2 e/boe.

The company also targets no routine flaring by 2030.

Chevron uses emissions intensity targets, which enable the company to assess, quantify and transparently communicate its own carbon performance in a standardized way.

The company also targets zero routine flaring by 2030 as outlined in the World Bank’s “Zero Routine Flaring by 2030” initiative.

2028 Portfolio Carbon Intensity Target The company also introduced a portfolio carbon intensity (PCI) metric, which is a measure of the carbon intensity across the full value chain of Chevron’s entire business.

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The company’s PCI target is 71 grams (g) carbon dioxide equivalent (CO 2 e) per megajoule (MJ) by 2028.

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 oil and gas operations, and approximately $8 billion for lower carbon investments in renewable fuels, hydrogen and carbon capture and offsets.

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

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

Beyond 2028, the company anticipates capital spending will be necessary to progress the company’s 2050 upstream production Scope 1 and 2 net zero aspiration and building of its lower carbon business lines.

Since 2021, the company has spent $7.7 billion in lower carbon investments, including $2.9 billion associated with the acquisition of REG in 2022.

Chevron’s goals, targets and aspirations reflect Chevron’s current plans, and Chevron may change them for various reasons, including market conditions;

changes in its portfolio;

and financial, operational, regulatory, reputational, legal and other factors.

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.

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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 were effective in 2023, including a 15 percent minimum tax on book income and a one 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.

The IRA has not had a material impact on our results of operations.

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

In December 2021, the Organization for Economic Co-operation and Development (OECD) issued model rules for a new 15 percent global minimum tax (Pillar Two), and various jurisdictions in which the company operates enacted or are in the process of enacting Pillar Two legislation.

Certain aspects of the tax under the Pillar Two framework will be effective beginning in 2024 in some jurisdictions and in 2025 (or later) in others.

Although we do not currently expect that Pillar Two will have a material impact on our results of operations, we are continuing to evaluate the impact of legislative adoption by individual countries.

Certain aspects of the tax under the Pillar Two framework became effective in 2024 in some jurisdictions and will be effective in 2025 (or later) in others.

Pillar Two did not have a material impact on the company’s results of operations in 2024.

Although we do not currently expect that Pillar Two will have a material impact on our future results of operations, we are continuing to evaluate the impact of pending legislative adoption by individual countries.

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.

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

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

While macroeconomic inflation is easing, trends in the costs of goods and services vary by spend category.

Trends in the costs of goods and services vary by spend category.

The labor market remains tight, and suppliers are passing along wage rate increases for labor intensive operations.

Chevron has applied inflation mitigation strategies in an effort to temper these cost increases, including fixed price and index-based contracts.

Lead times for key capital equipment remain long.

Chevron has addressed lead times by partnering with suppliers on demand planning, volume commitments, standardization and scope optimization.

Raw material prices have declined, leading to a lower cost for drilling pipe, chemicals and construction materials.

Onshore drilling activity in the United States declined;

however, availability of specialized offshore drilling rigs, supply vessels and equipment to perform onshore hydraulic fracturing remains under pressure.

Lead times for key capital equipment remain long and availability of offshore and specialized equipment is under pressure, with some experiencing upward pricing movements.

In the United States, cost pressures for materials and standard onshore drilling and completion equipment continue to ease.

Chevron has addressed equipment cost increases and long lead times by partnering with suppliers on demand planning, volume commitments, standardization and scope optimization.

In February 2025, the U.S.

announced the imposition of tariffs on imports from several U.S.

trade partners and could announce additional tariffs in future periods.

There is significant uncertainty as to the duration of these and any further tariffs, and the impacts these tariffs and any corresponding retaliatory tariffs will have on the company and its suppliers.

The financial impacts of the tariffs are currently not expected to be material;

however, the ultimate impact on the company’s results of operations and financial condition remains uncertain.

Refer to the Cautionary Statement Relevant to Forward-Looking Information on page 2 and to Item 1A.

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Acquisition and Disposition of Assets 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.

The company is targeting $10-15 billion of asset sales over the five-year period ending in 2028.

From 2024 through January 2025, the company has generated approximately $8 billion of asset sales proceeds.

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

In addition, some assets are sold along with their related liabilities, such as abandonment and decommissioning obligations.

In certain instances, such transferred obligations have, and may in the future, revert to the company and result in losses that could be significant.

In fourth quarter 2023, the company recognized an after-tax loss of $1.9 billion related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S.

Gulf of Mexico, as companies that purchased these assets have filed for protection under Chapter 11 of the U.S.

Bankruptcy Code, and the company believes it is now probable and estimable that a portion of these obligations will revert to the company.

The cash outlays for these abandonment and decommissioning obligations are expected to take place over the next decade.

Other Impacts The company closely monitors developments in the financial and credit markets, the level of worldwide economic activity, and the implications for the company of movements in prices for crude oil and natural gas.

In addition, some assets are divested along with their related liabilities, such as decommissioning obligations.

In certain instances, such transferred obligations have returned and may continue to return to the company and result in losses that could be significant.

For example, in fourth quarter 2023, the company recognized charges for decommissioning obligations from certain previously divested assets in the Gulf of America.

In 2024, the company spent $235 million related to these obligations and anticipates spending an additional $200-300 million annually through 2033.

To the extent the current owners of the company’s previously divested assets default on their decommissioning obligations, regulators may require that Chevron assume such obligations.

The company could have additional significant obligations revert, primarily in the United States.

The company is not currently aware of any such obligations that are reasonably possible to be material.

Refer to Note 24.

Other Contingencies and Commitments for additional information.

In December 2024, the company sold its 20 percent non-operated interest in the Athabasca Oil Sands Project and 70 percent operated interest in the Duvernay shale in Alberta, Canada, to Canadian Natural Resources Limited for $6.5 billion before taxes, and expects to make tax payments totaling $1.5 billion in first quarter 2025.

In 2024, these assets produced 86 thousand barrels of oil-equivalent per day and generated over $2.2 billion of sales and approximately $590 million of operational net income.

As part of the sale, the buyer assumed decommissioning obligations for the transferred assets.

In October 2023, the company announced that it had entered into a definitive merger agreement with Hess Corporation.

Refer to Note 30.

Agreement to Acquire Hess Corporation for additional information.

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

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

In fourth quarter 2024, the company announced plans to achieve $2-3 billion in structural cost reductions by the end of 2026.

These cost savings will largely come from optimizing the portfolio, leveraging technology to enhance productivity, and changing how and where work is performed, including expanded use of global capability centers.

In relation to these efforts, the company recognized a restructuring charge of $715 million after tax in fourth quarter 2024, with associated cash outflows anticipated over the next two years.

The company continues to evaluate incremental cost reduction opportunities and could incur additional restructuring and reorganization charges in future periods.

This will have an impact on the company’s pension and Other Post-Employment Benefit (OPEB) plans;

however, the impact is not yet estimable and any impacts will be recognized in future periods.

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.

Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry production and inventory levels, technology advancements, production quotas or other actions imposed by OPEC+ countries, actions of regulators, weather-related damage and disruptions, competing fuel prices, natural and human causes beyond the company’s control, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty.

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

These prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry production and inventory levels, technology advancements, production quotas or other actions imposed by OPEC+ countries, actions of regulators, weather-related damage and disruptions, competing fuel prices, natural and human causes beyond the company’s control, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty.

Any of these factors could also inhibit the company’s production capacity in an affected region.

The company closely monitors developments in the countries in which it operates and holds investments and seeks to manage risks in operating its facilities and businesses.

The longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to efficiently find, acquire and 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 has begun to experience regulatory challenges and delays in obtaining permits to conduct operations in certain jurisdictions.

These challenges have, and may continue to, impact the company’s plans for future investments.

For example, during fourth quarter 2023, the company impaired a portion of its U.S.

upstream assets, primarily in California, due to continuing regulatory challenges in the state that have resulted in lower anticipated future investment levels in its business plans.

The company expects to continue operating the impacted assets for many years to come.

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

In April 2024, Tengizchevroil LLP (TCO) achieved start-up of the Wellhead Pressure Management Project (WPMP) and at year-end 2024, all four pressure boost facility compressors are online and all metering stations have been converted to low pressure.

In January 2025, TCO started oil production at its Future Growth Project, which is expected to contribute to higher free cash flow.

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.

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

In fourth quarter 2022, Chevron received General License 41 from the United States government, enabling the company to resume activity in Venezuela subject to certain limitations, and the company continues such activities under this General License.

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 started in first quarter 2023, which have positively impacted the company’s 2023 results, but future results remain uncertain.

Crude oil liftings in Venezuela started in first quarter 2023, which have positively impacted the company’s results.

The company’s independent affiliates have continued to maintain safe and reliable operations;

however, future impact on results of operations and financial condition remain uncertain.

Chevron maintains an equity interest in the Caspian Pipeline Consortium (CPC) which provides a primary export route for Tengiz field production in Kazakhstan.

An adverse event or incident affecting CPC operations, which CPC has experienced from time to time, could have a negative impact on the Tengiz field and the company’s results of operations and financial position.

The financial impacts of such risks, including presently imposed sanctions and the February 2025 drone attack on the CPC pumping station, remain uncertain.

Other 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.

Chevron holds a 39.7 percent interest in the Leviathan field and a 25 percent interest in the Tamar field in Israel.

Despite the ongoing conflict between Israel and various regional adversaries, the company continues to maintain safe and reliable operations while meeting its contractual commitments.

The company continues to monitor the ongoing conflict in the region and any future impacts on the company’s results of operations and financial condition remain uncertain.

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

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.

An adverse effect on the Caspian Pipeline Consortium (CPC) operations could have a negative impact on the Tengiz field in Kazakhstan and the company’s results of operations and 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.

Chevron holds a 39.7 percent interest in the Leviathan field and a 25 percent interest in the Tamar gas field in Israel.

In early October 2023, due to a war between Israel and Hamas, the Government of Israel directed the company to shut down production at the Tamar gas field.

Approximately one month later, the company resumed production, and the Tamar gas field is currently operational.

The Leviathan gas field was not impacted by the war and is currently operational.

The financial impacts of the Tamar shutdown and other operational impacts were not material for the company.

However, given the ongoing conflict, the future impacts on the company’s results of operations and financial condition remain uncertain.

Chevron operates and holds interests in the Bibiyana, Jalalabad and Moulavi Bazar fields in Bangladesh.

Recent political unrest in the country has not impacted the company’s operations to date;

however, the future impacts, if any, on the company’s results of operations and financial condition remain uncertain.

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

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

Crude prices were volatile in 2023 due to tapering of post-pandemic demand resurgence, OPEC+ supply cuts, Federal Reserve interest rate action, and the proliferation of geopolitical conflict.

The company’s average realization for U.S.

crude oil and NGLs in 2023 was $59 per barrel, down 23 percent from 2022.

The company’s average realization for international crude oil and NGLs in 2023 was $72 per barrel, down 21 percent from 2022.

Henry Hub natural gas price averaged $2.25 per thousand cubic feet (MCF) for the full-year 2024, compared to $2.56 in 2023.

As of mid-February 2025, the Henry Hub price was $4.42 per MCF.

See page 47 for the company’s U.S.

and international average realizations for each of the past three years.

Crude prices in 2024 were influenced by geopolitical conflict and OPEC+ supply restraint, which was offset by factors such as non-OPEC supply growth and slowing demand growth.

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 $2.56 per thousand cubic feet (MCF) during 2023, compared with $6.36 per MCF during 2022.

High storage levels and strong production resulted in these lower prices.

As of mid-February 2024, the Henry Hub spot price was $1.73 per MCF.

(See page 45 for the company’s average natural gas realizations for the U.S.)

In the United States, lower Henry Hub prices were driven by high storage levels, strong production, and delayed starts to liquefied natural gas (LNG) export projects.

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.

The company’s long-term contract prices for 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 $7.69 per MCF during 2023, compared with $9.75 per MCF during 2022, mainly due to lower LNG prices.

Production The company’s worldwide net oil-equivalent production in 2023 was 3.1 million barrels per day, 4 percent higher than in 2022 primarily due to the acquisition of PDC Energy, Inc.

(PDC) and growth in the Permian Basin.

About 26 percent of the company’s net oil-equivalent production in 2023 occurred in OPEC+ member countries of Angola, Equatorial Guinea, Kazakhstan, Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait and Republic of Congo.

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

The company estimates its net oil-equivalent production in 2024 to increase four to seven percent over 2023, assuming a Brent crude oil price of $80 per barrel and including expected asset sales.

Production The company’s worldwide net oil-equivalent production in 2024 was 3.3 million barrels per day, 7 percent higher than in 2023 primarily due to the full-year of legacy PDC Energy, Inc.

(PDC) production and growth in the Permian Basin.

About 20 percent of the company’s net oil-equivalent production in 2024 occurred in OPEC+ member countries of Equatorial Guinea, Kazakhstan, Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait and the Republic of Congo.

The company estimates its net oil-equivalent production in 2025 to increase six to eight percent over 2024, assuming a Brent crude oil price of $70 per barrel and excluding expected asset sales.

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

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or other disruptions to operations.

The outlook for future production levels is also affected by the size and number of economic investment opportunities and the time lag between initial exploration and the beginning of production.

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

Proved Reserves Net proved reserves for consolidated companies and affiliated companies totaled 11.1 billion barrels of oil-equivalent at year-end 2023, a slight decrease from year-end 2022.

The reserve replacement ratio in 2023 was 86 percent.

The outlook for future

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

production levels is also affected by the size and number of economic investment opportunities and the time lag between initial exploration and the beginning of production.

Net crude oil production

Thousands of barrels per day

Other Americas

United States

Net natural gas liquids production

Thousands of barrels per day

Other Americas

United States

Net natural gas production

Millions of cubic feet per day

Other Americas

United States

Net proved reserves by geographic area

Billions of BOE*

Other Americas

United States

*barrels of oil-equivalent

Net proved reserves by product

Billions of BOE*

Natural gas liquids

*barrels of oil-equivalent

Proved Reserves Net proved reserves for consolidated companies and affiliated companies totaled 9.8 billion barrels of oil-equivalent at year-end 2024, a decrease from year-end 2023.

The reserve replacement ratio in 2024 was negative 4 percent.

The 5 and 10 year reserve replacement ratios were 72 percent and 88 percent, respectively.

Refer to Table V for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2022 and each year-end from 2022 through 2024, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2024.

Refer to the “Results of Operations” section on pages 41 and 42 for additional discussion of the company’s upstream business.

Refer to the “Results of Operations” section on pages 43 for additional discussion of the company’s upstream business.

Downstream Earnings for the downstream segment are closely tied to margins on the refining, manufacturing and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil, fuel and lubricant additives, petrochemicals and renewable fuels.

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Other factors affecting profitability for downstream operations include the reliability and efficiency of the company’s refining, marketing and petrochemical assets, the effectiveness of its crude oil and product supply functions, and the volatility of tanker-charter rates for the company’s shipping operations, which are driven by the industry’s demand for crude oil and product tankers.

Other factors beyond the company’s control include the general level of inflation and energy

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

costs to operate the company’s refining, marketing and petrochemical assets, and changes in tax, environmental, and other applicable laws and regulations.

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.

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 growing presence in renewable fuels in the United States after acquiring REG in 2022.

The company is also one of the largest renewable fuels producers in the United States.

Refer to the “Results of Operations” section on page 44 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.

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 2024 and early 2025 included the following:

Angola Received approvals to extend Block 0 concession through 2050.

Australia Achieved first natural gas production from the Gorgon Stage 2 development, supporting long-term energy supply in the Asia-Pacific region.

Israel Reached final investment decision to construct a third gathering pipeline that is expected to increase natural gas production capacity from approximately 1.2 to nearly 1.4 billion cubic feet per day from the Leviathan reservoir.

Japan Announced agreements to conduct pilot tests on advanced closed loop geothermal technology.

Kazakhstan Achieved mechanical completion on the Future Growth Project at the company’s 50 percent-owned affiliate, Tengizchevroil.

United States Announced an agreement to install new technologies on the company’s LNG vessels that are intended to reduce the carbon intensity of its LNG fleet operations.

United States Expanded the Bayou Bend carbon capture and sequestration hub on the U.S.

Gulf Coast through an acquisition of nearly 100,000 acres, and became the operator of the hub.

United States Announced commercial collaboration to purchase next generation renewable feedstocks that are intended to benefit farmers and increase supplies to meet a growing demand for lower carbon renewable fuels.

United States Acquired 73 exploration blocks in Gulf of Mexico lease sale 259 and submitted winning bids on an additional 28 exploration blocks in Gulf of Mexico lease sale 261, subject to final government approval.

United States Achieved first oil at the Mad Dog 2 project in the Gulf of Mexico.

United States Started operations of a solar power project with a joint venture partner in New Mexico to provide lower carbon energy for the Permian Basin.

United States Converted the diesel hydrotreater at the El Segundo, California refinery to process either 100 percent renewable or traditional feedstocks.

United States Completed the acquisition of PDC, adding 275,000 net acres in the Denver-Julesburg (DJ) Basin and 25,000 net acres in the Permian Basin.

United States Completed the acquisition of a majority stake in ACES Delta, LLC, which is developing a green hydrogen production and storage hub in Utah.

United States Announced a definitive agreement to acquire Hess Corporation (Hess), which is expected to strengthen Chevron’s long-term performance by adding world-class assets and people.

Venezuela Received approval to extend licenses with PetroBoscan, S.A.

and PetroIndependiente, S.A.

through 2041.

Angola Added frontier exploration acreage positions in the deepwater lower Congo Basin.

Angola Achieved first gas on the Sanha Lean Gas Connection project, securing incremental natural gas supply to the Angola Liquefied Natural Gas facility.

Australia Announced asset exchange of North West Shelf Assets for Wheatstone Assets and Julimar/Brunello fields.

Australia Received two offshore greenhouse gas assessment permits, covering an area of approximately 10,700 km 2 , to assess future carbon dioxide storage.

Brazil Secured 15 exploration blocks in the South Santos and Pelotas Basins .

Canada Sold the company’s interest in the Athabasca Oil Sands Project and Duvernay shale for $6.5 billion.

Equatorial Guinea Signed agreements to acquire two exploration blocks offshore Bioko Island.

Israel Reached final investment decision to add midstream infrastructure that is expected to increase production capacity at the Tamar gas field in Israel to 1.6 billion cubic feet per day.

Kazakhstan Completed the Wellhead Pressure Management Project and, in January 2025, started production at the Future Growth Project, which is expected to ramp up total output to around one million barrels of oil equivalent per day at the company’s 50 percent-owned affiliate, Tengizchevroil LLP in Kazakhstan.

Myanmar Withdrew from Chevron’s nonoperated working interests effective April 1, 2024.

Namibia Signed agreements to acquire 80 percent working interest in Petroleum Exploration License 82 in the Walvis Basin.

Nigeria Extended the Meji field offshore Nigeria with a near-field discovery and renewed the Agbami deep-water concession through 2044.

Republic of Congo Sold the company’s 31.5 percent nonoperated working interest in the offshore Haute Mer permit area and its 15.75 percent interest in the Republic of Congo portion of Lianzi in January 2025.

United States Reached final investment decision to build an oilseed processing plant in Louisiana through the company’s joint venture Bunge Chevron Ag Renewables LLC.

United States Drilled onshore and offshore stratigraphic wells to delineate carbon dioxide storage potential through the company’s joint venture Bayou Bend CCS LLC.

United States Launched a $500 million Future Energy Fund III focused on venture investments in technology-based solutions that have the potential to enable affordable, reliable and lower carbon energy.

United States Progressed the company’s pending merger with Hess Corporation by securing Hess stockholder approval and clearing Federal Trade Commission antitrust review.

United States Started production at the industry-first 20,000 pounds per square inch deepwater Anchor project, began water injection to boost production from the St.

Malo and Tahiti fields, and in January 2025 started production from the Whale semi-submersible platform in the Gulf of America.

United States Upgraded the Pasadena Refinery, which is expected to increase product flexibility and expand the processing capacity of lighter crude oil to 125,000 barrels per day.

United States Completed projects and operational changes designed to abate over 700,000 tonnes of carbon dioxide-equivalent from the company’s operations.

United States Announced plans to jointly develop scalable power solutions using natural gas-fired turbines with flexibility to integrate carbon capture and storage to support growing energy demand from U.S.

data centers.

Uruguay Entered an agreement to assume a 60 percent operated interest in Uruguay’s AREA OFF-1 offshore exploration block.

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

Common Stock Dividends The 2024 annual dividend was $6.52 per share, making 2024 the 37th consecutive year that the company increased its annual per share dividend payout.

In January 2024, the company’s Board of Directors increased its quarterly dividend by $0.12 per share, approximately eight percent, to $1.63 per share payable in March 2024.

In January 2025, the company’s Board of Directors increased its quarterly dividend by $0.08 per share, approximately five percent, to $1.71 per share payable in March 2025.

Common Stock Repurchase Program The company repurchased $15.2 billion of its common stock in 2024 under its stock repurchase program.

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

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

Results of Operations

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A discussion of variances between 2023 and 2022 can be found in the “Results of Operations” section on pages 41 through 43 of the company’s 2023 Annual Report on Form 10-K filed with the SEC on February 26, 2024.

Worldwide Upstream earnings

Billions of Dollars

United States

International

Worldwide Downstream earnings

Billions of dollars

United States

International

refined product sales

Thousands of barrels per day

Diesel/Gas oil

International refined product sales*

Thousands of barrels per day

Diesel/Gas oil

*includes equity share in affiliates

2024 2023 2022

10 unchanged sentences

MBOED — thousands of barrels of oil-equivalent per day.

upstream earnings decreased by $8.5 billion primarily due to lower realizations of $6.2 billion, $1.9 billion in charges related to abandonment and decommissioning obligations for previously sold oil and gas producing assets in the U.S.

Gulf of Mexico, and higher impairment charges of $1.8 billion, mainly from assets in California.

Partially offsetting these items are higher sales volumes of $1.9 billion.

Higher 2023 operating expenses of $460 million were more than offset by the absence of a 2022 early contract termination at Sabine Pass of $600 million.

Net oil-equivalent production was up 168,000 barrels per day, or 14 percent, primarily due to the acquisition of PDC and growth in the Permian Basin.

upstream earnings increased by $3.5 billion primarily due to higher sales volumes of $2.2 billion, including from legacy PDC assets, and the absence of charges from decommissioning obligations for previously divested assets in the Gulf of America of $1.9 billion, partly offset by lower realizations of $790 million.

Net oil-equivalent production was up 250,000 barrels per day, or 19 percent, primarily due to full-year of legacy PDC production and growth in the Permian Basin.

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

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MBOED — thousands of barrels of oil-equivalent per day.

International upstream earnings decreased by $4.4 billion primarily due to lower realizations of $7.2 billion and lower sales volumes of $280 million, partially offset by lower depreciation expense of $1.4 billion mainly due to absence of write-off and impairment charges in 2022, lower operating expenses of $820 million and a favorable one-time tax benefit in Nigeria of $560 million.

Foreign currency effects had an unfavorable impact on earnings of $440 million between periods.

International upstream earnings decreased by $2.3 billion primarily due to lower realizations of $770 million, higher operating expenses of $580 million, lower sales volumes of $570 million and absence of favorable one-time tax benefit in Nigeria of $560 million.

Foreign currency effects had a favorable impact on earnings of $19 million between periods.

Net oil-equivalent production was down 32,000 barrels per day, or 2 percent.

The decrease was primarily due to normal field declines, shutdowns and lower production following expiration of the Erawan concession in Thailand.

The decrease was primarily due to downtime at TCO and Nigeria, and withdrawal from Myanmar, partly offset by entitlement effects.

2024 2023 2022

Earnings $MM $ 531 $ 3,904 $ 5,394

Refinery Crude Oil Inputs MBD 934 866 903

Refinery Crude Unit Inputs MBD 917 962 924

Refined Product Sales MBD 1,286 1,287 1,228

* MBD — thousands of barrels per day.

downstream earnings decreased by $1.5 billion primarily due to lower margins on refined product sales of $660 million, higher operating expenses of $490 million and lower earnings from the 50 percent-owned CPChem of $220 million.

Refinery crude oil input was up 68,000 barrels per day, or 8 percent, primarily due to a smaller impact from planned turnaround activity at the Richmond, California refinery and higher crude oil processed in place of other feedstocks at the Pascagoula, Mississippi refinery.

These increases were partially offset by planned turnaround impacts at the El Segundo, California refinery in first quarter 2023.

Refined product sales were up 59,000 barrels per day, or 5 percent, primarily due to higher jet fuel demand and higher renewable fuel sales following the REG acquisition.

downstream earnings decreased by $3.4 billion primarily due to lower margins on refined product sales of $2.6 billion and higher operating expenses of $810 million.

Refinery crude unit inputs were down 45,000 barrels per day, or 5 percent, primarily due to the upgrade of the Pasadena, Texas refinery that was completed during the fourth quarter 2024 and downtime at the Pascagoula, Mississippi refinery.

Refined product sales were down 1,000 barrels per day.

International Downstream

1 unchanged sentence

$MM $ 1,196 $ 2,233 $ 2,761

Refinery Crude Oil Inputs MBD 626 639 576

Refinery Crude Unit Inputs MBD 646 636 652

Refined Product Sales MBD 1,495 1,445 1,386

2 unchanged sentences

2 MBD — thousands of barrels per day.

International downstream earnings decreased by $528 million primarily due to higher operating expenses of $360 million and an unfavorable swing in foreign currency effects of $247 million between periods.

Refinery crude oil input was down 13,000 barrels per day, or 2 percent, compared to the year-ago period.

Refined product sales were up 59,000 barrels per day, or 4 percent, primarily due to higher demand for jet fuel and gasoline.

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

International downstream earnings decreased by $1.0 billion primarily due to lower margins on refined product sales of $880 million and impairments of $190 million.

Foreign currency effects had a favorable impact on earnings of $138 million between periods.

Refinery crude unit inputs were up 10,000 barrels per day, or 2 percent.

Refined product sales were up 50,000 barrels per day, or 3 percent, primarily due to increased trading volumes.

Unit 2024 2023 2022

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

Net charges decreased by $768 million primarily due to lower employee benefit costs and higher interest income, partially offset by an unfavorable swing of $206 million in foreign currency effects.

Net charges increased by $462 million primarily due to higher employee benefit costs, severance charges, lower interest income and higher interest expense, partially offset by a favorable swing of $587 million in foreign currency effects.

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

Consolidated Statement of Income

3 unchanged sentences

Sales and other operating revenues $ 193,414 $ 196,913 $ 235,717

Sales and other operat ing revenues decreased in 2023 mainly due to lower commodity prices, partially offset by higher refined product sales volumes.

Sales and other operat ing revenues decreased in 2024 mainly due to lower commodity prices, partially offset by higher crude oil, natural gas and refined product sales volumes.

Millions of dollars 2024 2023 2022

Income (loss) from equity affiliates $ 4,596 $ 5,131 $ 8,585

Income from equity affiliates decreased in 2023 mainly due to lower upstream-related earnings from Tengizchevroil in Kazakhstan and Angola LNG and lower downstream-related earnings from GS Caltex in Korea and CPChem.

Income from equity affiliates decreased in 2024 mainly due to lower downstream-related earnings from GS Caltex in South Korea and lower upstream-related earnings from Tengizchevroil in Kazakhstan, partially offset by an absence of certain U.S.

upstream equity affiliate impairments and higher downstream-related earnings from Chevron Phillips Chemical Company LLC (CPChem).

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

1 unchanged sentence

Other income (loss) $ 4,782 $ (1,095) $ 1,950

Other income decreased in 2023 mainly due to charges related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S.

Gulf of Mexico, an unfavorable swing in foreign currency effects and lower gains on asset sales, partially offset by income from Venezuela non-equity investments and higher interest income.

Other income increased in 2024 mainly due to the absence of charges related to decommissioning obligations from previously divested oil and gas production assets in the Gulf of America, before tax gains on asset sales in Canada, a favorable swing in foreign currency effects and higher dividend income.

Millions of dollars 2024 2023 2022

Purchased crude oil and products $ 119,206 $ 119,196 $ 145,416

Crude oil and product purchases decreased in 2023 primarily due to lower commodity prices.

Crude oil and product purchases remained fairly flat in 2024 as lower crude and refined product prices were partially offset by higher crude oil and refined product volumes.

Millions of dollars 2024 2023 2022

Operating, selling, general and administrative expenses $ 32,298 $ 29,028 $ 29,026

Operating, selling, general and administrative expenses were relatively unchanged compared to last year.

Higher transportation and materials and supplies expenses were offset by lower employee benefit costs and the absence of early contract termination fees at Sabine Pass in 2022.

Operating, selling, general and administrative expenses increased compared to last year mainly due to higher employee-related expenses as a result of higher severance and employee benefit costs and higher downstream-related shutdown expenses.

Millions of dollars 2024 2023 2022

Exploration expense $ 995 $ 914 $ 974

Exploration expenses in 2023 decreased primarily due to lower charges for well write-offs.

Exploration expenses in 2024 were higher primarily due to higher geological and geophysical engineering costs.

Millions of dollars 2024 2023 2022

Depreciation, depletion and amortization $ 17,282 $ 17,326 $ 16,319

Depreciation, depletion and amortization expenses increased in 2023 primarily due to higher impairment charges and higher production, partially offset by lower rates.

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

Depreciation, depletion and amortization expenses decreased slightly in 2024 primarily due to lower impairment charges partially offset by higher production and higher rates.

Millions of dollars 2024 2023 2022

Taxes other than on income $ 4,716 $ 4,220 $ 4,032

Taxes other than on income increased in 2023 primarily due to higher excise taxes.

Taxes other than on income increased in 2024 primarily due to higher excise and property taxes.

Millions of dollars 2024 2023 2022

Interest and debt expense $ 594 $ 469 $ 516

Interest and debt expenses decreased in 2023 mainly due to higher capitalized interest and lower debt balances.

Interest and debt expenses increased in 2024 mainly due to higher debt balances.

Millions of dollars 2024 2023 2022

Other components of net periodic benefit costs $ 195 $ 212 $ 295

Other components of net periodic benefit costs decreased in 2023 primarily due to lower pension settlement costs as fewer lump-sum pension distributions were made in the current year, partially offset by the impact of higher interest rates.

Other components of net periodic benefit costs decreased in 2024 primarily due to lower pension settlement costs.

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

Millions of dollars 2024 2023 2022

Income tax expense (benefit) $ 9,757 $ 8,173 $ 14,066

The decrease in income tax expense in 2023 of $5.9 billion is due to the decrease in total income before tax for the company of $20.1 billion.

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

The increase in income tax expense in 2024 of $1.6 billion was primarily due to the tax impacts of the asset sales in Canada, partially offset by the decrease in total income before tax for the company of $2.1 billion.

The decrease in income before taxes for the company was primarily the result of lower downstream margins, lower upstream realizations, higher operating expenses, in part due to severance charges, partially offset by the absence of charges from decommissioning obligations for previously divested assets, higher sales volumes and favorable foreign exchange impacts.

income before tax decreased from $8.6 billion in 2023 to $8.1 billion in 2024.

This $12.4 billion decrease in income was primarily driven by lower upstream realizations and downstream margins, charges related to abandonment and decommissioning obligations, and higher impairment charges, partially offset by higher sales volumes.

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

income tax resulting in a decrease to tax expense of $2.7 billion between year-over-year periods, from $4.5 billion in 2022 to $1.8 billion in 2023.

This $0.5 billion decrease in income was primarily driven by lower downstream margins, higher operating expenses, in part due to severance charges, and lower upstream realizations, partially offset by the absence of charges related to decommissioning obligations for previously divested assets and higher sales volumes.

The increase of $0.1 billion in U.S.

income tax expense between year-over-year periods, from $1.8 billion in 2023 to $1.9 billion in 2024, was primarily driven by current period unfavorable tax items.

International income before tax decreased from $21.0 billion in 2023 to $19.5 billion in 2024.

This $7.7 billion decrease in income was primarily driven by lower upstream realizations, partly offset by the absence of a 2022 write-off and impairment charges.

The decrease in income primarily drove the $3.2 billion decrease in international income tax expense between year-over-year periods, from $9.6 billion in 2022 to $6.4 billion in 2023.

This $1.6 billion decrease in income was primarily driven by lower downstream margins, lower upstream realizations, higher operating expenses and lower sales volumes, partially offset by favorable foreign exchange impacts.

The increase of $1.5 billion in international income tax expense between year-over-year periods, from $6.4 billion in 2023 to $7.9 billion in 2024, was primarily driven by the tax impacts of the asset sales in Canada, partially offset by the decrease in income before tax.

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

8 unchanged sentences

MMCFD 5,172 4,637 4,354

Sales of NGLs MBD 354 276 201

Sales of Natural Gas Liquids MBD 490 354 276

Revenues from Net Production

11 unchanged sentences

Sales of Natural Gas MMCFD 5,678 6,025 5,786

Sales of NGLs MBD 94 107 84

Sales of Natural Gas Liquids MBD 132 94 107

Revenues from Liftings

14 unchanged sentences

MMCFD 28 32 24

Sales of NGLs MBD 22 27 29

Refinery Crude Oil Input MBD 934 866 903

Sales of Natural Gas Liquids MBD 21 22 27

Refinery Crude Unit Inputs 8

MBD 917 962 924

International Downstream

5 unchanged sentences

Sales of Natural Gas 4

Sales of NGLs MBD 153 127 96

Refinery Crude Oil Input MBD 626 639 576

Sales of Natural Gas Liquids MBD 136 153 127

Refinery Crude Unit Inputs 8

MBD 646 636 652

1 Includes company share of equity affiliates.

15 unchanged sentences

MBD 386 389 389

8 Includes crude oil and other inputs.

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

3 unchanged sentences

The company holds its cash with a diverse group of major financial institutions and has processes and safeguards in place designed to manage its cash balances and mitigate the risk of loss.

Cash provided by operating activities in 2023 was $35.6 billion, compared to $49.6 billion in 2022, primarily due to lower upstream realizations and refining margins.

Cash provided by operating activities was net of contributions to employee pension plans of approximately $1.1 billion in 2023 and $1.3 billion in 2022.

Cash provided by operating activities in 2024 was $31.5 billion, compared to $35.6 billion in 2023, primarily due to lower earnings and higher payments related to asset retirement obligations.

Cash provided by operating activities was net of contributions to employee pension plans of approximately $844 million in 2024 and $1.1 billion in 2023.

Capital expenditures totaled $16.4 billion in 2024 compared to $15.8 billion in 2023.

Proceeds and deposits related to asset sales and return of investments totaled $669 million in 2023 compared to $2.6 billion in 2022 .

Cash flow from financing activities includes proceeds from shares issued for stock options of $261 million in 2023, compared with a higher than typical $5.8 billion in 2022 when a large number of stock options were exercised.

Proceeds and deposits related to asset sales and return of investments totaled $7.7 billion in 2024 compared to $669 million in 2023 primarily related to proceeds from asset sales in Canada.

Cash flow from financing activities includes proceeds from shares issued for stock options of $330 million in 2024, compared with $261 million in 2023.

Restricted cash of $1.5 billion and $1.1 billion at December 31, 2024 and 2023, 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.

These amounts are generally associated with upstream decommissioning activities, tax payments and funds held in escrow for tax-deferred exchanges.

The increase of restricted cash in 2024 is mainly due to increase in funds for tax-deferred exchanges.

Dividends Dividends paid to common stockholders were $11.8 billion in 2024 and $11.3 billion in 2023.

Debt and Finance Lease Liabilities Total debt and finance lease liabilities were $20.8 billion at December 31, 2023, down from $23.3 billion at year-end 2022.

The $2.5 billion decrease in total debt and finance lease liabilities during 2023 was primarily due to the repayment of long-term notes that matured during the year.

Debt and Finance Lease Liabilities Total debt and finance lease liabilities were $24.5 billion at December 31, 2024, up from $20.8 billion at year-end 2023 as the company issued commercial paper and tax-exempt bonds and retired public bonds.

The $3.7 billion increase in total debt and finance lease liabilities during 2024 was primarily due to the issuance of commercial paper.

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 $12.7 billion at December 31, 2024, compared with $5.1 billion at year-end 2023.

Of these amounts, $4.5 billion and $4.1 billion were reclassified to long-term debt at the end of 2023 and 2022, respectively.

At year-end 2023, settlement of these obligations was not expected to require the use of working capital in 2024, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

During third quarter 2023, the company assumed $1.5 billion of debt in conjunction with the PDC acquisition, including balances outstanding under the revolving credit facility, PDC’s 6.125% notes due 2024 (2024 notes) and PDC’s 5.75% notes due 2026 (2026 notes).

The outstanding balances under the revolving credit facility and the 2024 notes were repaid during third quarter 2023.

The company also irrevocably deposited sufficient U.S.

Treasury securities with U.S.

Bank Trust Company, N.A., as trustee, to fund the redemption of the 2026 notes, resulting in the indenture being satisfied and discharged.

Of these amounts, $8.3 billion and $4.5 billion were reclassified to long-term debt at the end of 2024 and 2023, respectively, since settlement of these obligations was not expected to require the use of working capital within one year, as the company had the intent and the ability, as evidenced by committed credit facilities, to continue refinancing them.

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, 2023.

The company had $5.4 billion of commercial paper outstanding as of December 31, 2024, and there was no commercial paper outstanding at December 31, 2023.

The company has an automatic shelf registration statement that expires in November 2027 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

Cash from operating activities compared with capital expenditures and cash returned to shareholders

Billions of dollars

Stock repurchases

Capital expenditures

Cash from operating activities

Capital expenditures by segment

Billions of dollars

Affiliate capital expenditure

Billions of dollars

Debt at year-end

Billions of dollars

*Refer to pages 52-53 for calculations of debt ratio and net debt ratio

Net debt ratio*

*Refer to pages 52-53 for calculations of debt ratio and net debt ratio

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, Chevron U.S.A.

(CUSA), Noble Energy, Inc.

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

(Noble), and Texaco Capital Inc.

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All of these ratings denote high-quality, investment-grade securities.

The company’s future debt level is dependent primarily on results of operations, cash that may be generated from asset dispositions, the capital program, lending commitments to affiliates and shareholder distributions.

The company’s future debt level is dependent primarily on results of operations, cash that may be generated from asset dispositions, the capital program, acquisitions, investments, lending commitments to affiliates and cash returned to shareholders.

Based on its high-quality debt ratings, the company believes that it has substantial borrowing capacity to meet unanticipated cash requirements.

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Financial information for non-guarantor entities has been excluded.

Year Ended December 31, 2023 Year Ended December 31, 2022

In the year ended December 31, 2024, the Obligor Group recognized an increase in “Net income (loss)” and reduction in “Current liability - related party” and “Total net equity (deficit)” following the resolution of outstanding balances with subsidiaries outside of the Obligor Group.

At December 31,

(Millions of dollars) (unaudited)

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At December 31,

2023 At December 31,

(Millions of dollars) (unaudited)

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Total net equity (deficit) $ 186 $ (89,896)

Common Stock Repurchase Program In first quarter 2023, the company purchased a total of 22.4 million shares for $3.7 billion under the February 2019 stock repurchase program.

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 “2023 Program”).

Common Stock Repurchase Program 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 “2023 Program”).

The 2023 Program took effect on April 1, 2023, and does not have a fixed expiration date.

As of December 31, 2023, the company had purchased a total of 70.4 million shares for $11.2 billion, resulting in $63.8 billion remaining under the 2023 Program.

In aggregate, the company purchased 92.8 million shares for $14.9 billion in 2023.

In connection with the pending transaction with Hess, share repurchases have been restricted pursuant to SEC regulations since the acquisition announcement and will be restricted until the date of the Hess stockholder vote.

Chevron expects share repurchases in the first quarter of 2024 to be around $3 billion plus or minus 20 percent, depending primarily on the timing of the Hess definitive proxy statement mailing.

During 2024, the company purchased a total of 100.4 million shares for $15.2 billion and paid an additional $145 million in excise taxes related to 2023 buybacks.

As of December 31, 2024, the company had purchased a total of 170.9 million shares for $26.4 billion excluding excise taxes, resulting in $48.6 billion remaining under the 2023 Program.

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.

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Capex $ 11,330 $ 5,118 $ 16,448 $ 11,729 $ 4,100 $ 15,829 $ 8,856 $ 3,118 $ 11,974

Capex for 2023 was $15.8 billion, 32 percent higher than 2022 due to higher investments in the United States, including about $450 million invested in PDC assets post-acquisition and approximately $650 million of inorganic spend, mainly due to the acquisition of a majority stake in ACES Delta, LLC.

Capex excludes the acquisition cost of PDC.

The company estimates that 2024 Capex will be approximately $16 billion.

In the upstream business, Capex is estimated to be $14 billion, two-thirds of which is expected to be in the U.S., and includes around $5 billion for Permian Basin development and roughly $1.5 billion for other shale & tight assets in the U.S.

About 25 percent of U.S upstream Capex is planned for projects in the Gulf of Mexico.

Worldwide downstream spending in 2024 is estimated to be $1.5 billion with 80 percent allocated in the U.S.

In addition, investments in technology businesses and other corporate operations in 2024 are projected to be about $0.5 billion.

Lower carbon Capex included in the upstream and downstream segments totals around $2 billion, including investments to lower the carbon intensity of Chevron’s traditional operations and grow new energy business lines.

Capex for 2024 was $16.4 billion, 4 percent higher than 2023 due to higher investments in the upstream.

The company estimates that 2025 Capex will range from $14.5 to $15.5 billion.

Upstream Capex is projected at $13 billion, with two-thirds in the United States.

This includes $4.5 to $5 billion for Permian Basin development, with the remaining split between the DJ Basin and the Gulf of America.

In international Upstream, about $1 billion is allocated to Australia.

Downstream Capex is estimated at $1.2 billion, with two-thirds in the United States.

About $1.5 billion of total Capex, which is included within upstream and downstream budgets, is dedicated to lowering the carbon intensity of our operations and growing new energies businesses.

Corporate and other Capex is projected to be about $0.7 billion.

Affiliate Capital Expenditures Equity affiliate capital expenditures (Affiliate Capex) primarily includes additions to fixed asset and investment accounts in the equity affiliate companies’ financial statements and does not require cash outlays by the company.

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Affiliate Capex $ 802 $ 1,647 $ 2,449 $ 983 $ 2,551 $ 3,534 $ 768 $ 2,598 $ 3,366

Affiliate Capex for 2023 was $3.5 billion, 5 percent higher than 2022 due to higher spend at CPChem’s two major integrated polymer projects.

Affiliate Capex is expected to be $3 billion in 2024.

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

Affiliate Capex for 2024 was $2.4 billion, 31 percent lower than 2023 mainly due to lower spend at Tengizchevroil’s Wellhead Pressure Management Project (WPMP) and Future Growth Project (FGP).

Affiliate Capex is expected to range between $1.7 to $2.0 billion in 2025.

Less than half of Affiliate Capex is for Tengizchevroil, while the remaining spend primarily supports CPChem’s two major integrated polymer projects.

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

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Distributions to noncontrolling interests net of contributions totaled $195 million and $40 million in 2024 and 2023, respectively.

Included within noncontrolling interests at December 31, 2023 is $166 million of redeemable noncontrolling interest.

Pension Obligations Information related to pension plan contributions is included in Note 23 Employee Benefit Plans , under the heading “Cash Contributions and Benefit Payments.”

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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.

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

At December 31

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Cash and cash equivalents 6,781 8,178 17,678

Time deposits 4 — —

Marketable securities — 45 223

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Litigation and Other Contingencies

Ecuador Information related to Ecuador matters is included in Note 16 Litigation under the heading “Ecuador.”

Climate Change Information related to climate change-related matters is included in Note 16 Litigation under the heading “Climate Change.”

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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

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

environmental issues.

These asset retirement obligations include costs related to environmental issues.

The liability balance of approximately $12.7 billion for asset retirement obligations at year-end 2024 is related primarily to upstream properties.

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

For the company’s other ongoing operating assets, such as refineries and chemicals facilities, no provisions are made for exit or cleanup costs that may be required when such assets reach the end of their useful lives unless a decision to sell or otherwise decommission the facility has been made, as the indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the asset retirement obligation.

The company records decommissioning obligations for previously divested assets when it is probable that the decommissioning obligations would revert to the Company and costs can be reasonably estimated.

At the end of 2024, the liability balance was $2.5 billion.

Refer to Note 24 Other Contingencies and Commitments for additional discussion of decommissioning obligations for previously divested assets.

Refer to the discussion below for additional information on environmental matters and their impact on Chevron, and on the company’s 2024 environmental expenditures.

Refer to Note 24 Other Contingencies and Commitments for additional discussion of environmental remediation provisions and year-end reserves, and for abandonment and decommissioning obligations for previously sold assets.

Refer to Note 24 Other Contingencies and Commitments for additional discussion of environmental remediation provisions.

Refer also to Note 25 Asset Retirement Obligations for additional discussion of the company’s asset retirement obligations.

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

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

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

In addition, legislation and regulations intended to address hydraulic fracturing also continue to evolve in many jurisdictions where we operate.

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Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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.

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

The estimates of crude oil, NGLs 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.

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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.

Also, if the expectation of sale of a particular asset or asset group in any period has been deemed more likely than not, an impairment review is performed, and if the estimated net proceeds exceed the carrying value of the asset or asset group, no impairment charge is required.

Also, if the expectation of sale of a particular asset or asset group in any period has been deemed more likely than not, an impairment review is performed, and if the estimated future undiscounted cash flows exceed the carrying value of the asset or asset group, no impairment charge is required.

Such calculations are reviewed each period until the asset or asset group is disposed.

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Refer to Note 25 Asset Retirement Obligations for additional discussions on asset retirement obligations.

Pension and Other Postretirement Benefit Plans Note 23 Employee Benefit Plans includes information on the funded status of the company’s pension and other postretirement benefit (OPEB) plans reflected on the Consolidated Balance Sheet;

Pension and Other Post-Employment Benefit Plans Note 23 Employee Benefit Plans includes information on the funded status of the company’s pension and other post-employment benefit (OPEB) plans reflected on the Consolidated Balance Sheet;

the components of pension and OPEB expense reflected on the Consolidated Statement of Income;

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For the 10 years ended December 31, 2024, actual asset returns averaged 4.9 percent for this plan.

Additionally, with the exception of three years within this 10-year period, actual asset returns for this plan equaled or exceeded 7.0 percent during each year.

Additionally, with the exception of four years within this 10-year period, actual asset returns for this plan equaled or exceeded 7.0 percent during each year.

Total pension expense for 2024 was $551 million.

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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 65 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $279 million, and would have changed the plan’s funded status from a deficit of $80 million to a surplus of $199 million.

pension plan, which accounted for about 66 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $261 million, and would have increased the plan’s surplus from $573 million to $834 million.

For the company’s OPEB plans, expense for 2024 was $91 million, and the total liability, all unfunded at the end of 2024, was $1.9 billion.

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In addition, information related to company contributions is included on page 98 in Note 23 Employee Benefit Plans under the heading “Cash Contributions and Benefit Payments.”

Business Combinations — Purchase-Price Allocation Accounting for business combinations requires the allocation of the company’s purchase price to the various assets and liabilities of the acquired business at their respective fair values.

The company uses all available information to make these fair value determinations.

Determining the fair value of assets acquired generally involves assumptions regarding the amounts and timing of future revenues and expenditures, as well as discount rates.

For additional discussion of purchase price allocations, refer to Note 29 Acquisition of PDC Energy, Inc.

Contingent Losses Management also makes judgments and estimates in recording liabilities for claims, litigation, tax matters, transferred liabilities from previously sold assets, and environmental remediation.

Contingent Losses Management also makes judgments and estimates in recording liabilities for claims, litigation, tax matters, transferred liabilities from previously divested assets, and environmental remediation.

Actual costs can frequently vary from estimates for a variety of reasons.

For example, the costs for settlement of claims and litigation can vary from estimates based on differing interpretations of laws, opinions on culpability and assessments on the amount of damages.

The costs for decommissioning obligations for previously divested assets can also vary from estimates.

Recording of liabilities for such costs typically requires judgment to assess the likelihood of decommissioning obligations reverting to the company, the timing of decommissioning activity, regulatory requirements and the scope of decommissioning activities.

Similarly, liabilities for environmental remediation are subject to change because of changes in laws, regulations and their interpretation, the determination of additional information on the extent and nature of site contamination, and improvements in technology.

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The company generally reports these losses as “Operating expenses,” “Selling, general and administrative expenses” or “Other income (loss)” on the Consolidated Statement of Income.

An exception to this handling is for income tax matters, for which benefits are recognized only if management determines the tax position is

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.”

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

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, 2023.

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, 2024.

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.

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Based on the results of this evaluation, the company’s management concluded that internal control over financial reporting was effective as of December 31, 2024.

The company excluded PDC Energy, Inc.

(PDC) from our assessment of internal control over financial reporting as of December 31, 2023 because it was acquired by the company in a business combination during 2023.

Total assets and total revenue of PDC, a wholly-owned subsidiary, represent five percent and one percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2023.

/s/ MICHAEL K.

WIRTH /s/ PIERRE R.

BREBER /s/ ALANA K.

Wirth Pierre R.

Breber Alana K.

WIRTH /s/ EIMEAR P.

BONNER /s/ ALANA K.

Wirth Eimear P.

Bonner Alana K.

Chairman of the Board Vice President Vice President

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We believe that our audits provide a reasonable basis for our opinions.

As described in Management’s Report on Internal Control over Financial Reporting, management has excluded PDC Energy, Inc.

(PDC) from its assessment of internal control over financial reporting as of December 31, 2023 because it was acquired by the Company in a business combination during 2023.

We have also excluded PDC from our audit of internal control over financial reporting.

PDC is a wholly-owned subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent five percent and one percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2023.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the

Financial Table of Contents

transactions and dispositions of the assets of the company;

(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company;

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

Financial Table of Contents

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

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Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of-production method by individual field as the related proved reserves are produced.

As disclosed by management, variables impacting the Company’s estimated volumes of proved crude oil and natural gas reserves include field performance, available technology, commodity prices, and development, production and carbon costs.

As disclosed by management, variables impacting the Company’s estimated volumes of proved crude oil, natural gas liquids (NGLs) and natural gas reserves include field performance, available technology, commodity prices, and development, production and carbon costs.

Reserves are estimated by Company asset teams composed of earth scientists and engineers.

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Cash and cash equivalents $ 6,781 $ 8,178

Time deposits 4 —

Marketable securities — 45

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Proceeds and deposits related to asset sales and returns of investment 7,704 669 2,635

Net maturities of (investments in) time deposits ( 4 ) — —

Net sales (purchases) of marketable securities 45 175 117

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Consolidated Statement of Equity Financial Table of Contents

Amounts in millions of dollars

Millions of dollars, except per-share amounts

Other Treasury Chevron Corp.

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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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Treasury stock transactions 174 — — — 174 — 174

PDC Energy, Inc.

acquisition 2,550 — — 3,970 6,520 — 6,520

Net income (loss) — 21,369 — — 21,369 42 21,411

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Treasury stock transactions 255 — — — 255 — 255

PDC Energy, Inc.

acquisition 2,550 — — 3,970 6,520 — 6,520

Net income (loss) — 17,661 — — 17,661 88 17,749

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The company uses its incremental borrowing rate as a proxy for the discount rate based on the term of the lease unless the implicit rate is available.

Decommissioning Obligations from Previously Divested Assets Some assets are divested with their related liabilities, including decommissioning obligations, to a buyer that results in de-recognition of the liability from the balance sheet.

In certain instances, such transferred obligations may return to the company and result in losses.

To the extent the current owners of the company’s previously divested assets default on their decommissioning obligations, regulators may require that Chevron assume such obligations.

The company would accrue losses associated with these obligations when management determines the loss to be both probable and reasonably estimable.

This typically requires judgment to assess the likelihood of decommissioning obligations reverting to the company, the timing of decommissioning activity, regulatory requirements and the scope of decommissioning activities.

For more information on decommissioning obligations related to previously divested assets, refer to Note 24 Other Contingencies and Commitments .

Goodwill Goodwill resulting from a business combination is not subject to amortization.

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Refer to Note 25 Asset Retirement Obligations for a discussion of the company’s AROs.

For abandonment and decommissioning obligations related to previously sold assets, refer to Note 24 Other Contingencies and Commitment s .

federal Superfund sites and analogous sites under state laws, the company records a liability for its designated share of the probable and estimable costs, and probable amounts for other potentially responsible parties when mandated by the regulatory agencies because the other parties are not able to pay their respective shares.

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For equity awards, such as stock options and certain restricted stock units, total compensation cost is based on the grant date fair value, and for liability awards, such as stock appreciation rights, total compensation cost is based on the settlement value.

The company recognizes stock-based compensation expense for all awards over the service period required to earn the award, which is the shorter of the vesting period or the time period in which an employee becomes eligible to retain the award at retirement.

The company’s Long-Term Incentive Plan (LTIP) awards include stock options and stock appreciation rights, which have graded vesting provisions by which one-third of each award vests on each of the first, second and third anniversaries of the date of grant.

In addition, performance shares granted under the company’s LTIP will vest at the end of the three-year performance period.

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 company recognizes stock-based compensation expense for all awards over the service period required to earn the award, which is the shorter of the vesting period or the time period in

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

the fifth anniversary of the grant date, subject to adjustment upon termination pursuant to the satisfaction of certain criteria.

Commencing for grants issued in January 2023 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.

which an employee becomes eligible to retain the award at retirement.

For more information on stock options and other share-based compensation, refer to Note 22 Stock Options and Other Share-Based Compensation .

Changes in Accumulated Other Comprehensive Losses

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Net Other Comprehensive Income (Loss) 11 1 17 ( 191 ) ( 162 )

( 41 ) ( 1 ) ( 12 ) 1,145 1,091

Balance at December 31, 2023 $ ( 192 ) $ ( 11 ) $ 5 $ ( 2,762 ) $ ( 2,960 )

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Proceeds and deposits related to asset sales and returns of investment $ 7,704 $ 669 $ 2,635

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

Investments in time deposits $ ( 6 ) $ — $ —

Maturities of time deposits 2 — —

Net maturities of (investments in) time deposits $ ( 4 ) $ — $ —

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

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Shares purchased under share repurchase and deferred compensation plans ( 15,229 ) ( 14,939 ) ( 11,255 )

Share repurchase excise tax payments ( 145 ) — —

Net sales (purchases) of treasury shares $ ( 15,044 ) $ ( 14,678 ) $ ( 5,417 )

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Net contributions from (distributions to) noncontrolling interests $ ( 195 ) $ ( 40 ) $ ( 114 )

The “Other” line in the Operating Activities section includes changes in postretirement benefits obligations and other long-term liabilities.

The “Other” line in the Operating Activities section includes changes in asset retirement obligations, decommissioning obligations associated with previously divested assets, post-employment benefit obligations and other long-term liabilities.

Refer also to Note 25 Asset Retirement Obligations for a discussion of the company’s AROs activity, including revisions that did not involve cash receipts or payments .

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

“Depreciation, depletion and amortization” and “Deferred income tax provision” collectively include approximately $ 1,765 in non-cash reductions to “Properties, plant and equipment” and “Investments and advances” in 2023 relating to impairments, mainly of upstream assets in California.

“Other income (loss)” and “Deferred income tax provision” collectively include a $ 1,950 charge related to non-cash increases to “Deferred credits and other noncurrent obligations” related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S.

Gulf of Mexico.

The cash outlays for these abandonment and decommissioning obligations are expected to take place over the next decade.

“Depreciation, depletion and amortization” and “Deferred income tax provision” collectively include approximately $ 400

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

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, 2023.

in non-cash reductions to “Properties, plant and equipment” and “Investments and advances” in 2024 relating to impairments.

“Operating expenses” and “Deferred income tax provision” include an approximately $ 715 severance charge related to non-cash increases to “Net decrease (increase) in operating working capital” and “Other” associated with employee severance.

The cash outlay for severance payments is expected to take place through 2026.

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

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Restricted cash included in “Deferred charges and other assets”

1,200 822 813

Total cash, cash equivalents and restricted cash

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New Accounting Standards

Segment Reporting (Topic 280) Improvements to Reportable Segment Disclosures In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) 2023-07, which becomes effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024.

Segment Reporting (Topic 280) Improvements to Reportable Segment Disclosures The company has adopted the Financial Accounting Standards Board (FASB) Accounting Standard Update (ASU) 2023-07 which is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024.

The standard requires companies to disclose significant segment expenses.

The company does not expect the standard to have a material effect on its consolidated financial statements and has begun evaluating disclosure presentation alternatives.

The adoption of this ASU did not have an impact on the company’s consolidated financial position or results of operations.

For additional information, refer to Note 14 Operating Segments and Geographic Data .

Income Taxes (Topic 740) Improvements to Income Tax Disclosures In December 2023, the FASB issued ASU 2023-09, which becomes effective for fiscal years beginning after December 15, 2024.

The standard requires companies to disclose specific categories in the income tax rate reconciliation table and the amount of income taxes paid per major jurisdiction.

The company does not expect the standard to have a material effect on its consolidated financial statements and continues to evaluate disclosure presentation alternatives.

Income Statement (Topic 220) Reporting Comprehensive Income - Expense Disaggregation Disclosures In November 2024, the FASB issued ASU 2024-03, which becomes effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027.

The standard requires companies to disclose disaggregated information about certain income statement expense line items.

The company does not expect the standard to have a material effect on its consolidated financial statements and has begun evaluating disclosure presentation alternatives.

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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

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Millions of dollars, except per-share amounts

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

At December 31, 2024 At December 31, 2023

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Additionally, the company has $ 403 in future undiscounted cash flows for operating leases not yet commenced.

These leases are primarily for drill ships, drilling rigs and storage tanks.

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.

These leases are primarily for drilling rigs, time chartered vessels, exploration and production equipment and storage tanks.

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

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

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 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.

Assets include those related to the exploration and production of crude oil, natural gas, and natural gas liquids (NGLs) 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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Total TCO net equity $ 47,148 $ 46,219

Summarized Financial Data – Chevron Phillips Chemical Company LLC

Chevron has a 50 percent equity ownership interest in Chevron Phillips Chemical Company LLC (CPChem).

Refer to Note 15 Investments and Advances for a discussion of CPChem operations.

Summarized financial information for 100 percent of CPChem is presented in the table below:

Year ended December 31

2023 2022 2021

Sales and other operating revenues $ 11,560 $ 14,180 $ 14,104

Costs and other deductions 10,561 12,870 10,862

Net income attributable to CPChem 1,173 1,662 3,684

Restructuring and Reorganization Costs

In 2024, the company announced plans to achieve $ 2 - 3 billion in structural cost reductions by the end of 2026.

As a result, the company recorded severance accruals during fourth quarter 2024 for employee reduction programs related to an enterprise-wide restructuring, which is expected to be substantially completed by the end of 2026.

A charge of $ 980 was recorded in fourth quarter 2024, with $ 706 reported as “ Operating expenses ” and $ 274 reported as “Selling, general and administrative expenses” on the Consolidated Statement of Income.

Approximately $ 240 is associated with employee reductions in U.S.

Upstream, $ 197 in International Upstream, $ 247 in U.S.

Downstream, $ 22 in International Downstream and $ 274 in All Other.

Approximately $ 560 is classified as current and $ 430 is classified as long-term on the Consolidated Balance Sheet at December 31, 2024.

Notes to the Consolidated Financial Statements

1 unchanged sentence

Millions of dollars, except per-share amounts

At December 31

Current assets $ 3,284 $ 3,472

Other assets 16,425 15,184

Current liabilities 1,757 2,146

Other liabilities 3,269 2,941

Total CPChem net equity $ 14,683 $ 13,569

The following table summarizes the accrued severance liability.

Amounts Before Tax

Balance at January 1, 2024 $ 6

Accruals/Adjustments 987

Payments ( 3 )

Balance at December 31, 2024 $ 990

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, 2023 and 2022.

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

1 unchanged sentence

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.

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

The company designates certain derivative instruments as cash flow hedges, if applicable.

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.

3 unchanged sentences

The company does not materially adjust this information.

Properties, Plant and Equipment In 2023, the company impaired a portion of its U.S.

Properties, Plant and Equipment In 2024, the company did not have any individually material impairments of long lived assets measured at fair value on a nonrecurring basis.

In 2023, the company impaired a portion of its U.S.

upstream assets, primarily in California, due to continuing regulatory challenges in the state that have resulted in lower anticipated future investment levels in its business plans.

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.

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 2024 or 2023.

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, 2024 and 2023.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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Total nonrecurring assets at fair value $ 976 $ — $ 652 $ 324 $ 789 $ 691 $ 5 $ 165 $ 521 $ 2,532

At year-end 2023, the company had assets measured at fair value Level 3 using unobservable inputs of $ 521 .

The carrying value of these assets were written down to fair value based on estimates derived from discounted cash flow models.

Notes to the Consolidated Financial Statements

1 unchanged sentence

Millions of dollars, except per-share amounts

flows were determined using estimates of future production, an outlook of future price based on published prices and a discount rate believed to be consistent with those used by principal market participants.

At year-end 2024, the company had assets measured at fair value Level 3 using unobservable inputs of $ 324 .

The carrying value of these assets were written down to fair value based on estimates derived from discounted cash flow models.

Cash flows were determined using estimates of future production, an outlook of future price based on published prices and a discount rate believed to be consistent with those used by principal market participants.

Assets and Liabilities Not Required to Be Measured at Fair Value The company holds cash equivalents in U.S.

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“Cash and cash equivalents” do not include investments with a carrying/fair value of $ 1,481 and $ 1,097 at December 31, 2024, and December 31, 2023, respectively.

At December 31, 2023, these investments are classified as Level 1 and include restricted funds related to certain upstream decommissioning activities, a financing program and tax payments.

At December 31, 2024, these investments are classified as Level 1 and include restricted funds mainly related to certain upstream decommissioning activities, a tax-deferred transaction and financing programs.

Long-term debt, excluding finance lease liabilities, of $ 10,810 and $ 14,612 at December 31, 2024, and December 31, 2023, respectively, had estimated fair values of $ 9,791 and $ 13,709 , respectively.

Long-term debt primarily includes corporate issued bonds.

The fair value of corporate bonds is $ 13,321 and classified as Level 1.

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

At December 31, 2024, the fair value of corporate bonds is $ 9,243 and classified as Level 1 and the fair value of other long-term debt classified as Level 2 is $ 548 .

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

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Total liabilities at fair value $ 153 $ 262

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

Consolidated Statement of Income:

The Effect of Derivatives

Type of Derivative Statement of Year ended December 31

Contract Income Classification 2023 2022 2021

Year ended December 31

Type of Contract Statement of Income Classification 2024 2023 2022

Commodity Sales and other operating revenues $ ( 57 ) $ ( 304 ) $ ( 651 )

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$ ( 23 ) $ ( 505 ) $ ( 867 )

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

The amount reclassified from AOCL to “Sales and other operating revenues” from designated hedges was a decrease of $ 33 in 2023, compared with an increase of $ 80 in the prior year.

At December 31, 2023, before-tax deferred gains in AOCL related to outstanding crude oil price hedging contracts were $ 7 , 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 amount reclassified from AOCL to “Sales and other operating revenues” from designated hedges was a net loss of $ 25 in 2024, compared with a net loss of $ 33 in the prior year.

At December 31, 2024, before-tax deferred losses in AOCL related to outstanding crude oil price hedging contracts were $ 17 , 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, 2024 and 2023.

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At December 31, 2024, the company classifie d $ 481 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.

These assets are associated with upstream and downstream operations that were sold in early 2025, or are anticipated to be sold in the next 12 months.

The revenues and earnings contributions of these assets in 2024 were not material.

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In addition, 559,513 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

Financial Table of Contents

Millions of dollars, except per-share amounts

Earnings Per Share

2 unchanged sentences

The table below sets forth the computation of basic and diluted EPS:

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

Year ended December 31

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The investments are grouped into two business segments, Upstream and Downstream, representing the company’s “reportable segments” and “operating segments.” Upstream operations consist primarily of exploring for, developing, producing and transporting crude oil and natural gas;

liquefaction, transportation and regasification associated with liquefied natural gas (LNG);

liquefaction, transportation and regasification associated with LNG;

transporting crude oil by major international oil export pipelines;

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

The company’s segments are managed by “segment managers” who report to the “chief operating decision maker” (CODM).

The segments represent components of the company that engage in activities (a) from which revenues are earned and expenses are incurred;

(b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the segments and assesses their performance;

and (c) for which discrete financial information is available.

The company’s primary country of operation is the United States of America, its country of domicile.

Other components of the company’s operations are reported as “International” (outside the United States).

The company’s segments are managed by “segment managers” who report to the “chief operating decision maker” (CODM), which is comprised of the company’s Executive Committee, as referenced in Item 10 Executive Officers .

The segments represent components of the company that engage in activities from which revenues are earned and expenses are incurred.

Each segment has discrete financial information available.

The CODM regularly reviews the operating results of these segments to assess their performance and make decisions about resources to be allocated to the segments.

The company's primary country of operation is the United States of America, its country of domicile, while other components of the company's operations are reported as “International” (outside the United States).

Segment Sales and Other Operating Revenues Products are transferred between operating segments at internal product values that approximate market prices.

Revenues for the upstream segment are derived primarily from the production and sale of crude oil, natural gas and NGLs, as well as the sale of third-party production of natural gas.

Revenues for the downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude oil.

This segment also generates revenues from the manufacture and sale of fuel and lubricant additives, renewable fuels, and the transportation and trading of refined products and crude oil.

“All Other” activities include revenues from insurance operations, real estate activities and technology companies.

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

Segment Expenses Purchased crude oil and products, operating and selling, general and administrative (SG&A) expense, and depreciation, depletion and amortization are the company’s significant segment expenses.

Operating and SG&A expenses include transportation, employee costs, service and fees, fuel and utilities, materials and supplies, SG&A expenses and other components of periodic benefit costs.

Other costs and deductions primarily represent taxes other than on income, exploration expense and interest and debt expenses.

Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis.

1 unchanged sentence

However, operating segments are billed for the direct use of corporate services.

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

Non-billable costs remain at the corporate level in “All Other.”

Segmented income statements for the years ended December 31, 2024, 2023 and 2022 are presented below:

Upstream Downstream Segment Total All Other Total

Year Ended December 31, 2024 U.S.

Sales and other operating revenues before elimination $ 44,302 $ 43,466 $ 80,417 $ 77,430 $ 245,615 $ 617 $ 246,232

Intersegment revenue elimination ( 29,662 ) ( 11,258 ) ( 9,745 ) ( 1,668 ) ( 52,333 ) ( 485 ) ( 52,818 )

Sales and Other Operating Revenues 14,640 32,208 70,672 75,762 193,282 132 193,414

Income (loss) from equity affiliates ( 62 ) 3,642 1,010 10 4,600 ( 4 ) 4,596

Other income (loss) 1

346 3,460 358 96 4,260 522 4,782

Total Revenues and Other Income 14,924 39,310 72,040 75,868 202,142 650 202,792

Intersegment product transfers 2

25,305 4,190 ( 26,845 ) ( 2,833 ) ( 183 ) 183 —

Less expenses:

Purchased crude oil and products 13,326 9,445 33,514 62,921 119,206 — 119,206

Operating and SG&A expenses 7,708 6,412 9,425 6,034 29,579 2,914 32,493

Depreciation, depletion and amortization 7,562 7,935 1,091 360 16,948 334 17,282

Other costs and deductions 3

1,805 1,156 550 2,071 5,582 723 6,305

Total Costs and Other Deductions 30,401 24,948 44,580 71,386 171,315 3,971 175,286

Income Tax Expense (Benefit) 2,198 7,548 84 397 10,227 ( 470 ) 9,757

Net income (loss) attributable to non-controlling interests 28 4 — 56 88 — 88

Net Income (Loss) Attributable to Chevron Corporation $ 7,602 $ 11,000 $ 531 $ 1,196 $ 20,329 $ ( 2,668 ) $ 17,661

Values have been adjusted for eliminations, unless otherwise specified.

1 Includes interest income of $ 296 in “All Other.”

2 Valuation of product transfers between operating segments.

3 Includes interest expense of $ 539 in “All Other.”

Notes to the Consolidated Financial Statements

1 unchanged sentence

Millions of dollars, except per-share amounts

Upstream Downstream Segment Total All Other Total

Year ended December 31, 2023

Sales and other operating revenues before elimination $ 40,115 $ 43,805 $ 83,567 $ 78,058 $ 245,545 $ 597 $ 246,142

Intersegment revenue elimination ( 26,307 ) ( 11,871 ) ( 8,793 ) ( 1,794 ) ( 48,765 ) ( 464 ) ( 49,229 )

Sales and Other Operating Revenues 13,808 31,934 74,774 76,264 196,780 133 196,913

Income (loss) from equity affiliates ( 387 ) 4,272 736 519 5,140 ( 9 ) 5,131

Other income (loss) 1

( 2,536 ) 776 444 39 ( 1,277 ) 182 ( 1,095 )

United States $ 4,148 $ 12,621 $ 7,319

International 13,290 17,663 8,499

Total Upstream 17,438 30,284 15,818

United States 3,904 5,394 2,389

International 2,233 2,761 525

Total Downstream 6,137 8,155 2,914

Total Segment Earnings 23,575 38,439 18,732

Interest expense ( 432 ) ( 476 ) ( 662 )

Interest income 491 261 36

Other ( 2,265 ) ( 2,759 ) ( 2,481 )

Total Revenues and Other Income 10,885 36,982 75,954 76,822 200,643 306 200,949

Intersegment product transfers 2

23,665 4,274 ( 23,887 ) ( 4,184 ) ( 132 ) 132 —

Less expenses:

Purchased crude oil and products 13,019 7,270 37,176 61,731 119,196 — 119,196

Operating and SG&A expenses 6,879 5,837 8,432 6,058 27,206 2,034 29,240

Depreciation, depletion and amortization 7,666 8,109 931 301 17,007 319 17,326

Other costs and deductions 3

1,676 1,010 515 1,782 4,983 620 5,603

Total Costs and Other Deductions 29,240 22,226 47,054 69,872 168,392 2,973 171,365

Income Tax Expense (Benefit) 1,141 5,733 1,109 519 8,502 ( 329 ) 8,173

Net income (loss) attributable to non-controlling interests 21 7 — 14 42 — 42

Net Income (Loss) Attributable to Chevron Corporation $ 4,148 $ 13,290 $ 3,904 $ 2,233 $ 23,575 $ ( 2,206 ) $ 21,369

Values have been adjusted for eliminations, unless otherwise specified.

1 Includes interest income of $ 491 in “All Other.”

2 Valuation of product transfers between operating segments.

3 Includes interest expense of $ 432 in “All Other.”

Upstream Downstream Segment Total All Other Total

Year Ended December 31, 2022 U.S.

Sales and other operating revenues before elimination $ 50,822 $ 56,156 $ 91,824 $ 87,741 $ 286,543 $ 518 $ 287,061

Intersegment revenue elimination ( 29,870 ) ( 13,815 ) ( 5,529 ) ( 1,728 ) ( 50,942 ) ( 402 ) ( 51,344 )

Sales and Other Operating Revenues 20,952 42,341 86,295 86,013 235,601 116 235,717

Income (loss) from equity affiliates ( 22 ) 6,648 1,003 962 8,591 ( 6 ) 8,585

Other income (loss) 1

103 1,272 527 ( 8 ) 1,894 56 1,950

Total Revenues and Other Income 21,033 50,261 87,825 86,967 246,086 166 246,252

Intersegment product transfers 2

29,801 7,078 ( 31,245 ) ( 5,706 ) ( 72 ) 72 —

Less expenses:

Purchased crude oil and products 21,008 12,717 40,483 71,208 145,416 — 145,416

Operating and SG&A expenses 6,799 6,810 7,829 5,094 26,532 2,789 29,321

Depreciation, depletion and amortization 5,012 9,830 913 311 16,066 253 16,319

Other costs and deductions 3

1,699 1,230 446 1,515 4,890 632 5,522

Total Costs and Other Deductions 34,518 30,587 49,671 78,128 192,904 3,674 196,578

Income Tax Expense (Benefit) 3,678 9,055 1,515 280 14,528 ( 462 ) 14,066

Net income (loss) attributable to non-controlling interests 17 34 — 92 143 — 143

Net Income (Loss) Attributable to Chevron Corporation $ 12,621 $ 17,663 $ 5,394 $ 2,761 $ 38,439 $ ( 2,974 ) $ 35,465

Values have been adjusted for eliminations, unless otherwise specified.

1 Includes interest income of $ 261 in “All Other.”

2 Valuation of product transfers between operating segments.

3 Includes interest expense of $ 476 in “All Other.”

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

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

17 unchanged sentences

Total Assets $ 256,938 $ 261,632

Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2023, 2022 and 2021, are presented in the table on the next page.

Products are transferred between operating segments at internal product values that approximate market prices.

Revenues for the upstream segment are derived primarily from the production and sale of crude oil and natural gas, as well as the sale of third-party production of natural gas.

This segment also generates revenues from the manufacture and sale of fuel and lubricant additives and the transportation and trading of refined products and crude oil.

“All Other” activities include revenues from insurance operations, real estate activities and technology companies.

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

Year ended December 31 *

2023 2022 2021

United States

$ 40,115 $ 50,822 $ 29,219

International

43,805 56,156 40,921

83,920 106,978 70,140

Intersegment Elimination — United States

( 26,307 ) ( 29,870 ) ( 15,154 )

Intersegment Elimination — International

( 11,871 ) ( 13,815 ) ( 10,994 )

Total Upstream 45,742 63,293 43,992

United States

83,567 91,824 57,209

International

78,058 87,741 58,098

161,625 179,565 115,307

Intersegment Elimination — United States

( 8,793 ) ( 5,529 ) ( 2,296 )

Intersegment Elimination — International

( 1,794 ) ( 1,728 ) ( 1,521 )

Total Downstream 151,038 172,308 111,490

United States

International

Intersegment Elimination — United States

( 462 ) ( 400 ) ( 382 )

Intersegment Elimination — International

( 2 ) ( 2 ) ( 2 )

Total All Other 133 116 124

Sales and Other Operating Revenues

United States

124,277 143,161 86,934

International

121,865 143,900 99,021

246,142 287,061 185,955

Intersegment Elimination — United States

( 35,562 ) ( 35,799 ) ( 17,832 )

Intersegment Elimination — International

( 13,667 ) ( 15,545 ) ( 12,517 )

Total Sales and Other Operating Revenues

$ 196,913 $ 235,717 $ 155,606

* Other than the United States, no other country accounted for 10 percent or more of the company’s Sales and Other Operating Revenues.

Segment Income Taxes Segment income tax expense for the years 2023, 2022 and 2021 is as follows:

Year ended December 31

2023 2022 2021

United States $ 1,141 $ 3,678 $ 1,934

International 5,733 9,055 4,192

Total Upstream 6,874 12,733 6,126

United States 1,109 1,515 547

International 519 280 203

Total Downstream 1,628 1,795 750

All Other ( 329 ) ( 462 ) ( 926 )

Total Income Tax Expense (Benefit) $ 8,173 $ 14,066 $ 5,950

Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 15 Investments and Advances .

Information related to properties, plant and equipment by segment is contained in Note 18 Properties, Plant and Equipment .

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

Information related to unusual items is contained in Note 27 Other Financial Information .

Investments and Advances

20 unchanged sentences

Total International $ 35,478 $ 35,827 $ 3,652 $ 4,791 $ 7,610

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

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.

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

At December 31, 2024, the company’s carrying value of its investment in TCO was about $ 73 higher than the amount of underlying equity in TCO’s net assets.

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 principal balance of $ 4,500 .

Included in the investment is a loan to TCO to fund the development of the Wellhead Pressure Management Project (WPMP) and Future Growth Project (FGP) with a principal balance of $ 4,500 .

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.

8 unchanged sentences

“Accounts payable” includes $ 556 and $ 591 due to affiliated companies at December 31, 2024 and 2023, respectively.

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

The following table provides summarized financial information on a 100 percent basis for all equity affiliates as well as Chevron’s total share, which includes Chevron’s net loans to affiliates of $ 4,731 , $ 4,494 and $ 4,278 at December 31, 2024, 2023 and 2022, respectively.

14 unchanged sentences

The total income tax expense recorded by the company’s equity affiliates in 2024 was $ 2,874 , with Chevron’s share being $ 1,286 .

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

The Ecuadorian trial court entered judgment against Chevron, and Ecuador’s highest Constitutional Court affirmed the judgment for approximately $ 9.5 billion.

In 2017, Chevron obtained a final court ruling in the United States determining that the Ecuadorian judgment had been procured through fraud, bribery, and corruption, and prohibiting the Ecuadorian plaintiffs and their cohorts from seeking to enforce the Ecuadorian judgment in the United States or profiting from their illegal acts.

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 in Chevron’s favor, finding that the Ecuadorian judgment was procured through fraud, bribery, and corruption and was based on environmental claims that Ecuador had already settled and released.

The tribunal ruled that the Ecuadorian judgment “violates international public policy” and “should not be recognized or enforced by the courts of other States,” and ordered Ecuador to remove the judgment’s status of enforceability and to compensate Chevron for its injuries in an amount to be established separately by the tribunal.

Ecuador’s requests to have a Dutch court set aside the tribunal’s award were denied, and the Dutch Supreme Court affirmed such denial in a final ruling in favor of Chevron in November 2023.

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.

Notes to the Consolidated Financial Statements

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Climate Change

Governmental and other entities in various jurisdictions across the United States have brought legal proceedings against fossil fuel producing companies, including Chevron entities, purporting to seek legal and equitable relief to address alleged impacts of climate change.

Governmental and other plaintiffs in various jurisdictions across the United States have brought legal proceedings against fossil fuel producing companies, including Chevron entities, purporting to seek legal and equitable relief to address alleged impacts of climate change.

Chevron entities are or were among the codefendants in 32 separate lawsuits filed by various U.S.

cities and counties, four U.S.

states, the District of Columbia, two Native American tribes, and a trade group in both federal and state courts.

1 One of the city lawsuits was dismissed on the merits and two suits, including one of the county lawsuits and the case brought by the trade association, were voluntarily dismissed by the plaintiffs.

The lawsuits have asserted 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, equitable relief for pollution, impairment and destruction of natural resources, unjust enrichment, violations of consumer protection statutes, violations of unfair competition statutes, violations of a federal antitrust statute, and violations of federal and state RICO statutes, 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.

states, the District of Columbia, the Commonwealth of Puerto Rico, two Native American tribes, and a trade group in both federal and state courts.

3 The lawsuits have asserted 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, equitable relief for pollution, impairment and destruction of natural resources, unjust enrichment, violations of consumer and environmental protection statutes, violations of unfair competition statutes, violations of a federal antitrust statute, and violations of federal and state RICO statutes, 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.

Further such proceedings are likely to be brought by other parties.

1 unchanged sentence

Supreme Court has denied petitions for writ of certiorari on jurisdictional questions to date.

Supreme Court has also denied petitions for certiorari to review a decision from the Hawaii Supreme Court allowing claims brought by the City and County of Honolulu to proceed past the pleadings.

The unprecedented legal theories set forth in these proceedings include claims for damages (both compensatory and punitive), injunctive and other forms of equitable relief, including without limitation abatement, contribution to abatement funds, disgorgement of profits and equitable relief for pollution, impairment and destruction of natural resources, civil penalties and liability for fees and costs of suits.

2 unchanged sentences

3 The cases are:

Municipality of Bayamon et al.

Exxon Mobil Corp., et al.

3 unchanged sentences

C-02-CV-21-000250 (Md.

County of Anne Arundel v.

Ct.) (dismissed on the merits, Plaintiff’s appeal pending);

Anne Arundel County v.

BP P.L.C., et al.

C-02-CV-21-000565 (Md.

Ct.) (dismissed on the merits, Plaintiff’s appeal pending);

Mayor and City Council of Baltimore v.

1 unchanged sentence

24-C-18-004219 (Md.

Ct.) (dismissed on the merits, Plaintiff’s appeal pending);

People ex rel.

1 unchanged sentence

CGC-23-609134 (Cal.

Bucks County v.

BP P.L.C., et al., No.

2024-01836 (Pa.

City of Charleston v.

1 unchanged sentence

2020-CP-10-3975 (S.C.

of Common Pleas);

District of Columbia v.

38 unchanged sentences

MER-L-001797-22 (N.J.

Ct.) (dismissed on the merits, appeal may be filed);

Estado Libre Asociado de Puerto Rico [Commonwealth of Puerto Rico] v.

Exxon Mobil Corp., et al.

SJ2024CV06512 (Tribunal de Primera Instancia, Estado Libre Asociado de P.R.) [P.R.

of First Instance, Commonwealth of P.R.];

City of New York v.

1 unchanged sentence

18-cv-00182 (S.D.N.Y.) (dismissed on the merits);

Pacific Coast Federation of Fishermen’s Associations v.

Pacific Coast Federation of Fishermen’s Associations, Inc.

Chevron Corp., et al.

2 unchanged sentences

State of Rhode Island v.

Chevron Corp., et al ., No.

Chevron Corp., et al ., C.A.

PC-2018-4716 (R.I.

20 unchanged sentences

2024CH01024 (Ill.

PORSC-CV-24-442 (Me.

Notes to the Consolidated Financial Statements

4 unchanged sentences

4 The lawsuits allege that the defendants’ historical operations were conducted without necessary permits or failed to comply with permits obtained and seek damages and other relief, including the costs of restoring coastal wetlands allegedly impacted by oil field operations.

Further such proceedings may be filed by other parties.

The Supreme Court denied a petition for writ of certiorari on jurisdictional questions impacting certain of these cases, and those cases have been or will be remanded to Louisiana state court.

Federal jurisdictional questions are still being decided for the remaining cases in the United States Court of Appeals for the Fifth Circuit.

A case has been set for trial in the United States District Court for the Eastern District of Louisiana and is scheduled to begin in October 2024.

Further such proceedings may be brought by other parties.

The Supreme Court denied a petition for writ of certiorari on jurisdictional questions impacting certain of these cases, and those cases have been or will be remanded to Louisiana state court, one of which has been set for trial and is scheduled to begin in March 2025.

Federal jurisdictional questions are still being decided for the remaining cases in the United States federal court system.

Due to the unprecedented nature of the suits, the company is unable to estimate any range of possible liability, but given the uncertainty of litigation there can be no assurance that the cases will not have a material adverse effect on the company’s results of operations and financial condition.

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Cameron Parish v.

Anadarko E&P Onshore, LLC, et al.

10-19578 (38th Jud.

Ct., Cameron Par.);

Cameron Parish v.

Apache Corporation (of Delaware), et al.

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Cameron Parish v .

Auster Oil & Gas, Inc ., et al., No.

10-19582 (38th Jud.

Ct., Cameron Par.);

Cameron Parish v .

Ballard Exploration Company, Inc., et al.

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Chevron’s share of its equity affiliates’ total income tax expense in 2024 was $ 1,286 .

The 2023 decrease in income tax expense of $ 5,893 is a result of the year-over-year decrease in total income before income tax expense, which is primarily due to lower upstream realizations and downstream margins.

The company’s effective tax rate changed from 28.3 percent in 2022 to 27.6 percent in 2023.

The change in effective tax rate is mainly due to mix effects resulting from the absolute level of earnings or losses and whether they arose in higher or lower tax rate jurisdictions.

The 2024 increase in income tax expense of $ 1,584 and the change in the company’s effective tax rate from 27.6 percent in 2023 to 35.5 percent in 2024 were primarily a result of the tax impacts from the asset sales in Canada.

Notes to the Consolidated Financial Statements

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Deferred tax assets valuation allowance 21,313 20,416

Total deferred taxes, net $ 14,661 $ 12,626

Deferred tax liabilities increased by $ 1,779 from year-end 2022, driven by an increase to properties, plant and equipment.

Total deferred income taxes, net $ 15,621 $ 14,661

Deferred tax liabilities increased by $ 1,336 from year-end 2023, driven by deferred tax impacts resulting from the asset sales in Canada and foreign exchange impacts.

Deferred tax assets increased by $ 1,273 from year-end 2023.

This increase was primarily related to increases in foreign tax credits and other accrued liabilities, partially offset by decreases in tax loss carryforwards and employee benefits.

The overall valuation allowance relates to deferred tax assets for U.S.

This increase was primarily related to increases in foreign tax credits and foreign exchange impacts, partially offset by decreases in tax loss carryforwards and other accrued liabilities.

The overall valuation allowance, which increased by $ 897 from year-end 2023, relates to deferred tax assets for U.S.

foreign tax credit carryforwards, tax loss carryforwards and temporary differences.

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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, or where no taxable temporary differences exist that are attributable to unremitted earnings from an investment in a foreign entity.

The indefinite reinvestment assertion continues to apply for the purpose of determining deferred tax liabilities for U.S.

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Settlements with taxing authorities in current year — ( 2 ) ( 110 )

( 2 ) ( 110 ) ( 18 )

Reductions as a result of a lapse of the applicable statute of limitations

Balance at December 31 $ 4,852 $ 5,452 $ 5,323

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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.

Of the amount of unrecognized tax benefits the company has identified as of December 31, 2024, it is reasonably possible that developments on tax matters in certain tax jurisdictions may result in decreases of approximately 68 percent 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.

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, 2023, accrued expense of $ 229 for anticipated interest and penalties was included on the Consolidated Balance Sheet, compared with accrued benefit of $ 112 as of year-end 2022.

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, 2024, accrued expense of $ 268 for anticipated interest and penalties was included on the Consolidated Balance Sheet, compared with accrued expense of $ 229 as of year-end 2023.

Income tax expense (benefit) associated with interest and penalties was $ 40 , $ 124 and $ 152 in 2024, 2023 and 2022, respectively.

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At December 31, 2024, the company had no interest rate swaps on short-term debt.

At December 31, 2023, the company had $ 8,050 in 364 -day committed credit facilities with various major banks that enable the refinancing of short-term obligations on a long-term basis.

The credit facilities allow the company to convert any amounts outstanding into a term loan for a period of up to one year.

At December 31, 2024, the company had $ 8,250 in 364 -day committed credit facilities with various major banks that enable the refinancing of short-term obligations.

The credit facilities allow the company the option to convert outstanding short-term obligations into a term loan for a period of up to one year from the facilities termination date.

This supports commercial paper borrowing and can also be used for general corporate purposes.

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 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, 2023.

The company’s practice has been to replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate.

Any borrowings under these facilities 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 these facilities at December 31, 2024.

The company classified $ 8,250 and $ 4,543 of short-term debt as long-term at December 31, 2024 and 2023, respectively.

Settlement of these obligations is not expected to require the use of working capital within one year, and the company has both the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

Settlement of these obligations is not expected to require the use of working capital within one year, as the company had the intent and the ability, as evidenced by committed credit facilities, to continue refinancing them.

Notes to the Consolidated Financial Statements

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Notes due 2025 1.724 0.687 - 3.326

$ 1,650 $ 1,650

Notes due 2026 2.954 2,250 2,250

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Notes due 2030 2.236 1,500 1,500

Debentures due 2031 8.625 102 102

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Debentures due 2097 7.250 60 60

Bank loans due 2023 -

Bank loans due 2025 to 2027 3.321 3.306 - 3.367

Medium-term notes, maturing from 2033 to 2038 6.101 4.324 - 7.840

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3 For details on finance lease liabilities, see Note 5 Lease Commitments .

Chevron has an automatic shelf registration statement that expires in November 2027.

This registration statement is for an unspecified amount of nonconvertible debt securities issued or guaranteed by Chevron Corporation or CUSA.

Long-term debt excluding finance lease liabilities with a principal balance of $ 14,836 matures as follows:

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and after 2029 – $ 5,281 .

During the third quarter of 2023, the company assumed $ 1.5 billion of debt in conjunction with the PDC acquisition, including balances outstanding under the revolving credit facility, PDC’s 6.125 % notes due 2024 (2024 notes) and PDC’s 5.75 % notes due 2026 (2026 notes).

The outstanding balances under the revolving credit facility and the 2024 notes were repaid during third quarter 2023.

The company also irrevocably deposited sufficient U.S.

Treasury securities with U.S.

Bank Trust Company, N.A., as trustee, to fund the redemption of the 2026 notes, resulting in the indenture being satisfied and discharged.

See Note 9 Fair Value Measurements for information concerning the fair value of the company’s long-term debt.

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Reclassifications to wells, facilities and equipment based on the determination of proved reserves

— ( 481 ) ( 425 )

Capitalized exploratory well costs charged to expense — ( 67 ) ( 73 )

( 67 ) ( 73 ) ( 34 )

Ending balance at December 31 $ 1,662 $ 1,648 $ 1,627

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Of the $ 1,645 of exploratory well costs capitalized for more than one year at December 31, 2024, $ 847 is related to seven projects that had drilling activities underway or firmly planned for the near future.

The $ 726 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.

The $ 798 balance is related to seven 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 $ 798 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability:

(a) $ 311 ( four projects) – undergoing front-end engineering and design with final investment decision expected within four years ;

(a) $ 383 ( five 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 14 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.

Approximately three-quarters of these decisions are expected to occur in the next five years .

Approximately half of these decisions are expected to occur in the next five years .

The $ 1,645 of suspended well costs capitalized for a period greater than one year as of December 31, 2024, represents 75 exploratory wells in 14 projects.

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Compensation expense for stock options for 2024, 2023 and 2022 was $ 90 ($ 68 after tax), $ 85 ($ 65 after tax) and $ 60 ($ 46 after tax), respectively.

In addition, compensation expense for stock appreciation rights, restricted stock, performance shares and restricted stock units resulted in a net benefit of $( 100 ) ($( 76 ) after tax) for 2023, primarily as a result of reductions in the fair value of outstanding liability-classified performance shares that are remeasured each reporting period.

Compensation expense for stock appreciation rights, restricted stock, performance shares and restricted stock units was $ 1,013 ($ 770 after tax) and $ 701 ($ 554 after tax) for 2022 and 2021, respectively.

In addition, compensation expense for stock appreciation rights, restricted stock, performance shares and restricted stock units for 2024, 2023 and 2022 was $ 510 ($ 388 after tax), $( 100 ) ($( 76 ) after tax) and $ 1,013 ($ 770 after tax), respectively.

No significant stock-based compensation cost was capitalized at December 31, 2024, or December 31, 2023.

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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.

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, share-settled performance shares and other share-settled awards that do not require full payment in cash or property for shares underlying such awards by the award recipient.

Contractual terms of equity awards vary between three years for the performance shares and special restricted stock units with cliff vesting at the end of the contractual period, five years for standard restricted stock units with cliff vesting at the end of the contractual period and 10 years for the stock options and stock appreciation rights with graded vesting provisions by which one-third of each award vests around each of the first, second and third anniversaries of the date of grant.

Commencing for grants issued in January 2023 and after, standard restricted stock units vest ratably on an annual basis over a three-year period.

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During 2024, 1,525,452 performance shares were granted, 1,966,923 shares vested with cash proceeds distributed to recipients and 118,400 shares were forfeited.

At December 31, 2023, there were 4,419,310 performance shares outstanding that are payable in cash.

The fair value of the liability recorded for these instruments was $ 360 and was measured largely using the Monte Carlo simulation method.

At December 31, 2024, there were 3,859,439 performance shares outstanding, of which 2,815,575 are payable in cash and 1,043,864 are payable in shares.

The fair value of the liability recorded for these instruments payable in cash was $ 307 and was measured largely using the Monte Carlo simulation method.

Notes to the Consolidated Financial Statements

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nonqualified pension plans that are not subject to funding requirements under laws and regulations because contributions to these pension plans may be less economic and investment returns may be less attractive than the company’s other investment alternatives.

The company also sponsors other postretirement benefit (OPEB) plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees.

The company also sponsors other post-employment benefit (OPEB) plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees.

The plans are unfunded, and the company and retirees share the costs.

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Benefits paid ( 692 ) ( 217 ) ( 714 ) ( 218 ) ( 202 ) ( 222 )

Actual expenses/taxes — ( 2 ) — — — —

Divestitures/Acquisitions — — — ( 14 ) — —

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Benefits paid ( 692 ) ( 217 ) ( 714 ) ( 218 ) ( 202 ) ( 222 )

Actual expenses — ( 2 ) — — — —

Fair value of plan assets at December 31 9,537 3,061 9,137 3,398 — —

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Net amount recognized at December 31 $ ( 603 ) $ ( 228 ) $ ( 1,255 ) $ ( 207 ) $ ( 1,880 ) $ ( 2,017 )

For the year ended December 31, 2024, the decrease in benefit obligations was primarily due to actuarial gains caused by higher discount rates used to value the obligations.

For the year ended December 31, 2023, the increase in benefit obligations was primarily due to actuarial losses caused by lower discount rates used to value the obligations.

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.

Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $ 3,376 and $ 3,792 at the end of 2024 and 2023, respectively.

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2024 2023 Other Benefits

Net actuarial loss $ 3,161 $ 823 $ 3,147 $ 659 $ ( 266 ) $ ( 392 )

Prior service (credit) costs 37 126 40 107 ( 89 ) ( 115 )

Net actuarial (gain) loss $ 2,796 $ 849 $ 3,161 $ 823 $ ( 401 ) $ ( 266 )

Prior service (credits) costs 33 133 37 126 ( 34 ) ( 89 )

Total recognized at December 31 $ 2,829 $ 982 $ 3,198 $ 949 $ ( 435 ) $ ( 355 )

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Amortization of prior service costs (credits) 4 11 4 8 2 6 ( 25 ) ( 25 ) ( 27 )

Recognized actuarial losses 199 8 218 15 309 46 ( 19 ) 13 16

Settlement losses 56 — 363 ( 6 ) 672 7 — — —

Recognized actuarial (gains) losses 243 18 199 8 218 15 ( 15 ) ( 19 ) 13

Settlement losses (gains) — 1 56 — 363 ( 6 ) — — —

Curtailment losses (gains) — — — 2 — ( 5 ) ( 1 ) — —

4 unchanged sentences

Net actuarial (gain) loss during period ( 122 ) 45 270 172 ( 279 ) ( 257 ) ( 151 ) 108 ( 514 )

Amortization of actuarial loss ( 255 ) ( 8 ) ( 581 ) ( 5 ) ( 981 ) ( 73 ) 19 ( 13 ) ( 15 )

Amortization of actuarial (gain) loss ( 243 ) ( 19 ) ( 255 ) ( 8 ) ( 581 ) ( 5 ) 15 19 ( 13 )

Prior service (credits) costs during period — 18 — 28 40 38 30 1 18

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pension and OPEB plans.

The effective discount rates derived from this analysis were 5.0 percent, 5.2 percent, and 2.8 percent for 2023, 2022, and 2021, respectively, for both the main U.S.

pension and OPEB plans.

The effective discount rates derived from this analysis were 5.7 percent, 5.0 percent, and 5.2 percent for 2024, 2023, and 2022, respectively, for the main U.S.

pension plan and 5.6 percent, 5.0 percent, and 5.2 percent for 2024, 2023, and 2022, respectively, for the main U.S.

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2023, for the main U.S.

Other Benefit Assumptions For the measurement of accumulated post-employment benefit obligation at December 31, 2024, for the main U.S.

OPEB plan, the assumed health care cost-trend rates start with 8.4 percent in 2025 and gradually decline to 4.5 percent for 2034 and beyond.

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The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below:

International Real Estate Other Total

Real Estate Other Total

Total at December 31, 2022 $ — $ — $ 38 $ 139 $ 177

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Chevron’s environmental reserve as of December 31, 2024, was $ 945 .

Included in this balance was $ 232 related to remediation activities at sites for which the company had been identified as a potentially responsible party under the provisions of the U.S.

Included in this balance was $ 220 related to remediation activities at sites for which the company has been identified as a potentially responsible party under the provisions of the U.S.

federal Superfund law which provide for joint and several liability for all responsible parties.

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Refer to Note 25 Asset Retirement Obligations for a discussion of the company’s asset retirement obligations.

Other Contingencies Chevron receives claims from and submits claims to customers;

Decommissioning Obligations for Previously Divested Assets Some assets are divested along with their related liabilities, such as decommissioning obligations.

In certain instances, such transferred obligations have returned and may continue to return to the company.

For example, in fourth quarter 2023, the company recognized charges for decommissioning obligations from certain previously divested assets in the Gulf of America.

To the extent the current owners of the company’s previously divested assets default on their decommissioning obligations, regulators may require that Chevron assume such obligations.

The company could have additional significant obligations revert, primarily in the United States.

The company is not currently aware of any such obligations that are reasonably possible to be material.

The liability balance at the end of 2023 was $ 2,708 , $ 235 was spent in 2024, and the balance at the end of 2024 was $ 2,478 .

Other Contingencies The company and its affiliates continue to review and analyze their operations and may close, retire, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve competitiveness and profitability.

These activities, individually or together, may result in significant gains or losses in future periods.

Chevron receives claims from and submits claims to customers;

trading partners;

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The amounts of these claims, individually and in the aggregate, may be significant and take lengthy periods to resolve, and may result in gains or losses in future periods.

The company and its affiliates also continue to review and analyze their operations and may close, retire, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve competitiveness and profitability.

These activities, individually or together, may result in significant gains or losses in future periods.

In addition, some assets are sold along with their related liabilities and in certain instances, such transferred obligations have reverted and may in the future revert to the company and result in losses that could be significant.

In fourth quarter 2023, the company recognized an after-tax loss of $ 1,950 related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S.

Gulf of Mexico, as companies that purchased these assets have filed for protection under Chapter 11 of the U.S.

Bankruptcy Code, and we believe it is now probable and estimable that a portion of these obligations will revert to the company.

Asset Retirement Obligations

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This uncertainty about the timing and/or method of settlement is factored into the measurement of the liability when sufficient information exists to reasonably estimate fair value.

Recognition of the ARO includes:

(1) the present value of a liability and offsetting asset, (2) the subsequent accretion of that liability and depreciation of the asset, and (3) the periodic review of the ARO liability estimates and discount rates.

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 for the asset retirements prevent estimation of the fair value of the associated ARO.

The company performs periodic

The ARO liability is initially recognized at its fair value with an increase to the related asset.

Subsequent accretion of the liability and depreciation of the asset is recorded over time.

The company evaluates its ARO estimates regularly or when there is significant new information about costs, timing, and duration of asset retirement activity.

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

reviews of its downstream long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation.

AROs are primarily recorded for the company’s crude oil and natural gas producing assets.

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 2024, 2023 and 2022:

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Liabilities settled ( 2,083 ) ( 1,471 ) ( 1,102 )

Reduction due to asset sales ( 171 ) ( 94 ) ( 179 )

Accretion expense 588 593 560

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Earnings in 2024 included after -tax gains of approximately $ 246 relating to the sale of certain properties.

Of this amount, approximately $ 33 and $ 110 related to downstream and upstream, respectively.

Earnings in 2022 included after-tax gains of approximately $ 390 relating to the sale of certain properties, of which approximately $ 90 and $ 300 related to downstream and upstream assets, respectively.

Earnings in 2021 included after-tax gains of approximately $ 785 relating to the sale of certain properties, of which approximately $ 30 and $ 755 related to downstream and upstream assets, respectively.

Earnings in 2023 included after-tax charges of approximately $ 1,950 for abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S.

Gulf of Mexico and $ 1,765 for upstream impairments, mainly in California, and several tax items with a net benefit of $ 655 .

Earnings in 2022 included after-tax charges of approximately $ 1,075 for impairments and other asset write-offs related to upstream, $ 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 c osts, $ 260 for early retirement of debt, $ 120 relating to upstream remediation and $ 110 relating to downstream legal reserves.

Of this amount, approximately $ 231 and $ 15 related to upstream and downstream, respectively.

Earn ings in 2023 included after-tax gains of approximately $ 143 relating to the sale of certain properties, of which approximately $ 110 and $ 33 related to upstream and downstream assets, respectively.

Earnings in 2022 included after-tax gains of approximately $ 390 relating to the sale of certain properties, of which approximately $ 300 and $ 90 related to upstream and downstream assets, respectively.

Earnings in 2024 included after-tax charges of approximat ely $ 715 for s everance ($ 208 in All Other, $ 188 in U.S.

Downstream, $ 183 in U.S.

Upstream, $ 119 in International Upstream, $ 17 in International Downstream) and $ 400 for impairments ($ 185 in International Downstream, $ 125 in International Upstream, $ 90 in U.S.

Downstream) .

Earnings in 2023 included after-tax charges of approximately $ 1,950 for decommissioning obligations from previously divested oil and gas production assets in the U.S.

Upstream Gulf of America, $ 1,765 for U.S.

Upstream impairments, mainly in California, and several tax items with a net benefit of $ 655 in International Upstream.

Earnings in 2022 included after-tax charges of approximately $ 1,075 for impairments and other asset write-offs related to International Upstream, $ 600 for an early contract termination in U.S.

Upstream, and $ 271 for pension settlement costs in All Other.

Notes to the Consolidated Financial Statements

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* Includes $ 45 , $( 11 ) and $ 253 in 2024, 2023 and 2022, respectively, for the company’s share of equity affiliates’ foreign currency effects.

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 has $ 4,578 in goodwill on the Consolidated Balance Sheet, of which $ 4,226 is in the upstream segment primarily related to the 2005 acquisition of Unocal and $ 352 is in the downstream segment related to the 2022 acquisition of Renewable Energy Group, Inc.

The company tested this goodwill for impairment during 2024, and no impairment was required.

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Non-trade receivables also include employee and tax receivables that are deemed immaterial and low risk.

Loans to equity affiliates and non-equity investees are also considered non-trade and associated allowances of $ 219 and $ 560 at December 31, 2023 and December 31, 2022, respectively, are included within “Investments and advances” on the Consolidated Balance Sheet.

Loans to equity affiliates and non-equity investees are also considered non-trade and associated allowances of zero and $ 219 at December 31, 2024, and December 31, 2023, respectively, are included within “Investments and advances” on the Consolidated Balance Sheet.

Notes to the Consolidated Financial Statements

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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 value.

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 date of acquisition, 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 with appropriate operating cost and development cost assumptions.

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As a result of measuring the assets acquired and the liabilities assumed at fair value, there was no goodwill or bargain purchase recognized.

The following table summarizes the provisional fair values assigned to assets acquired and liabilities assumed:

The following table summarizes the fair values assigned to assets acquired and liabilities assumed:

At August 7, 2023

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On October 23, 2023, Chevron Corporation announced it had entered into a definitive agreement with Hess Corporation (Hess) to acquire all of its outstanding shares in an all-stock transaction, valued at approximately $ 53,000 , pursuant to which Hess stockholders will receive 1.0250 shares of Chevron common stock for each Hess share.

The transaction was unanimously approved by the Boards of Directors of both companies and is anticipated to close around the middle of 2024.

The acquisition is subject to Hess stockholder approval.

It is also subject to regulatory approvals and other closing conditions.

The transaction was unanimously approved by the Boards of Directors of both companies.

On May 28, 2024, a majority of Hess stockholders voted to approve the merger.

Following the Federal Trade Commission’s (FTC) review of the transaction, on September 30, 2024, the FTC announced that a majority of the Commission voted to accept a consent agreement among the FTC, Chevron and Hess, resolving the concerns the FTC identified during its review of the transaction.

Chevron and Hess have taken and will continue to take appropriate steps to maintain our ability to close the merger under the Hart-Scott-Rodino Act of 1976, as amended.

The filing of an arbitration relating to the right of first refusal contained in the Stabroek Block operating agreement among Hess Guyana Exploration Limited, a wholly owned subsidiary of Hess, and affiliates of Exxon Mobil Corporation, and China National Offshore Oil Corporation has delayed completion of the transaction.

An arbitration decision against Hess Guyana and in favor of Exxon Guyana and CNOOC Guyana would cause the transaction not to be completed.

The arbitration merits hearing has been scheduled for May 2025, with a decision expected in approximately the following three months.

Chevron and Hess are working to complete the merger as soon as practicable.

However, neither Chevron nor Hess can predict the actual date on which the transaction will be completed, if at all, because it is subject to conditions beyond each company’s control.

Risk Factors for a discussion of risks related to the Hess acquisition.

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3 Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses.

2023 also includes a loss related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S.

Gulf of Mexico.

2023 also includes a loss related to decommissioning obligations from certain previously divested oil and gas production assets in the Gulf of America.

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

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Proved undeveloped reserves are the quantities expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.

Proved reserves are estimated by company asset teams composed of earth scientists and engineers.

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Major changes are also reviewed with the company’s senior leadership team including the Chief Executive Officer and the Chief Financial Officer.

The company’s annual reserves activity is also reviewed with the Board Audit Committee and the Board of Directors.

The company’s annual reserves activity is also reviewed with the company’s Audit Committee and Board of Directors.

If major changes to reserves were to occur between the annual reviews, those matters would also be discussed with the Board.

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Extension and discoveries 390

Purchases 312

Transfers to proved developed (950)

Quantity at December 31 2,761

In 2023, revisions include a net decrease of 407 million BOE in the United States.

Revisions in Midland and Delaware basins yielded a decrease of 275 million BOE mainly due to a decrease of 186 million BOE from portfolio optimization and a reduction of 74 million BOE from reservoir performance.

Reduced development activities contributed to a net decrease of 114 million BOE in east Texas and California.

In Kazakhstan, primarily at TCO, performance-driven reservoir model changes led to a net decrease of 107 million BOE to proved undeveloped reserves with a largely offsetting increase

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

to proved developed reserves in existing wells.

These reductions were partially offset by an increase of 49 million BOE in Israel mainly due to the final investment decision on a new gas pipeline project.

In 2023, extensions and discoveries of 258 million BOE in the United States were primarily due to planned development of new locations in shale and tight assets in the Midland and Delaware basins of 173 million BOE and the DJ basin of 49 million BOE, and deepwater assets in the Gulf of Mexico of 36 million BOE.

In Other Americas, 57 million BOE of extensions and discoveries were mainly from shale and tight assets in Argentina.

In 2023, purchases of 301 million BOE in the United States are primarily from the acquisition of PDC.

In 2024, revisions in the United States were primarily from the Denver-Julesburg (DJ) basin yielding a decrease of 98 million BOE mainly due to reservoir performance and portfolio optimization.

A net decrease of 33 million BOE in the Midland and Delaware basins was due to reservoir performance.

In 2024, extensions and discoveries of 316 million BOE in the United States were primarily due to planned development of new locations in shale and tight assets in the DJ basin of 171 million BOE, the Midland and Delaware basins of 123 million BOE, and deepwater assets in the Gulf of America of 22 million BOE.

In Other Americas, 58 million BOE of extensions and discoveries were from shale and tight assets in Argentina.

In 2024, purchases of 70 million BOE in the United States are primarily from newly identified proved undeveloped well locations associated with the acquisition of PDC.

The difference in 2024 extensions and discoveries of 161 million BOE, between the net quantities of proved reserves of 551 million BOE as reflected on pages 112 to 114 and net quantities of proved undeveloped reserves of 390 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 2024.

Transfers to proved developed reserves in 2023 include 395 million BOE in the United States, primarily from 268 million BOE in the Midland and Delaware basins, 83 million BOE in the DJ basin, and 44 million BOE in the Gulf of Mexico.

Other significant transfers to proved developed are 114 million BOE in Israel and a combined 87 million BOE in Bangladesh, Argentina, Canada, Kazakhstan, and other international locations.

Transfers to proved developed reserves in 2024 include 464 million BOE in the United States, from 256 million BOE in the Midland and Delaware basins, 126 million BOE in the DJ basin, and 82 million BOE in the Gulf of America.

Other significant transfers to proved developed were 329 million BOE in Kazakhstan, primarily at TCO, and 75 million BOE in Angola, primarily at Angola LNG.

A combined 81 million BOE of transfers to proved developed were recorded in Argentina, Canada, Australia, Nigeria, China, and other international locations.

These transfers are the consequence of development expenditures on completing wells and facilities.

During 2023, investments totaling approximately $9.1 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 $5.0 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 $2.5 billion, primarily related to development projects for TCO in Kazakhstan.

An additional $0.3 billion were spent on development activities in Australia.

In Africa, about $0.7 billion was expended on various offshore development and natural gas projects in Nigeria, Angola and Republic of Congo.

During 2024, the company’s investments totaled approximately $8.2 billion in oil and gas producing activities, and about $0.1 billion in non-oil and gas producing activities, to advance the development of proved undeveloped reserves.

The United States accounted for about $5.5 billion primarily related to various development activities in the Midland and Delaware basins, the Gulf of America and the DJ basin.

In Africa, about $0.8 billion was expended on various offshore development and natural gas projects in Nigeria and Angola.

An additional $0.5 billion was spent on development activities in Australia.

Development activities in other international locations were primarily responsible for about $1.4 billion of expenditures.

The company’s equity affiliates investments in oil and gas producing activities to advance development of proved undeveloped reserves in 2024 was $1.3 billion primarily related to development projects for TCO in Kazakhstan.

Reserves that remain proved undeveloped for five or more years are a result of several factors that affect optimal project development and execution.

These factors may include the complex nature of the development project in adverse and remote locations, physical limitations of infrastructure or plant capacities that dictate project timing, compression projects that are pending reservoir pressure declines, and contractual limitations that dictate production levels.

At year-end 2023, the company held approximately 1 billion BOE of proved undeveloped reserves that have remained undeveloped for five years or more.

At year-end 2024, the company held approximately 624 million BOE of proved undeveloped reserves that have remained undeveloped for five years or more.

The majority of these reserves are in locations where the company has a proven track record of developing major projects.

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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 137 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.

Affiliates account for about 650 million BOE of proved undeveloped reserves with about 575 million BOE that have remained undeveloped for five years or more.

Approximately 511 million BOE are related to TCO in Kazakhstan and about 64 million BOE are related to Angola LNG.

At TCO and Angola LNG, further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with reservoir depletion and facility constraints.

In Africa, approximately 138 million BOE have remained undeveloped for five years or more, due to facility constraints at various fields and infrastructure associated with the Escravos gas projects in Nigeria.

Affiliates account for about 237 million BOE of proved undeveloped reserves with about 197 million BOE that have remained undeveloped for five years or more related to TCO.

At TCO, further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with reservoir depletion and facility constraints.

Annually, the company assesses whether any changes have occurred in facts or circumstances, such as changes to development plans, regulations, or government policies, that would warrant a revision to reserve estimates.

In 2023, lower commodity prices negatively impacted the economic limits of oil and gas properties, resulting in a proved reserve decrease of approximately 135 million BOE, and positively impacted proved reserves due to entitlement effects, resulting in a proved reserves increase of approximately 89 million BOE.

The year-end reserves quantities have been updated for these circumstances and significant changes have been discussed in the appropriate reserves sections.

In 2024, lower natural gas prices in North America were primarily responsible for the negative impact to the economic limits of oil and gas properties, resulting in a proved reserve decrease of approximately 58 million BOE.

The year-end reserves quantities have been updated for these circumstances and significant changes are discussed in the appropriate reserves sections herein.

Over the past three years, the ratio of proved undeveloped reserves to total proved reserves has ranged between 28 percent and 35 percent.

Proved Reserve Quantities For the three years ended December 31, 2023, the pattern of net reserve changes shown in the following tables is not necessarily indicative of future trends.

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

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

permitting, partner approvals of development plans, changes in oil and gas prices, OPEC constraints, geopolitical uncertainties, civil unrest, events of war or military conflicts.

Proved Reserve Quantities For the three-year period ended December 31, 2024, the pattern of net reserve changes shown in the following tables is not necessarily indicative of future trends.

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, civil unrest, events of war or military conflicts.

At December 31, 2024, proved reserves for the company were 9.8 billion BOE.

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Noteworthy changes in crude oil, condensate and synthetic oil proved reserves for 2022 through 2024 are discussed below and shown in the table on the following page:

Revisions 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 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.

Entitlement effects primarily contributed to a decrease of 106 million barrels of synthetic oil at the Athabasca Oil Sands project in Canada.

In the Other Americas, performance revisions and price effects, mainly in Canada and Argentina, were primarily responsible for the 41 million barrels increase.

In 2022, entitlement effects primarily contributed to a decrease of 49 million barrels of synthetic oil at the Athabasca Oil Sands project in Canada.

Revisions 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.

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In Other Americas, entitlement effects primarily contributed to an increase of 42 million barrels of synthetic oil at the Athabasca Oil Sands project in Canada.

In Asia, reservoir performance, mainly in the Partitioned Zone of Saudi Arabia/Kuwait, was responsible for the 48 million barrels increase.

In Asia, reservoir performance, mainly in the Partitioned Zone between Saudi Arabia and Kuwait (the Partitioned Zone), was responsible for the 48 million barrels increase.

Reservoir performance in Nigeria was mainly responsible for the 37 million barrels increase in Africa.

Extensions and Discoveries 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 2024, the 37 million barrels increase in Asia was due to reservoir performance, primarily in the Partitioned Zone.

Extensions and Discoveries In 2022, extensions and discoveries in the Midland, Delaware and DJ basins, and approval of the Ballymore Project in the Gulf of America, 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.

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In Other Americas, the 55 million barrels of extensions and discoveries increase was mainly from shale and tight assets in Argentina.

In 2024, extensions and discoveries of 119 million barrels in the Midland and Delaware basins, and 45 million barrels in the DJ basin, were primarily responsible for the 185 million barrels increase in the United States.

In Other Americas, the 52 million barrels of extensions and discoveries increase was mainly from shale and tight assets in Argentina.

Purchases 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.

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In 2023, the acquisition of PDC in the DJ and Delaware basins was primarily responsible for the 207 million barrels increase in the United States.

Sales In 2021, sales of 32 million barrels in the United States were in the Midland and Delaware basins.

In 2024, the renewal of the Agbami field deepwater license in Nigeria increased reserves by 51 million barrels.

Sales In 2024, sales of 593 million barrels in synthetic oil were from the Athabasca oil sand assets in Canada and the 46 million barrels in Other Americas were from the divestment of shale and tight assets in Canada.

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

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Noteworthy changes in NGLs proved reserves for 2022 through 2024 are discussed below and shown in the table on the following page:

Revisions 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.

In 2023, the 110 million barrels decrease in the United States was primarily in the Midland and Delaware basins with a decrease of 49 million barrels due to portfolio optimization and a decrease of 29 million barrels due to reservoir performance.

Revisions In 2023, the 110 million barrels decrease in the United States was primarily in the Midland and Delaware basins with a decrease of 49 million barrels due to portfolio optimization and a decrease of 29 million barrels due to reservoir performance.

In 2024, the 41 million barrels decrease in the United States was primarily from a decrease of 65 million barrels in the DJ basin, which was partially offset by an increase of 31 million barrels from the Gulf of America.

Extensions and Discoveries In 2022, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 163 million barrels increase in the United States.

In 2023, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 92 million barrels increase in the United States.

In 2024, extensions and discoveries in the Midland and Delaware basins of 72 million barrels, and in the DJ basin of 52 million barrels, were responsible for the 124 million barrels increase in the United States.

Purchases In 2023, the acquisition of PDC in the DJ and Delaware basins was primarily responsible for the 262 million barrels increase in the United States.

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Noteworthy changes in natural gas proved reserves for 2022 through 2024 are discussed below and shown in the table on the following page:

Revisions In 2021, the approval of the Jansz Io Compression project was mainly responsible for the 1.2 trillion cubic feet (TCF) increase in Australia.

Higher commodity prices, resulting in the increase of planned development activity in the Midland and Delaware basins, were mainly responsible for the 829 billion cubic feet (BCF) increase in the United States.

In TCO, entitlement effects and technical changes in field operating assumptions, reservoir model, and project schedule were primarily responsible for the 179 BCF decrease.

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.

Revisions 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.

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In Asia, final investment decision on a new gas pipeline project in Israel and reservoir performance in Bangladesh were mainly responsible for the 481 BCF increase.

In 2024, a decrease of 425 BCF in the DJ basin, primarily related to reservoir performance, was mainly responsible for the 572 BCF decrease in the United States.

The 504 BCF increase in Australia was mainly due to reservoir performance of the Jansz Io field.

Extensions and Discoveries In 2022, extensions and discoveries of 1.6 TCF in the United States were primarily in the Midland and Delaware basins.

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

In 2023, extensions and discoveries of 660 BCF in the United States were primarily in the Midland and Delaware basins.

In 2024, extensions and discoveries of 912 BCF in the United States were primarily in the DJ basin with 476 BCF, and the Midland and Delaware basins with 432 BCF.

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

Purchases In 2023, the acquisition of PDC in the DJ basin was primarily responsible for the 2.2 TCF in the United States.

In 2024, the 177 BCF in the United States was primarily associated with the acquisition of PDC in the DJ basin.

Sales In 2022, sales of 243 BCF in the United States were primarily in the Eagle Ford shale and Midland and Delaware basins.

In 2024, sales of 260 BCF in Other Americas were from the divestment of shale and tight assets in Canada.

Net Proved Reserves of Natural Gas

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2 Reserves associated with Africa.

3 Total “as sold” volumes are 2,609, 2,600 and 2,599 for 2023, 2022 and 2021, respectively.

3 Total “as sold” volumes were 2,768, 2,609 and 2,600 for 2024, 2023 and 2022, respectively.

4 Includes reserve quantities related to PSC.

PSC-related reserve quantities are 7 percent, 8 percent and 8 percent for consolidated companies for 2023, 2022 and 2021, respectively.

PSC-related reserve quantities were 6 percent, 7 percent and 8 percent for consolidated companies for 2024, 2023 and 2022, respectively.

5 Reserve quantities include natural gas projected to be consumed in operations of 2,462, 2,655 and 2,737 billions of cubic feet as of December 31, 2024, 2023 and 2022, respectively.

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The standardized measure of discounted future net cash flows is calculated in accordance with SEC and FASB requirements.

This includes using the average of first-day-of-the-month oil and gas prices for the 12-month period prior to the end of the reporting period, estimated future development and production costs assuming the continuation of existing economic conditions, estimated costs for asset retirement obligations (includes costs to retire existing wells and facilities in addition to those future wells and facilities necessary to produce proved undeveloped reserves), and estimated future income taxes based on appropriate statutory tax rates.

This includes using the unweighted arithmetic average of the first-day-of-the-month oil and gas prices for the 12-month period prior to the end of the reporting period, estimated future development and production costs assuming the continuation of existing economic conditions, estimated costs for asset retirement obligations (includes costs to retire existing wells and facilities in addition to those future wells and facilities necessary to produce proved undeveloped reserves), and estimated future income taxes based on appropriate statutory tax rates.

Discounted future net cash flows are calculated using 10 percent mid-period discount factors.

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Probable and possible reserves, which may become proved in the future, are excluded from the calculations.

The valuation requires assumptions as to the timing and amount of future development and production costs.

The valuation requires assumptions as to the timing and amount of future development and production costs, which could change over time as new information becomes available.

The calculations are made as of December 31 each year and do not represent management’s estimate of the company’s future cash flows or value of its oil and gas reserves.

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Amendment Number One to the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, and incorporated herein by reference.

10.3+* Amendment Number Two to the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan .

10.4+ Form of Retainer Stock Option Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.17 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2009, and incorporated herein by reference.

3 unchanged sentences

10.7+ Summary of Chevron Incentive Plan Award Criteria, filed as Exhibit 10.6 to Chevron Corporation's Annual Report on Form 10-K for the year ended December 31, 2022, and incorporated herein by reference.

10.7+ Long-Term Incentive Plan of Chevron Corporation, amended and restated effective Octo ber 2 , 2023, filed as Exhibit 10.5 to Chevron Corporation ’ s Quarterly Report on Form 10-Q for the quarter ended September 3 0, 2023, and incorporated herein by reference.

10.8+ Form of Performance Share Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed February 1, 2021, and incorporated herein by reference.

Form of Performance Share Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed February 3, 2020, and incorporated herein by reference.

10.8+ Long-Term Incentive Plan of Chevron Corporation, amended and restated effective October 2, 2023, filed as Exhibit 10.5 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2023, and incorporated herein by reference.

10.9+ Form of Non-Qualified Stock Option Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.

8 to Chevron Corporation’s Annual Report on Form 10 -K for the year ended December 31, 20 14 , and incorporated herein by reference.

10.10+ Form of Non-Qualified Stock Option Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed January 30, 2017, and incorporated herein by reference.

10.11+ Form of Non-Qualified Stock Option Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed February 2, 2018, and incorporated herein by reference.

10.12+ Form of Standard Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.3 to Chevron Corporation’s Current Report on Form 8-K filed February 3, 2020, and incorporated herein by reference.

Form of Special Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.3 to Chevron Corporation’s Current Report on Form 8-K filed February 4, 2019, and incorporated herein by reference.

10.13+ Form of Non-Qualified Stock Option Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.2 to Chevron Corporation’s Current Report on Form 8-K filed February 3, 2020, and incorporated herein by reference.

10.13+ Form of Stock Appreciation Rights Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.13 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 201 9 , and incorporated herein by reference.

10.14+ Form of Performance Share Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed February 1, 2021, and incorporated herein by reference.

10.15+ Chevron Corporation Deferred Compensation Plan for Management Employees, filed as Exhibit 10.5 to Chevron Corporation’s Current Report on Form 8-K filed December 13, 2005, and incorporated herein by reference.

10.15+ Chevron Corporation Deferred Compensation Plan for Management Employees II, amended and restated effective October 2, 2023, filed as Exhibit 10.

1 to Chevron Corporation’s Quarterly Report on Form 10- Q for the quarter ended September 30, 2023 , and incorporated herein by reference.

10.16+ Chevron Corporation Retirement Restoration Plan, amended and restated effective October 2, 2023, filed as Exhibit 10.

10.16+ Chevron Corporation Deferred Compensation Plan for Management Employees II, amended and restated effective October 2, 2023, filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2023, and incorporated herein by reference.

10.17+ Chevron Corporation Retirement Restoration Plan, amended and restated effective August 1, 2024, filed as Exhibit 10.2 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 202 4 , and incorporated herein by reference.

10.18+ Chevron Corporation ESIP Restoration Plan, Amended and Restated as of August 1, 20 24 , filed as Exhibit 10.

3 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 20 24 , and incorporated herein by reference.

10.17+ Chevron Corporation ESIP Restoration Plan, Amended and Restated as of January 1, 2018, filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017, and incorporated herein by reference.

10.19+ Agreement between Chevron Corporation and R.

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10.20+ Agreement between Chevron Corporation and R.

Hewitt Pate, dated De cember 13, 2018 .

10.20+ Amended and Restated Aircraft Time-Sharing Agreement, dated as of April 1, 2020, between Chevron U.S.A.

Hewitt Pate, dated December 13, 201 8 , filed as Exhibit 10.19 to Chevron Corporation ’ s Annual Report on Form 10-K for the year ended December 31, 2023, and incorporated her ein by reference .

10.21+* Amended and Restated Aircraft Time-Sharing Agreement, dated as of November 16, 2024 , between Chevron U.S.A.

and Michael K.

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, amended and restated effective October 2, 2023, filed as Exhibit 10.

4 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2023, and incorporated herein by reference.

10.22+ 2022 Long-Term Incentive Plan of Chevron Corporation, amended and restated effective October 2, 2023, filed as Exhibit 10.4 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2023, and incorporated herein by reference.

10.23+ 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 (s hare 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 (share 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.

10.25+ 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.

10.26+ 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.

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10.36+ Form of Stock Appreciation Right Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.9 to Chevron Corporation’s Current Report on Form 8-K filed February 2, 2024, and incorporated herein by reference.

10.38+ General Release and Separation Agreement, dated February 15, 2023, by and between Chevron Corporation and James W.

Johnson , filed as Exhibit 10.30 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2022 and incorporated herein by reference.

19* Insider Trading Policies and Procedures.

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Rule 13a-14(b)/15d-14(b) Certification by the company’s Chief Financial Officer (page E-6).

Chevron Corporation Dodd-Frank Clawback Policy.

Chevron Corporation Dodd-Frank Clawback Policy , filed as Exh i bit 97.1 to Ch ev ron Corporation ’ s Annual Report on Form 10-K for the year ended December 31, 2023, and incorporated herein by r eference .

99.1* Definitions of Selected Energy and Financial Terms (pages E-7 through E-10).

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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 26th day of February, 2024.

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 26th day of February, 2024.

Principal Executive Officer

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Principal Financial Officer

/s/ PIERRE R.

Breber, Vice President

/s/ EIMEAR P.

Bonner, Vice President

and Chief Financial 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