What changed in this filing

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Item 9A. Controls and Procedures

2026-02-24 compared with 2025-02-21 · 707 added, 512 removed, 3261 unchanged (27% 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, 2025.

The company excluded Hess from our assessment of internal control over financial reporting as of December 31, 2025, because it was acquired by the company in a business combination during 2025.

Total assets and total revenues of Hess, a

wholly-owned subsidiary of Chevron Corporation, represent 24 percent and 3 percent, respectively, of the related consolidated financial statement amounts as of and for the period ended December 31, 2025.

The effectiveness of the company’s internal control over financial reporting as of December 31, 2025, 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 26, 2025 .

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.

Wirth’s plan provides for the potential exercise of vested stock options and the associated sale of up to 262,900 shares of Chevron common stock between March 2, 2026 and February 26, 2027 .

Bonner , Chief Financial Officer , entered into a pre-arranged stock trading plan on November 22, 2025 .

Bonner’s plan provides for the potential exercise of vested stock options and the associated sale of up to 132,768 shares of Chevron common stock between February 27, 2026 and February 26, 2027 .

Hewitt Pate , Chief Legal Officer , entered into a pre-arranged stock trading plan on November 26, 2025 .

Pate’s plan provides for the potential exercise of vested stock options and the associated sale of up to 335,509 shares of Chevron common stock between February 27, 2026 and February 26, 2027 .

The trading plans were entered into during an open insider trading window and are 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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Information about our Executive Officers at February 24, 2026

Members of the Corporation’s Executive Committee are the Executive Officers of the Corporation:

The Corporation’s executive officers are shown in the table below:

Name Age Current and Prior Positions (up to five years) Primary Areas of Responsibility

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Chief Executive Officer

Bonner 50 Vice President (since Aug 2021);

Chief Financial Officer (since Mar 2024)

Bonner* 51 Chief Financial Officer (since Mar 2024)

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

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

Midstream - Worldwide;

Asset Performance and Process Safety

Health, Safety and Environment;

Supply Chain Management

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

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 - Sep 2023)

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

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

Global Reserves;

Facilities Designs and Solutions;

Ryder Booth* 57 Chief Technology and Engineering Officer (since Jul 2025)

Vice President, Midcontinent (Aug 2021 - Jun 2025)

Reserves and Storage;

Facilities Engineering;

Capital Projects;

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Information Technology;

Operations and Turnarounds;

Asset Retirement;

Environmental Management;

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

Health, Safety and Environment;

Supply Chain Management

Gustavson* 53 President, New Energies (since Aug 2021)

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

Power for Data Centers;

Artificial Intelligence

Hewitt Pate* 63 Chief Legal Officer (since Aug 2009) Law, Governance and Compliance

Robert Clay Neff 63 President, Upstream (since Jul 2025)

President, Chevron International Exploration and Production (Oct 2022 - Jul 2025)

President, Chevron Middle East, Africa, South America Exploration and Production Company (Nov 2019 - Oct 2022) Upstream - Worldwide Exploration and Production;

Andy Walz 58 President, Downstream, Midstream & Chemicals (since Oct 2024)

President, Americas Products (Oct 2019 - Oct 2024) Downstream - Worldwide Manufacturing, Marketing, Lubricants, and Chemicals;

*Member of the Corporation’s Executive Committee

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 2026 Annual Meeting of Stockholders and 2026 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act in connection with the company’s 2026 Annual Meeting (the 2026 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 2026 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 2025 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 2026 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 2026 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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Financial Instruments - Credit Losses

Acquisition of PDC Energy, Inc.

Agreement to Acquire Hess Corporation

Acquisition of Hess Corporation

Supplemental Information on Oil and Gas Producing Activities

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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, Singapore, South Korea, Thailand, the United Kingdom, the United States and Venezuela.

Angola, Argentina, Australia, Bangladesh, Brazil, Canada, China, Egypt, Equatorial Guinea, Guyana, Israel, Kazakhstan, Malaysia, 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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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 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.

and California’s Low Carbon Fuel Standard;

programs that price GHG emissions, including

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

California’s Cap-and-Trade Program;

performance standards, including methane-specific 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.

Inflation Reduction Act.

Some of these policies and programs include renewable and low carbon fuel standards;

programs that price GHG emissions;

performance standards;

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

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

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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 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.

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

These policies have the potential to enable opportunities for Chevron in its oil and gas and lower carbon business lines.

Although we expect the company’s costs to comply with these policies and

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

programs to continue to increase, these costs currently do not have a material impact on the company’s financial condition or results of operations.

Significant uncertainty remains as to the pace and extent to which a lower carbon future progresses, which is dependent, in part, on substantial advancements and changes in policy, technology, and customer and consumer preferences.

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

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

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

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

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

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

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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 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.

Chevron aims to grow its oil and gas business, lower the carbon intensity of operations and grow new energies businesses.

To grow new energies businesses, Chevron plans to leverage 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.

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

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;

Chevron regularly evaluates its aspirations, targets and goals.

The company has changed and/or eliminated some of these aspirations, targets and goals and may continue to do so in the future 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.

For its aspiration to achieve net zero for upstream production Scope 1 and 2 GHG emissions on an equity basis by 2050, many of the necessary advancements in technology, policy and collective action have not occurred.

As a result, Chevron is not on track to achieve the aspiration by 2050.

While Chevron continues to have the aspiration, it will no longer use 2050 as a timeline.

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 and persist.

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;

(1) sufficient and substantial advances in technology, including 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;

(3) successful generation, acquisition, retirement and accounting of cost-effective, verifiable carbon offsets from nature-based solutions or carbon capture and storage;

(4) the availability of suppliers that can meet sustainability-related standards;

(5) evolving regulatory requirements 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.

and (8) actions taken by the company’s competitors.

Please refer to “Risk Factors” in Part I, Item 1A, on pages 25 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, 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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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 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.

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.

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 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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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 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 applied inflation mitigation strategies to temper cost increases, including fixed price and index-based contracts.

Lead times for key capital equipment remain long due to strong demand levels.

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.

Risk Factors for a discussion of some of the inherent risks that could materially impact the company’s results of operations or financial condition.

The offshore market remains competitive for vessels and subsea equipment.

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

In 2025, the U.S.

announced the imposition of various changing tariffs on imports from our trade partners.

The tariff impact in 2025 was less than one percent of the company’s third party spend and was not material to the company’s financial results.

In first quarter 2026, the company continued to work with partners across its supply chain to identify alternative sourcing options and mitigate the impact of the tariffs.

Although the U.S.

Supreme Court struck down some global tariffs in February 2026, there remains significant uncertainty as to the duration and magnitude of any future tariffs that may be imposed as permitted under U.S.

laws and, accordingly, as to the resultant impacts these tariffs could have on the company and its suppliers and the company’s future results of operations.

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.

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

From 2024 through January 2026, the company has generated approximately $9 billion of asset sales proceeds.

Looking ahead, the company expects $1-2 billion in annual asset sale proceeds through 2030.

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

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In 2025, the company spent $297 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.

To the extent the current owners of the company’s previously divested assets default on their decommissioning obligations, regulators

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

may require that Chevron assume such obligations.

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

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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.

In July 2025, the company completed its acquisition of Hess Corporation (Hess).

Refer to Note 29.

Agreement to Acquire Hess Corporation for additional information.

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

Acquisition of Hess Corporation for additional information.

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, natural gas and natural gas liquids (NGLs).

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.

The company has announced plans to achieve $3-4 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:

In 2025, the company delivered $1.5 billion in structural cost savings, with $2 billion achieved in the annual run rate.

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

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

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The longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to 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 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 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 has been conducting limited activities in Venezuela consistent with authorizations issued by the United States government.

The financial results for Chevron’s business in Venezuela have been 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.

Following the issuance of a general license and other authorizations, crude oil liftings in Venezuela restarted in 2023.

Chevron maintained its presence in Venezuela consistent with the U.S.

government sanctions policy, and pursuant to this policy, continued delivering limited crude oil to the U.S.

from these affiliates through January 2026.

Based on recently revised authorizations that align with current U.S.

sanctions policy for Venezuela, Chevron will continue delivery of crude oil produced from its Venezuelan assets to the U.S.

and to the international market.

Current geopolitical developments relating to Venezuela could have an impact on the company’s operations in Venezuela and, as a result, impact the company’s future results of operations.

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.

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

The financial impacts of such risks remain uncertain.

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

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.

The conflict between Israel and various regional adversaries has not significantly impacted the company’s operations, with the company continuing to maintain safe and reliable operations while meeting its contractual commitments.

The company continues to monitor the potential for further conflict in the region, and any future impacts 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.

Henry Hub natural gas.

The Brent price averaged $81 per barrel for the full-year 2024, compared to $83 in 2023.

The Brent price averaged $69 per barrel for the full-year 2025, compared

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to $81 in 2024.

As of mid-February 2026, the Brent price was $70 per barrel.

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

Crude prices were lower in 2025 driven by supply growth in non-OPEC countries and slowing demand despite impacts from geopolitical conflicts and OPEC+ supply decisions.

Platts (crude) & Energy Intelligence (natural gas)

Henry Hub natural gas price averaged $3.53 per thousand cubic feet (MCF) for the full-year 2025, compared to $2.25 in 2024.

As of mid-February 2026, the Henry Hub price was $3.43 per MCF.

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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, 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.

In the U.S., higher Henry Hub prices were driven by higher weather-driven demand in the U.S.

and increasing liquefied natural gas (LNG) export demand.

Outside the United States, prices for natural gas also depend on regional supply and demand, regulatory circumstances and infrastructure conditions in local markets.

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.

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.

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

Production The company’s worldwide net oil-equivalent production in 2025 was 3.7 million barrels per day, 12 percent higher than in 2024 primarily due to the acquisition of Hess and growth in TCO, the Permian Basin and the Gulf of America, which were partly offset by the impacts of asset sales.

About 21 percent of the company’s net oil-equivalent production in 2025 occurred in OPEC+ member countries of Equatorial Guinea, Kazakhstan, Malaysia, Nigeria and the Partitioned Zone between Saudi Arabia and Kuwait.

The company estimates its net oil-equivalent production in 2026 to increase 7 to 10 percent over 2025, assuming a Brent crude oil price of $60 per barrel and excluding expected asset sales.

This includes a full year contribution from Hess assets.

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

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.

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

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*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.

Proved Reserves Net proved reserves for consolidated companies and affiliated companies totaled 10.6 billion barrels of oil-equivalent at year-end 2025, an increase from year-end 2024.

The reserve replacement ratio in 2025 was 158 percent.

The 5 and 10 year reserve replacement ratios were 91 percent and 95 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 2023 and each year-end from 2023 through 2025, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2025.

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

Refer to the “Results of Operations” section on pages 42 through 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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Chevron operates or has significant ownership interests in refineries in each of these areas.

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

Refer to the “Results of Operations” section on page 43 for additional discussion of the company’s downstream operations.

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Key noteworthy developments and other events during 2025 and early 2026 included the following:

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.

Angola Achieved first oil from the South N’dola platform, leveraging existing infrastructure.

Argentina Exercised option to participate in the Vaca Muerta Sur Pipeline Project to export crude from the Vaca Muerta shale to a new export terminal.

Australia Reached final investment decision (FID) on the Gorgon backfill development to connect the Geryon and Eurytion fields to existing infrastructure, enabling long-term supply of domestic gas in Western Australia and LNG in Asia.

Brazil Secured nine offshore blocks in the Foz do Amazonas Basin.

Guinea-Bissau Secured two frontier exploration blocks (Blocks 5B and 6B).

Guyana Achieved first oil at Yellowtail, the fourth development in the offshore Stabroek Block, and reached FID on the Hammerhead project, the seventh development.

Israel Reached FID on the Leviathan Gas Expansion project, which is expected to increase production capacity to 2.1 billion cubic feet per day and support increased exports to Egypt.

Kazakhstan Started production at the Future Growth Project and ramped up total production to approximately 1 million barrels of oil-equivalent per day at Tengiz.

Malaysia/Thailand JDA Completed the sale of the company’s interest in the Malaysia-Thailand Joint Development Area.

Namibia Secured exploration blocks in Petroleum Exploration License 82 (Blocks 2112B and 2212A) in Walvis Basin.

Nigeria Discovered hydrocarbons in two exploration and appraisal wells in the Delta South-AA in Petroleum Mining Lease 46 and the Awodi-07 in Petroleum Prospecting License 263 in shallow offshore water.

Peru Secured three offshore exploration blocks (Blocks Z-61, Z-62, and Z-63) in the Trujillo Basin.

Republic of Congo Completed the sale of the company’s interest in the Republic of Congo.

Suriname Secured two shallow water blocks (Blocks 9 and 10).

United States Completed the acquisition of Hess, creating a combined company with a premier upstream portfolio and achieving the initial run-rate synergy target of $1 billion.

United States Started and ramped up production at the Anchor, Ballymore, Stampede, and Whale fields in the deepwater Gulf of America.

United States Grew production in the Permian Basin by more than 10 percent with lower Capex compared to the prior year, reaching one million barrels of oil equivalent per day.

United States Discovered oil at the non-operated Far South well in the deepwater Gulf of America and secured additional exploration blocks in the Gulf of America.

United States Completed the sale of a portion of its interest in certain gas assets in East Texas and the sale of certain non-operated midstream pipelines and facilities.

United States Started production from the Geismar renewable diesel plant in Louisiana after completing an expansion that increased capacity from 7,000 to 22,000 barrels per day.

United States Entered the U.S.

lithium sector and acquired approximately 135,000 net acres in the Smackover Formation in Northeast Texas and Southwest Arkansas for direct lithium extraction.

United States Announced plans to provide power solutions to support U.S.

data center growth, with the first project under development in West Texas.

United States Achieved the highest U.S.

refinery throughput in 20 years through recent expansion projects and efficiency improvements.

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

Common Stock Dividends The 2025 annual dividend was $6.84 per share, making 2025 the 38th consecutive year that the company increased its annual per share dividend payout.

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.

In January 2026, the company’s Board of Directors increased its quarterly dividend by $0.07 per share, approximately four percent, to $1.78 per share payable in March 2026.

Common Stock Repurchase Program The company repurchased $12.1 billion of its common stock in 2025 under its stock repurchase program.

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

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.

upstream earnings decreased by $1.8 billion, primarily due to lower liquids realizations of $2.4 billion, higher operating expenses of $2.0 billion, and higher depreciation, depletion and amortization of $1.4 billion, partly offset by higher sales volumes of $2.8 billion, and higher natural gas realizations of $800 million.

All figures are inclusive of Hess.

Net oil-equivalent production was up 259,000 barrels per day, or 16 percent, primarily due to the acquisition of Hess and higher production in the Permian Basin and the Gulf of America.

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 $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 downtime at TCO and Nigeria, and withdrawal from Myanmar, partly offset by entitlement effects.

International upstream earnings decreased by $4.0 billion, primarily due to higher DD&A of $2.8 billion, lower realizations of $2.0 billion, an unfavorable foreign currency effect of $803 million between periods, and the absence of prior year favorable asset sales impacts of $260 million, partly offset by higher liftings of $2.2 billion, and lower operating expenses of $470 million.

All figures are inclusive of Hess.

Net oil-equivalent production was up 126,000 barrels per day, or 7 percent.

The increase was primarily due to the acquisition of Hess and higher production at TCO in Kazakhstan, partly offset by impacts from asset sales in Canada and the Republic of Congo.

2025 2024 2023

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* MBD — thousands of barrels per day.

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.

downstream earnings increased by $844 million, primarily due to lower operating expenses of $730 million and higher margins on refined product sales of $580 million, partly offset by lower earnings from the 50 percent-owned Chevron Phillips Chemical Company of $440 million.

Refinery crude unit inputs were up 121,000 barrels per day, or 13 percent, primarily due to increased capacity at the Pasadena, Texas refinery upon completion of the Light Tight Oil project.

Refined product sales were up 31,000 barrels per day, or 2 percent, compared to the year-ago period.

International Downstream

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2 MBD — thousands of barrels per day.

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.

International downstream earnings increased by $451 million, primarily due to higher margins on refined product sales of $440 million and the absence of prior year impairments of $185 million, partly offset by foreign currency effects, which had an unfavorable impact on earnings of $174 million between periods.

Refinery crude unit inputs were up 6,000 barrels per day, or 1 percent from the year-ago period.

Refined product sales were down 11,000 barrels per day, or 1 percent from the year-ago period.

Unit 2025 2024 2023

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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 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

Net charges increased by $877 million, primarily due to higher interest expense, and higher pension settlement and curtailment costs.

Consolidated Statement of Income

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Sales and other operating revenues $ 184,432 $ 193,414 $ 196,913

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.

Sales and other operat ing revenues decreased in 2025 mainly due to lower crude oil and refined product prices, partially offset by higher crude oil and refined product sales volumes and higher natural gas prices and volumes.

Millions of dollars 2025 2024 2023

Income (loss) from equity affiliates $ 3,000 $ 4,596 $ 5,131

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).

Income from equity affiliates decreased in 2025 mainly due to lower upstream-related earnings from Tengizchevroil LLP (TCO) in Kazakhstan as higher liftings from the FGP project were more than offset by higher depreciation, depletion and amortization and lower realizations, and lower downstream-related earnings from CPChem primarily due to lower chemicals margins.

These decreases were partially offset by higher downstream-related earnings from GS Caltex in South Korea.

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

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Other income (loss) $ 1,599 $ 4,782 $ (1,095)

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.

Other income decreased in 2025 mainly due to the absence of before tax gains on asset sales in Canada, an unfavorable swing in foreign currency effects, and lower income from Venezuela.

Millions of dollars 2025 2024 2023

Purchased crude oil and products $ 108,214 $ 119,206 $ 119,196

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.

Purchased crude oil and products decreased in 2025 due to lower crude oil and refined product prices and volumes, partially offset by higher natural gas prices and volumes.

Millions of dollars 2025 2024 2023

Operating, selling, general and administrative expenses $ 33,131 $ 32,298 $ 29,028

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.

Operating, selling, general and administrative expenses increased compared to last year primarily due to the acquisition of Hess and higher professional service costs, partially offset by lower severance accruals.

Millions of dollars 2025 2024 2023

Exploration expense $ 1,051 $ 995 $ 914

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

Exploration expenses in 2025 were relatively flat compared to last year.

Millions of dollars 2025 2024 2023

Depreciation, depletion and amortization $ 20,132 $ 17,282 $ 17,326

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

Depreciation, depletion and amortization expenses increased in 2025 primarily due to higher production and higher rates.

Millions of dollars 2025 2024 2023

Taxes other than on income $ 5,230 $ 4,716 $ 4,220

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

Taxes other than on income increased in 2025 primarily due to higher excise taxes related to downstream activities.

Millions of dollars 2025 2024 2023

Interest and debt expense $ 1,217 $ 594 $ 469

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

Interest and debt expenses increased in 2025 mainly due to higher debt balances, including debt assumed from the acquisition of Hess.

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

Millions of dollars 2025 2024 2023

Other components of net periodic benefit costs $ 313 $ 195 $ 212

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

Other components of net periodic benefit costs increased in 2025 primarily due to higher settlement and curtailment losses, partially offset by higher expected return on plan assets.

Millions of dollars 2025 2024 2023

Income tax expense (benefit) $ 7,258 $ 9,757 $ 8,173

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.

The decrease in income tax expense in 2025 of $2.5 billion was primarily due to the decrease in total income before tax for the company of $7.8 billion, along with the absence of the tax impacts of the asset sales in Canada.

The decrease in income before taxes for the company was primarily the result of higher upstream depreciation, depletion and amortization, lower upstream realizations, unfavorable foreign exchange impacts, and higher operating costs, partially offset by higher upstream sales volumes and higher downstream margins.

income before tax decreased from $8.1 billion in 2024 to $6.0 billion in 2025.

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.

This $2.1 billion decrease in income was primarily driven by lower upstream realizations, higher upstream depreciation, depletion and amortization and higher operating expenses, partially offset by higher upstream sales volumes and higher downstream margins.

The decrease of $337 million in U.S.

income tax expense between year-over-year periods, from $1.9 billion in 2024 to $1.6 billion in 2025, was primarily driven by the decrease in income before tax, partially offset by current period unfavorable tax items.

International income before tax decreased from $19.5 billion in 2024 to $13.8 billion in 2025.

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.

This $5.7 billion decrease in income was primarily driven by higher upstream depreciation, depletion and amortization, lower upstream realizations, unfavorable foreign exchange impacts and the absence of impacts related to the asset sales in Canada, partially offset by higher upstream sales volumes.

The decrease of $2.2 billion in international income tax expense between year-over-year periods, from $7.9 billion in 2024 to $5.7 billion in 2025, was primarily driven by the decrease in income before tax, along with the absence of tax impacts of the asset sales in Canada.

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

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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 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.

Cash provided by operating activities in 2025 was $33.9 billion, compared to $31.5 billion in 2024, primarily as higher cash distributions from TCO and contributions from legacy Hess assets more than offset the impact of lower commodity prices.

Between January and March 2025, Chevron purchased 15.38 million shares of Hess common stock in open market transactions for approximately $2.2 billion.

Cash provided by operating activities was net of contributions to employee pension plans of approximately $588 million in 2025 and $844 million in 2024.

Capital expenditures totaled $17.3 billion in 2025 compared to $16.4 billion in 2024.

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.

Proceeds and deposits related to asset sales and return of investments totaled $1.8 billion in 2025 compared to $7.7 billion in 2024.

Net repayment (borrowing) of loans by equity affiliates included an inflow of $778 million in 2025 mainly due to a loan repayment from TCO, compared with an outflow of $233 million in the year ago period.

Restricted cash of $1.0 billion and $1.5 billion at December 31, 2025 and 2024, 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.

These amounts are generally associated with upstream decommissioning activities and tax payments.

The decrease of restricted cash in 2025 is mainly due to the release of funds for tax-deferred exchanges.

Dividends Dividends paid to common stockholders were $12.8 billion in 2025 and $11.8 billion in 2024.

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.

Debt and Finance Lease Liabilities Total debt, including finance lease liabilities, was $40.8 billion at December 31, 2025, up from $24.5 billion at year-end 2024.

In 2025, the company issued $11.2 billion of public bonds, retired $4.0 billion of public bonds at maturity and reduced commercial paper balances.

In third quarter 2025, the company also assumed $10.0 billion of debt and finance lease liabilities as part of the acquisition of Hess, including approximately $3.7 billion related to Hess Midstream Operations LP that is non-recourse to Chevron Corporation.

The company’s total debt due within one year, consisting primarily of the current portion of long-term debt and redeemable long-term obligations, totaled $10.9 billion at December 31, 2025, compared with $12.7 billion at year-end 2024.

Of these amounts, $9.9 billion and $8.25 billion were reclassified to long-term debt at the end of 2025 and 2024, 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 $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 had $4.6 billion of commercial paper outstanding as of December 31, 2025, compared with $5.4 billion at December 31, 2024.

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.

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Billions of dollars

Hess stock purchase

Stock repurchases

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Billions of dollars

Affiliate capital expenditure

Affiliate capital expenditures

Billions of dollars

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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

*Refer to page 52 for calculations of debt and debt ratios

Debt coverage ratios

Debt-to-CFFO*

Net debt-to-CFFO*

*Refer to page 52 for calculations of debt and debt ratios

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, CUSA, Noble Energy, Inc.

(Noble), and Texaco Capital Inc.

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

(Noble), Texaco Capital Inc., and Hess Corporation.

The securities that are the obligation of, or guaranteed by, Chevron Corporation carry an AA- rating by Standard and Poor’s Corporation and an Aa2 rating by Moody’s Investors Service.

The company’s U.S.

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Financial information for non-guarantor entities has been excluded.

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,

Year ended December 31,

(Millions of dollars) (unaudited)

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As of December 31, 2025, the company had purchased a total of 250.8 million shares for $38.5 billion excluding excise taxes, resulting in $36.5 billion remaining under the 2023 Program.

Chevron expects share repurchases in the first quarter of 2026 to be between $2.5-$3.0 billion.

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 $ 10,929 $ 6,418 $ 17,347 $ 11,330 $ 5,118 $ 16,448 $ 11,729 $ 4,100 $ 15,829

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.

Capex for 2025 was $17.3 billion, 5 percent higher than 2024 as spend on legacy Hess assets post-acquisition and increased investments in U.S.

data center power solutions more than offset lower spend in the downstream segment.

The company estimates that 2026 organic capex will range from $18 to $19 billion.

Upstream Capex is projected at $17 billion, including nearly $6 billion for U.S.

shale and tight assets in the Permian, DJ and Bakken basins, and about $7 billion for global offshore developments, primarily supporting growth in Guyana, Eastern Mediterranean and Gulf of America.

Downstream Capex is expected to be around $1 billion, with nearly three-fourths allocated to the U.S.

About $1 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.

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Affiliate Capex $ 795 $ 1,005 $ 1,800 $ 802 $ 1,647 $ 2,449 $ 983 $ 2,551 $ 3,534

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 for 2025 was $1.8 billion, 27 percent lower than 2024 mainly due to lower spend at TCO’s Wellhead Pressure Management Project (WPMP) and Future Growth Project (FGP).

Affiliate Capex is expected to range between $1.3 to $1.7 billion in 2026.

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

Nearly half of this amount is allocated to CPChem’s two major integrated polymer projects, while TCO’s budget accounts for roughly one-fourth.

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

Noncontrolling Interests The company had noncontrolling interests of $839 million at December 31, 2024, and $972 million at December 31, 2023.

Noncontrolling Interests The company had noncontrolling interests of $5.7 billion at December 31, 2025, including non-controlling interest in Hess Midstream LP (HESM), and $839 million at December 31, 2024.

Distributions to noncontrolling interests net of contributions totaled $323 million and $195 million in 2025 and 2024, respectively.

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The aggregate amount of interest due on these obligations, excluding leases, is:

after 2029 – $4,355.

2026 – $1.6 billion;

2027 – $1.4 billion;

2028 – $1.2 billion;

2029 – $1.1 billion;

2030 – $915 million;

after 2030 – $6.0 billion.

Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements Information related to these off-balance sheet matters is included in Note 24 Other Contingencies and Commitments , under the heading “Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements.”

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Interest Coverage Ratio 15.1 36.5 49.0

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

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

Year ended December 31

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Free Cash Flow $ 16,592 $ 15,044 $ 19,780

Adjusted Free Cash Flow Free cash flow excluding operating working capital impacts, plus proceeds and deposits related to asset sales and returns of investments, plus net repayments (borrowings) of loans by equity affiliates, which represents the total cash available to creditors and investors after investing in the business excluding the timing impacts of working capital.

The company believes the preceding free cash flow measures are useful to monitor the financial health of the company and its performance over time.

Year ended December 31

Millions of dollars 2025 2024 2023

Net cash provided by operating activities $ 33,939 $ 31,492 $ 35,609

Capital expenditures 17,347 16,448 15,829

Free Cash Flow $ 16,592 $ 15,044 $ 19,780

Net decrease (increase) in operating working capital (1,008) 1,211 (3,185)

Proceeds and deposits related to asset sales and returns of investment 1,826 7,704 669

Net repayment (borrowing) of loans by equity affiliates 778 (233) (302)

Adjusted Free Cash Flow $ 20,204 $ 21,304 $ 23,332

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

Debt Ratio Total debt as a percentage of total debt plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage.

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Debt Ratio 17.9 % 13.9 % 11.5 %

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, 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.

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Long-term debt 39,781 20,135 20,307

24,541 20,836 23,339

Total debt 40,758 24,541 20,836

Cash and cash equivalents 6,293 6,781 8,178

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Marketable securities — — 45

Total adjusted debt 17,756 12,613 5,438

Total net debt 34,461 17,756 12,613

Total Chevron Corporation Stockholders’ Equity

186,450 152,318 160,957

Total adjusted debt plus total Chevron Corporation Stockholders’ Equity $ 170,074 $ 173,570 $ 164,720

Total net debt plus total Chevron Corporation Stockholders’ Equity $ 220,911 $ 170,074 $ 173,570

Net Debt Ratio 15.6 % 10.4 % 7.3 %

Debt-to-CFFO The sum of total debt divided by CFFO, which measures the company’s ability to cover its debt using the cash it generates from operations.

At December 31

Millions of dollars 2025 2024 2023

Short-term debt $ 977 $ 4,406 $ 529

Long-term debt 39,781 20,135 20,307

Total debt 40,758 24,541 20,836

Net cash provided by operating activities (CFFO) 33,939 31,492 35,609

Debt-to-CFFO 1.2x 0.8x 0.6x

Net Debt-to-CFFO The sum of total debt less cash and cash equivalents, time deposits and marketable securities, divided by CFFO, which measures the company’s ability to cover its net debt using the cash it generates from operations.

The company believes the preceding debt measures are useful to monitor the strength of the company’s balance sheet.

At December 31

Millions of dollars 2025 2024 2023

Short-term debt $ 977 $ 4,406 $ 529

Long-term debt 39,781 20,135 20,307

Total debt 40,758 24,541 20,836

Cash and cash equivalents 6,293 6,781 8,178

Time deposits 4 4 —

Marketable securities — — 45

Total net debt 34,461 17,756 12,613

Net cash provided by operating activities (CFFO) 33,939 31,492 35,609

Net Debt-to-CFFO 1.0x 0.6x 0.4x

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

Capital Employed The sum of Chevron Corporation Stockholders’ Equity, total debt and noncontrolling interests, which represents the net investment in the business.

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Risk Factors .

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

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

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

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

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

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The change in fair value of Chevron’s derivative commodity instruments in 2025 was not material to the company’s results of operations.

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

The company uses the Monte Carlo simulation method as its Value-at-Risk (VaR) model to estimate the maximum potential loss in fair value, at the 95 percent confidence level with a one-day holding period, from the effect of adverse changes in market conditions on derivative commodity instruments held or issued.

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The liability balance of approximately $15.0 billion for asset retirement obligations at year-end 2025 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.

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

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

Suspended Wells Information related to suspended wells is included in Note 21 Accounting for Suspended Exploratory Wells .

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Using definitions and guidelines established by the American Petroleum Institute, Chevron estimated its worldwide environmental spending in 2025 at approximately $2.8 billion for its consolidated companies.

Included in these expenditures were approximately $0.6 billion of environmental capital expenditures and $1.9 billion of costs associated

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

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

Included in these expenditures were approximately $0.8 billion of environmental capital expenditures and $2.0 billion of costs associated with the prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites, and the decommissioning and restoration of sites.

For 2026, total worldwide environmental capital expenditures are estimated at $0.7 billion.

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Such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities.

Estimates and assumptions are based on management’s experience and other information available prior to the issuance of the financial statements.

Estimates and assumptions are based on management’s experience and other information available prior to

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

the issuance of the financial statements.

Materially different results can occur as circumstances change and additional information becomes known.

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Refer to Table V , “Proved Reserve Quantity Information,” for the changes in proved reserve estimates for each of the three years ended December 31, 2023, 2024 and 2025, and to Table VII , “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” for estimates of proved reserve values for each of the three years ended December 31, 2023, 2024 and 2025.

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

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

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

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

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

commodity chemicals and refined products.

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

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and the related underlying assumptions.

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

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

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For the 10 years ended December 31, 2025, actual asset returns averaged 6.0 percent for this plan.

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.

Additionally, with the exception of three years within this 10-year period, actual asset returns for this plan equaled or exceeded 7.1 percent during each year.

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

Total pension expense for 2025 was $677 million.

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A one percent increase in the discount rates for this same plan would have reduced pension expense for 2025 by approximately $175 million.

The aggregate funded status recognized at December 31, 2024, was a net liability of approximately $0.8 billion.

The aggregate funded status recognized at December 31, 2025, was a net liability of approximately $70 million.

An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan.

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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 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.

pension plan, which accounted for about 56 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $247 million, and would have increased the plan’s surplus from $804 million to $1.1 billion.

For the company’s OPEB plans, expense for 2025 was $88 million, and the total liability, all unfunded at the end of 2025, was $2.0 billion.

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In addition, information related to company contributions is included on page 101 in Note 23 Employee Benefit Plans under the heading “Cash Contributions and Benefit Payments.”

Business Combinations – Purchase-Price Allocation Accounting 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 Hess Corporation .

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.

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

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

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

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.

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, 2025.

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

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

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

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

impact on the company’s consolidated financial statements and financial or operational performance in any given period” in Item 1A.

Risk Factors , on page 27.

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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, 2025.

The company excluded Hess from our assessment of internal control over financial reporting as of December 31, 2025 because it was acquired by the company in a business combination during 2025.

Total assets and total revenues of Hess, a wholly-owned subsidiary, represent 24 percent and 3 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2025.

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Bonner Alana K.

Chairman of the Board Vice President Vice President

and Chief Executive Officer and Chief Financial Officer and Controller

Chairman of the Board Chief Financial Officer Controller

and Chief Executive Officer

February 24, 2026

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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 Hess Corporation (Hess) from its assessment of internal control over financial reporting as of December 31, 2025 because it was acquired by the Company in a purchase business combination during 2025.

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

Hess is a wholly-owned subsidiary of Chevron Corporation whose total assets and total revenues represent 24 percent and 3 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2025.

Financial Table of Contents

Definition and Limitations of Internal Control over Financial Reporting

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

Financial Table of Contents

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

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Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments.

The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments.

The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

The Impact of Proved Developed Crude Oil and Natural Gas Reserves on Upstream Property, Plant, and Equipment, Net

As described in Notes 1 and 18 to the consolidated financial statements, the Company’s upstream property, plant and equipment, net balance was $129.1 billion as of December 31, 2024, and depreciation, depletion and amortization expense was $15.5 billion for the year ended December 31, 2024.

As described in Notes 1 and 18 to the consolidated financial statements, the Company’s upstream property, plant and equipment, net balance was $200.8 billion as of December 31, 2025, and the related depreciation, depletion and amortization expense was $18.4 billion for the year ended December 31, 2025, the majority of which related to proved developed crude oil and natural gas reserves.

The Company follows the successful efforts method of accounting for crude oil and natural gas exploration and production activities.

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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.

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

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

The principal considerations for our determination that performing procedures relating to the impact of proved developed crude oil and natural gas reserves on upstream property, plant, and equipment, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved developed crude oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved developed crude oil and natural gas reserves.

The principal considerations for our determination that performing procedures relating to the impact of proved developed crude oil and natural gas reserves on upstream property, plant, and equipment, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved developed crude oil and natural gas reserves, which are derived using historical production volumes and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, specifically historical production volumes, methods, and assumptions used by management and its specialists in developing the estimates of proved developed crude oil and natural gas reserves.

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

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

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

These procedures included testing the effectiveness of controls

Financial Table of Contents

relating to management’s estimates of proved developed crude oil and natural gas reserves.

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

As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed.

The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of data used by the specialists and an evaluation of the specialists’ findings related to estimated future production volumes by comparing the estimate to relevant historical and current period information, as applicable.

The procedures performed also included (i) evaluating the methods and assumptions used by the specialists;

(ii) testing the completeness and accuracy of the data used by the specialists related to historical production volumes;

and (iii) evaluating the specialists’ findings related to estimated future production volumes by comparing the estimate to relevant historical and current period production volumes, as applicable.

Acquisition of Hess - Valuation of Oil and Gas Properties

As described in Note 29 to the consolidated financial statements, on July 18, 2025, the Company acquired Hess and recorded estimated fair values of the acquired properties, plant and equipment of approximately $73.5 billion, of which a significant portion relates to oil and gas properties.

Oil and gas properties were valued using a discounted cash flow model that incorporated assumptions for commodity prices, future production volumes, operating costs, development costs, and risk-adjusted discount rates.

The principal considerations for our determination that performing procedures relating to the valuation of oil and gas properties acquired in the acquisition of Hess is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the fair value estimates of oil and gas properties acquired;

(ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to commodity prices, future production volumes, operating costs, development costs, and risk-adjusted discount rates;

and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

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

These procedures included testing the effectiveness of controls relating to the acquisition accounting, including controls over the valuation of oil and gas properties acquired.

These procedures also included, among others (i) reading the acquisition agreement;

(ii) testing management’s process for developing the fair value estimates of oil and gas properties acquired;

(iii) evaluating the appropriateness of the discounted cash flow model;

(iv) testing the completeness and accuracy of underlying data used in the discounted cash flow model;

and (v) evaluating the reasonableness of the significant assumptions used by management related to commodity prices, future production volumes, operating costs, development costs, and risk-adjusted discount rates.

Evaluating the reasonableness of management’s assumption related to commodity prices involved comparing the prices to observable market data.

Evaluating the reasonableness of management’s assumptions relating to future production volumes, operating costs, and development costs involved evaluating whether the assumptions used by management were reasonable as compared to historical results of Hess.

Professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of the discounted cash flow model and the reasonableness of the risk-adjusted discount rates assumptions.

The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the future production volumes used in the discounted cash flow model.

As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed.

The procedures performed also included (i) evaluating the methods and assumptions used by the specialists;

(ii) testing the completeness and accuracy of the data used by the specialists;

and (iii) evaluating the specialists’ findings.

/s/ PricewaterhouseCoopers LLP

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Total Chevron Corporation Stockholders’ Equity 186,450 152,318

Noncontrolling interests (includes redeemable noncontrolling interest of $ 0 and $ 166 at December 31, 2024 and 2023)

Noncontrolling interests 5,726 839

Total Equity 192,176 153,157

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Acquisition of businesses, net of cash received 1,056 — 55

Acquisition of Hess Corporation common stock ( 2,225 ) — —

Capital expenditures ( 17,347 ) ( 16,448 ) ( 15,829 )

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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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Treasury stock transactions 541 — — — 541 — 541

Hess Corporation acquisition 11,775 — — 33,828 45,603 5,035 50,638

Net income (loss) — 12,299 — — 12,299 186 12,485

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When appropriate, the company’s share of the affiliate’s reported earnings is adjusted quarterly to reflect the difference between these allocated values and the affiliate’s historical book values.

Variable interest entity The company enters into certain arrangements with legal entities that are evaluated under ASC 810 to determine whether they represent variable interest entities (VIEs).

Hess Midstream LP (HESM) is Chevron’s only significant VIE.

The company had an approximately 38 percent consolidated ownership interest at December 31, 2025 in HESM, with the balance owned by public shareholders.

The company has concluded that it is the primary beneficiary of the VIE since it has the power to direct those activities that most significantly impact the economic performance of HESM, and is obligated to absorb losses and has the right to receive benefits that could potentially be significant to HESM.

This conclusion was based on a qualitative analysis that considered HESM’s governance structure, the commercial agreements between HESM and the company, and the voting rights established between the members.

Noncontrolling Interests Ownership interests in the company’s subsidiaries held by parties other than the parent are presented separately from the parent’s equity on the Consolidated Balance Sheet.

The amount of consolidated net income attributable to the parent and the noncontrolling interests are both presented on the face of the Consolidated Statement of Income and Consolidated Statement of Equity.

Included within noncontrolling interest is redeemable noncontrolling interest.

Fair Value Measurements The three levels of the fair value hierarchy of inputs the company uses to measure the fair value of an asset or a liability are as follows.

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Interest rate swaps related to floating-rate debt, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.

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

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

In the aggregate, these costs are below market.

“Materials, supplies and other” inventories are primarily stated at cost or net realizable value.

Where Chevron is a party to master netting

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

arrangements, fair value receivable and payable amounts recognized for derivative instruments executed with the same counterparty are generally offset on the balance sheet.

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

In the aggregate, these costs are below market.

“Materials, supplies and other” inventories are primarily stated at cost or net realizable value.

Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and production activities.

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The company has elected the short-term lease exception and therefore only recognizes right-of-use assets and lease liabilities for leases with a term greater than one year.

The company has elected the practical expedient to not separate non-lease components from lease components for most asset classes except for certain asset classes that have significant non-lease (i.e., service) components.

Where leases are used in joint ventures, the company recognizes 100 percent of the right-of-use assets and lease liabilities when the company is the sole signatory for the lease (in most cases, where the company is the operator of a joint venture).

Lease costs reflect only the costs associated with the operator’s working interest share.

The lease term includes the committed lease term identified in the contract, taking into account renewal and termination options that management is

The company has elected the practical

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

reasonably certain to exercise.

expedient to not separate non-lease components from lease components for most asset classes except for certain asset classes that have significant non-lease (i.e., service) components.

Lease costs reflect only the costs associated with the operator’s working interest share.

The lease term includes the committed lease term identified in the contract, taking into account renewal and termination options that management is reasonably certain to exercise.

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.

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The cumulative translation effects for those few entities, both consolidated and affiliated, using functional currencies other than the U.S.

dollar are included in “Currency translation adjustment” on the Consolidated Statement of Equity.

dollar are included in “Currency translation adjustment” within Note 2.

Changes in AOCL .

Revenue Recognition The company accounts for each delivery order of crude oil, NGLs, natural gas, petroleum and chemical products as a separate performance obligation.

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When deliveries contain multiple products, an observable standalone selling price is generally used to measure revenue for each product.

The company includes estimates in the transaction price only to the extent that a significant reversal of revenue is not probable in subsequent periods.

Stock Options and Other Share-Based Compensation The company issues stock options and other share-based compensation to certain employees.

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

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

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

company includes estimates in the transaction price only to the extent that a significant reversal of revenue is not probable in subsequent periods.

Stock Options and Other Share-Based Compensation The company issues stock options and other share-based compensation to certain employees.

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.

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

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Net contributions from (distributions to) noncontrolling interests $ ( 323 ) $ ( 195 ) $ ( 40 )

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 $ 400

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

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.

Refer also to Note 29 - Acquisition of Hess Corporation for a discussion of the acquisition of Hess.

Cash received in connection with the acquisition is reflected in the Consolidated Statement of Cash Flows as “Acquisition of businesses, net of cash received.” Acquisition‑related changes to the Consolidated Balance Sheet that did not result in cash inflows or outflows are excluded from the Consolidated Statement of Cash Flows.

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

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New Accounting Standards

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 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.

Income Taxes (Topic 740) Improvements to Income Tax Disclosures The company has adopted the Financial Accounting Standards Board (FASB) Accounting Standard Update (ASU) 2023-09 which is 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.

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 17 Taxes .

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.

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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

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Millions of dollars, except per-share amounts

The following table summarizes the accrued severance liability.

The following table summarizes the accrued severance liability on the Consolidated Balance Sheet.

The balance is expected to be substantially settled by the end of 2026.

Amounts Before Tax

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Balance at December 31, 2025 $ 683

Notes to the Consolidated Financial Statements

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Fair Value Measurements

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The company does not materially adjust this information.

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.

Properties, Plant and Equipment The company did not have any individually material impairments of long lived assets measured at fair value on a nonrecurring basis in 2025 or 2024.

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 2025 or 2024.

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Total nonrecurring assets at fair value $ 53 $ — $ 44 $ 9 $ 168 $ 976 $ — $ 652 $ 324 $ 789

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

At year-end 2025, the company had assets measured at fair value Level 3 using unobservable inputs of $ 9 .

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

The carrying value of these assets were written down to fair value primarily 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.

Fair value measurements related to assets and liabilities acquired in the Hess Corporation (Hess) acquisition are disclosed in Note 29 - Acquisition of Hess Corporation .

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

The instruments classified as cash equivalents are primarily bank time deposits with maturities of 90 days or less and money market funds.

“Cash and cash equivalents” had carrying/fair values of $ 6,781 and $ 8,178 at December 31, 2024, and December 31, 2023, respectively.

“Cash and cash equivalents” had carrying/fair values of $ 6,293 and $ 6,781 at

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

December 31, 2025, and December 31, 2024, respectively.

The fair values of cash and cash equivalents are classified as Level 1 and reflect the cash that would have been received if the instruments were settled at December 31, 2025.

“Cash and cash equivalents” do not include investments with a carrying/fair value of $ 992 and $ 1,481 at December 31, 2025, and December 31, 2024, respectively.

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.

At December 31, 2025, these investments are classified as Level 1 and include restricted funds mainly related to certain upstream decommissioning activities.

Long-term debt, excluding finance lease liabilities, of $ 28,532 and $ 10,810 at December 31, 2025, and December 31, 2024, respectively, had estimated fair values of $ 28,610 and $ 9,791 , respectively.

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Total liabilities at fair value $ 68 $ 153

Notes to the Consolidated Financial Statements

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Consolidated Statement of Income:

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The amount reclassified from AOCL to “Sales and other operating revenues” from designated hedges was a net loss of $ 27 in 2025, compared with a net loss of $ 25 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.

At December 31, 2025, before-tax deferred gains in AOCL

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

related to outstanding crude oil price hedging contracts were $ 10 , 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, 2025 and 2024.

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At December 31, 2025, the company classifie d $ 25 of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet.

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.

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

The revenues and earnings contributions of these assets in 2025 were not material.

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In addition, 537,174 shares remain available for issuance from the 1,600,000 shares of the company’s common stock that were reserved for awards under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan.

Notes to the Consolidated Financial Statements

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Earnings Per Share

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

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

Year ended December 31

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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), which is comprised of the company’s Executive Committee, as referenced in Item 10 Executive Officers .

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.

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

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

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 net 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

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

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.

company on a worldwide basis.

Corporate administrative costs are not allocated to the operating segments.

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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.

Governmental and other plaintiffs in various jurisdictions across the United States have brought lawsuits 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 34 separate lawsuits filed by various U.S.

cities and counties, four U.S.

cities and counties, seven U.S.

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.

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

While defendants have sought to remove cases filed in state court to federal court, most of those cases have been remanded to state court and the U.S.

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.

Supreme Court has denied petitions for certiorari on the question of whether federal courts have jurisdiction over those cases.

Supreme Court has also denied 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.

On February 23, 2026, the U.S.

Supreme Court granted certiorari in Suncor Energy (U.S.A.) Inc., et.

County Commissioners of Boulder County, et.

25‑170), a case in which no Chevron entity is a party, to address the questions of whether federal law precludes state‑law claims seeking relief for injuries allegedly caused by the effects of interstate and international greenhouse gas emissions on the global climate and whether the U.S.

Supreme Court has statutory and Article III jurisdiction to hear that case.

The unprecedented legal theories set forth in these climate lawsuits 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.

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.

Management believes that these proceedings are legally and factually meritless and detract from constructive efforts to address the important policy issues presented by climate change and will vigorously defend against such proceedings.

Management believes that these lawsuits are legally and factually meritless and detract from constructive efforts to address the important policy issues presented by climate change and will vigorously defend against such lawsuits.

3 The cases are:

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Exxon Mobil Corp., et al.

22-cv-1550 (D.P.R.);

22-cv-1550 (D.P.R.) (dismissed on the merits;

Plaintiffs’ appeal pending);

City of Annapolis v.

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

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

Ct.) (dismissed on the merits;

Plaintiff’s appeal pending);

Anne Arundel County v.

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

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

Ct.) (dismissed on the merits;

Plaintiff’s appeal pending);

Mayor and City Council of Baltimore v.

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24-C-18-004219 (Md.

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

Ct.) (dismissed on the merits;

Plaintiff’s appeal pending);

People ex rel.

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Bucks County v.

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

BP P.L.C., et al.

2024-01836 (Pa.

Pl.) (dismissed on the merits;

Plaintiff’s appeal pending);

City of Charleston v.

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

Pl.) (dismissed on the merits and for lack of personal jurisdiction);

District of Columbia v.

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BP America Inc., et al.

N20C-09-097 (Del.Super.

N20C-09-097 (Del.

Ct.) (dismissed on the merits in substantial part);

City of Hoboken v.

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King County v.

, et al., No.

BP P.L.C., et al.

18-2-11859-0 (Wash.

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Exxon Mobil Corp., et al.

23-cv-01608 (D.P.R.);

23-cv-01608 (D.P.R.) (dismissed on the merits;

Plaintiff’s appeal pending);

City of Oakland v.

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

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

Ct.) (dismissed on the merits;

Plaintiff’s appeal pending);

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

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

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

of First Instance, Commonwealth of P.R.] (voluntarily dismissed);

City of New York v.

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State of Rhode Island v.

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

Chevron Corp., et al.

PC-2018-4716 (R.I.

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PORSC-CV-24-442 (Me.

State of Hawaii v.

BP P.L.C., et al.

, 1CCV-25-0000717 (Haw.

The People of the State of Michigan v.

BP p.l.c., et.al.

26-cv-00254 (W.D.

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

Seven coastal parishes and the State of Louisiana have filed lawsuits in Louisiana against numerous oil and gas companies seeking damages for coastal erosion in or near oil fields located within Louisiana’s coastal zone under Louisiana’s State and Local Coastal Resources Management Act (SLCRMA).

Seven coastal parishes and the State of Louisiana have filed lawsuits in Louisiana against numerous oil and gas companies seeking remediation damages for coastal erosion in or near oil fields located within Louisiana’s coastal zone under Louisiana’s State and Local Coastal Resources Management Act (SLCRMA).

Chevron entities are defendants in 36 of these cases.

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.

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

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.

Management believes that the claims lack legal and factual merit and will continue to vigorously defend against such proceedings.

Most of these cases have been remanded to Louisiana state court.

In April 2025, a jury in a Louisiana state court awarded Plaquemines Parish $ 744.6 million in a trial against Chevron entities (i.e., Plaquemines Parish v.

Rozel Operating Co., et al.

The state court judge continued a hearing on Plaquemines Parish’s motion for entry of judgment on the Rozel trial verdict and stayed that case pending a decision by the United States Supreme Court on whether certain cases belong in federal, rather than state, court.

The United States Supreme Court heard oral argument on the federal jurisdiction question on January 12, 2026.

The company does not concede the viability of the Rozel jury verdict and plans to appeal any judgment based on that verdict.

The jury’s decision was unique to the facts and circumstances of the case and may not be representative of future outcomes for other claims brought against Chevron entities under the SLCRMA.

In accordance with guidance on the evaluation of loss contingencies, the company has recorded an accrual of $ 131 million, which the company believes to be a reasonably estimable loss in light of the available defenses.

It is reasonably possible that the estimate of the loss could change based on the progression of the case, including the appeals process.

However, because of the uncertainties associated with ongoing litigation, we are unable to estimate the range of reasonably possible loss that may be attributable to liabilities, if any, in excess of the amount accrued.

While the company believes the jury verdict is not legally or factually supported and intends to appeal and vigorously pursue post-judgment remedies, there can be no assurances that such defense efforts will be successful.

To the extent the company is required to pay remediation damages in these cases, it may have a material adverse effect on our financial position and results of operations.

Management believes that the claims in these lawsuits lack legal and factual merit and will continue to vigorously defend against such proceedings.

4 The cases are:

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St., Bernard Par.).

City of New Orleans v.

Apache Louisiana Mins, LLC, et al.

19-cv-08290, (E.D.

Notes to the Consolidated Financial Statements

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Total income tax expense (benefit) $ 7,258 $ 9,757 $ 8,173

For 2025, ASU 2023-09 requires an expanded view of the rate reconciliation as well as a summary of income taxes paid for material jurisdictions.

Chevron has elected a prospective presentation.

The tables below represent the new standard for 2025 and revert to prior guidance for comparable years.

Notes to the Consolidated Financial Statements

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The reconciliation between the U.S.

statutory federal income tax rate and the company’s effective income tax rate is detailed in the following table:

Year ended December 31

statutory federal income tax rate and the company’s effective income tax rate for the year ended December 31, 2025, in accordance with ASU 2023-09 guidance, is detailed in the following table:

Taxes On Income Year ended December 31

Income (loss) before income taxes

United States $ 5,979

International 13,764

Total income (loss) before income taxes 19,743

Federal statutory income tax 4,146 21.0 %

State and local income tax, net of federal income tax effect 1

Foreign tax effects

Statutory tax rate difference 334 1.7 %

Additional non-U.S.

income taxes 2

Foreign exchange 356 1.8 %

Other 14 0.1 %

Additional non-U.S.

income taxes 2

Equity affiliate accounting effect 3

( 353 ) ( 1.8 ) %

Other 128 0.6 %

Nigeria - primarily additional non-U.S.

income taxes 368 1.9 %

Saudi Arabia - primarily statutory tax rate difference 583 3.0 %

Other foreign jurisdictions 345 1.7 %

Total foreign tax effects 2,686 13.6 %

Effect of cross-border tax laws - primarily surplus foreign tax credits 4

( 2,477 ) ( 12.5 ) %

Changes in valuation allowances 4

Other adjustments 5

( 12 ) ( 0.1 ) %

Total income tax expense and effective tax rate $ 7,258 36.8 %

1 State taxes in California and New Mexico make up the majority (greater than 50%) of the tax effect in this category.

2 Includes items such as withholding taxes and oil profit taxes.

3 After‑tax equity affiliate income is included in pretax earnings, which results in a negative adjustment in the rate reconciliation.

4 Surplus foreign tax credits and their related valuation allowances are shown gross but largely offset.

5 Tax credits, nontaxable and nondeductible items and changes in unrecognized tax benefits were all immaterial and included in other adjustments.

The reconciliation between the U.S.

statutory federal income tax rate and the company’s effective income tax rate for the years ended December 31, 2024 and 2023, as previously reported, is detailed in the following table:

Year ended December 31

Income (loss) before income taxes

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Effective income tax rate 35.5 % 27.6 %

35.5 % 27.6 % 28.3 %

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

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2023 - $( 84 )).

2022 - $( 36 )).

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

Generally Accepted Accounting Principles.

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

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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Millions of dollars, except per-share amounts

The 2025 decrease in income tax expense of $ 2,499 was driven by the decrease in total income before tax of $ 7,763 , along with the absence of the tax impacts from the prior year asset sales in Canada.

The change in the company’s effective tax rate from 35.5 percent in 2024 to 36.8 percent in 2025 was primarily a result of unfavorable foreign exchange impacts.

The reconciliation of income taxes paid in the U.S.

and other significant international jurisdictions for the year ended December 31, 2025, is detailed in the following table:

Income Taxes Paid Year ended December 31

state and local 224

All other jurisdictions

Australia 1,592

Saudi Arabia 611

All others 1,198

Income taxes paid $ 7,304

Federal taxes paid are affected by accelerated depreciation and the immediate expensing of research and development costs provided by the One Big Beautiful Bill Act of 2025, as well as net operating loss carryforwards, tax credits from biofuels production and other lower carbon activities, and prior year overpayments.

2 Includes taxes associated with the Canada asset sale in 2024 that were paid in 2025.

3 Taxes settled with the government in the form of crude oil barrels.

4 Includes withholding tax and excludes taxes paid by the company’s equity affiliate, TCO.

The company records its deferred taxes on a tax-jurisdiction basis.

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Employee benefits ( 1,924 ) ( 2,050 )

Deferred credits ( 292 ) ( 268 )

Tax credits ( 430 ) ( 292 )

Tax loss carryforwards ( 7,141 ) ( 3,034 )

Other accrued liabilities ( 909 ) ( 1,137 )

Inventory ( 68 ) ( 126 )

Operating leases ( 1,886 ) ( 1,352 )

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Total deferred income taxes, net $ 27,152 $ 15,621

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 foreign exchange impacts, partially offset by decreases in tax loss carryforwards and other accrued liabilities.

Deferred tax liabilities increased by $ 14,915 from year-end 2024, driven by the acquisition of Hess.

Deferred tax assets increased by $ 8,932 from year-end 2024, primarily related to increases in foreign tax credits and tax loss carryforwards from the acquisition of Hess.

The overall valuation allowance, which increased by $ 5,548 from year-end 2024, relates to deferred tax assets for U.S.

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foreign tax credit carryforwards of $ 18,932 will expire between 2026 and 2035.

Notes to the Consolidated Financial Statements

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At December 31, 2025 and 2024, deferred taxes were classified on the Consolidated Balance Sheet as follows:

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

state and foreign withholding tax purposes.

state and foreign withholding tax purpos es.

It is not practicable to estimate the amount of state and foreign withholding taxes that might be payable on the possible remittance of earnings that are intended to be reinvested indefinitely.

The company does not anticipate incurring significant additional taxes on remittances of earnings that are not indefinitely reinvested.

The company does not anticipate incu rring significant additional taxes on remittances of earnings that are not indefinitely reinvested.

Uncertain Income Tax Positions The company recognizes a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that the position is more likely than not (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position.

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The following table indicates the changes to the company’s unrecognized tax benefits for the years ended December 31, 2025, 2024 and 2023.

The term “unrecognized tax benefits” in the accounting standards for income taxes refers to the

Notes to the Consolidated Financial Statements

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differences between a tax position taken or expected to be taken in a tax return and the benefit measured and recognized in the financial statements.

The term “unrecognized tax benefits” in the accounting standards for income taxes refers to the differences between a tax position taken or expected to be taken in a tax return and the benefit measured and recognized in the financial statements.

Interest and penalties are not included.

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With certain exceptions, income tax examinations are completed through 2019 for the United States and 2007 for other major jurisdictions.

The company engages in ongoing discussions with tax authorities regarding the resolution of tax matters in the various jurisdictions.

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, 2025, accrued expense of $ 306 for anticipated interest and penalties was included on the Consolidated Balance Sheet, compared with accrued expense of $ 268 as of year-end 2024.

Income tax expense (benefit) associated with interest and penalties was $ 37 , $ 40 and $ 124 in 2025, 2024 and 2023, respectively.

Notes to the Consolidated Financial Statements

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Taxes Other Than on Income

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Property and other miscellaneous taxes

1,129 977 818

Payroll taxes 308 296 286

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Total taxes other than on income $ 5,230 $ 4,716 $ 4,220

Notes to the Consolidated Financial Statements

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Properties, Plant and Equipment 1

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Total $ 434,955 $ 345,933 $ 346,081 $ 219,729 $ 147,799 $ 153,619 $ 91,568 $ 15,841 $ 26,724 $ 20,132 $ 17,282 $ 17,326

1 Other than the United States and Australia, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2024.

1 Other than the United States, Guyana and Australia, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2025.Guyana had PP&E of $ 50,960 in 2025.

Australia had PP&E of $ 36,761 , $ 38,969 and $ 41,409 in 2025, 2024 and 2023, respectively.

Gross Investment at Cost and Additions at Cost for 2025 each include $ 73,538 associated with the acquisition of Hess.

Gross Investment at Cost and Additions at Cost for 2023 each include $ 10,487 associated with the PDC acquisition.

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Redeemable long-term obligations 3,049 3,069

10,918 12,656

Reclassified to long-term debt ( 9,941 ) ( 8,250 )

Total short-term debt $ 977 $ 4,406

* Inclusive of unamortized premiums of $ 0 at December 31, 2024 and $ 17 at December 31, 2023.

Notes to the Consolidated Financial Statements

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Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date.

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Notes due 2030 3.955 2.236 - 5.500

Notes and Debentures due 2031 7.484 7.300 - 8.625

Notes and Debentures due 2032 4.944 4.500 - 8.625

Notes due 2033 7.125 540 —

Debentures due 2031 8.625 102 102

Debentures due 2032 8.416 8.000 - 8.625

Notes due 2035 4.909 4.850 - 4.980

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Notes due 2049 4.200 237 237

Notes due 2050 2.763 2.343 - 3.078

Notes due 2075 3.722 154 —

Debentures due 2097 7.250 60 60

Bank loans due 2026 to 2028 5.460 2.448 - 8.040

Term loans and credit facility borrowings 7.320 7.250 - 8.136

Medium-term notes, maturing from 2033 to 2038 5.786 3.688 - 7.840

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Debt due within one year ( 2,345 ) ( 4,012 )

Fair market value adjustment for debt acquired in the Noble acquisition 529 578

Fair market value adjustment for debt acquired in the Noble and Hess acquisitions 649 529

Reclassified from short-term debt 9,941 8,250

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Capitalized exploratory well costs charged to expense ( 1 ) — ( 67 )

Other reductions* ( 52 ) — —

Ending balance at December 31 $ 1,759 $ 1,662 $ 1,648

* Represents property sales.

The following table provides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:

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* Certain projects have multiple wells or fields or both.

Of the $ 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 $ 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.

Of the $ 1,611 of exploratory well costs capitalized for more than one year at December 31, 2025, $ 848 is related to nine projects that had drilling activities underway or firmly planned for the near future.

The $ 763 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.

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 $ 763 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability:

(a) $ 383 ( five projects) – undergoing front-end engineering and design with final investment decision expected within four years ;

(a) $ 348 ( four 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 15 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 half of these decisions are expected to occur in the next five years .

More than half of these decisions are expected to occur in the next five years .

The $ 1,611 of suspended well costs capitalized for a period greater than one year as of December 31, 2025, represents 73 exploratory wells in 15 projects.

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Actual expenses — ( 7 ) — ( 2 ) — —

Divestitures/Acquisitions 1,932 580 — — — —

Fair value of plan assets at December 31 11,787 3,897 9,537 3,061 — —

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Net amount recognized at December 31 $ 57 $ ( 127 ) $ ( 603 ) $ ( 228 ) $ ( 1,981 ) $ ( 1,880 )

For the year ended December 31, 2025, the increase in benefit obligations was primarily due to the acquisition of Hess.

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.

Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $ 3,171 and $ 3,376 at the end of 2025 and 2024, respectively.

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Rate of compensation increase 4.5 % 4.0 % 4.5 % 3.9 % 4.5 % 3.9 % N/A N/A N/A

Cash balance interest crediting rate 4.7 % N/A N/A N/A N/A N/A N/A N/A N/A

Assumptions used to determine net periodic benefit cost:

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Rate of compensation increase 4.5 % 3.9 % 4.5 % 3.9 % 4.5 % 4.2 % N/A N/A N/A

Cash balance interest crediting rate 4.8 % N/A N/A N/A N/A N/A N/A N/A N/A

Expected Return on Plan Assets The company’s estimated long-term rates of return on pension assets are driven primarily by actual historical asset-class returns, an assessment of expected future performance, advice from external actuarial firms and the incorporation of specific asset-class risk factors.

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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.

The effective discount rates derived from this analysis were 5.5 percent,

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

5.7 percent, and 5.0 percent for 2025, 2024, and 2023, respectively, for the main U.S.

pension plan and 5.3 percent, 5.6 percent, and 5.0 percent for 2025, 2024, and 2023, respectively, for the main U.S.

Other Benefit Assumptions For the measurement of accumulated post-employment benefit obligation at December 31, 2025, for the main U.S.

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— — — — — 76 — 76 — —

Real Estate 4

Real Assets 4

1,383 — — — 1,383 105 — 16 — 89

Alternative Investments 5

— — — — — 9 — 9 — —

Cash and Cash Equivalents 289 13 — — 276 108 90 — — 18

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— — — — — 89 — 89 — —

Real Estate 4

Real Assets 4

1,594 — — — 1,594 118 — 22 — 96

Alternative Investments 5

423 — — — 423 14 — 8 — 6

Cash and Cash Equivalents 273 66 — — 207 93 90 — — 3

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3 Mixed funds are composed of funds that invest in both equity and fixed-income instruments in order to diversify and lower risk.

4 The year-end valuations of the U.S.

real estate assets are based on third-party appraisals that occur at least once a year for each property in the portfolio.

4 Includes Real Estate and Infrastructure.

The year-end valuations of U.S.

Real Assets are based on third-party appraisals that occur at least once a year for each property in the portfolio.

5 Includes Private Equity.

6 The “Other” asset class includes net payables for securities purchased but not yet settled (Level 1);

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pension plan, the company’s Investment Committee has established the following approved asset allocation ranges:

Equities 30 – 60 percent, Fixed Income 30 – 50 percent, Real Estate 5 – 25 percent, Alternative Investments 0 – 5 percent and Cash 0 – 15 percent.

Equities 30 – 60 percent, Fixed Income 30 – 50 percent, Real Assets 5 – 25 percent, Private Equity 0 – 5 percent and Cash 0 – 10 percent.

pension plan, the U.K.

Board of Trustees has established the following asset allocation guidelines:

Plan Trustee has established the following asset allocation guidelines:

Equities 5 – 15 percent, Fixed Income 63 – 93 percent, Real Estate 5 – 15 percent, and Cash 0 – 7 percent.

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Settlement of open tax years, as well as other tax issues in countries where the company conducts its businesses, are not expected to have a material effect on the consolidated financial position or liquidity of the company and, in the opinion of management, adequate provisions have been made for all years under examination or subject to future examination.

Guarantees The company has one guarantee to an equity affiliate totaling $ 98 .

This guarantee is associated with certain payments under a terminal use agreement entered into by an equity affiliate.

Over the approximate 3-year remaining term of this guarantee, the maximum guarantee amount will be reduced as certain fees are paid by the affiliate.

There are numerous cross-indemnity agreements with the affiliate and the other partners to permit recovery of amounts paid under the guarantee.

Chevron has recorded no liability for this guarantee.

Guarantees The company has provided certain guarantees in the ordinary course of business, including financial and performance guarantees related to equity affiliates.

Chevron has no material guarantees outstanding.

Indemnifications The company often includes standard indemnification provisions in its arrangements with its partners, suppliers and vendors in the ordinary course of business, the terms of which range in duration and sometimes are not limited.

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federal Superfund sites and analogous sites under state laws, refineries, chemical plants, marketing facilities, crude oil fields and mining sites.

Although the company has provided for known environmental obligations that are probable and reasonably estimable, it is likely that the company will continue to incur additional liabilities.

The amount of additional future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

Although the company has provided for known environmental obligations that are probable and reasonably estimable, it is likely that the company will continue to incur additional liabilities.

parties, and the extent to which such costs are recoverable from third parties.

These future costs may be material to results of operations in the period in which they are recognized, but the company does not expect these costs will have a material effect on its consolidated financial position or liquidity.

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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

Financial Table of Contents

Millions of dollars, except per-share amounts

AROs are primarily recorded for the company’s crude oil and natural gas producing assets.

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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.

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

The following table indicates the changes to the company’s before-tax asset retirement obligations in 2025, 2024 and 2023:

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Balance at January 1 $ 12,667 $ 13,833 $ 12,701

Liabilities assumed in the PDC acquisition — 220 —

Liabilities assumed in acquisition 1,682 — 220

Liabilities incurred 186 83 183

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Earnings 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 2024 included after-tax charges of approximat ely $ 715 for s everance ($ 208 in All Other, $ 188 in U.S.

Earnings in 2025 included after-tax charges of approximat ely $ 355 for Hess severance and transition costs ( $ 245 in U.S.

Upstream, $ 70 in International Upstream, $ 40 in All Other), $ 300 for legal reserves ( $ 170 in U.S.

Downstream, $ 130 i n U.S.

Upstream) and $ 223 for pension settlement and curtailment costs.

Earnings in 2024 included after-tax charges of approximately $ 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.

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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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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 zero and $ 219 at December 31, 2024, and December 31, 2023, 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 $ 83 and zero at December 31, 2025, and December 31, 2024, respectively, are included within “Investments and advances” on the Consolidated Balance Sheet.

Acquisition of Hess Corporation

On July 18, 2025, the company acquired Hess Corporation (Hess), an independent oil and gas exploration and production company.

Hess’s principal upstream operations are in the United States, Guyana and Malaysia.

Hess’s operations also include an approximately 38 percent ownership interest in Hess Midstream LP (HESM), with operations primarily in the Bakken shale in the Williston Basin area of North Dakota.

The aggregate purchase price of Hess was approximately $ 48 billion, including 15.38 million shares of Hess common stock purchased in open market transactions in the first quarter of 2025 and 301.25 million shares of Chevron common stock issued as closing consideration in July.

As part of the transaction, the company assumed debt with an aggregate outstanding principal value of $ 8.8 billion.

The shares issued represented approximately 15 percent of the shares of Chevron common stock outstanding immediately after the transaction closed on July 18, 2025.

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

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

Acquisition of PDC Energy, Inc.

On August 7, 2023, the company acquired PDC Energy, Inc.

(PDC), an independent exploration and production company with operations in the Denver-Julesburg Basin in Colorado and the Delaware Basin in west Texas.

The aggregate purchase price of PDC was $ 6,520 , with approximately 41 million shares of Chevron common stock issued as consideration in the transaction.

The shares represented approximately two percent of the shares of Chevron common stock outstanding immediately after the transaction closed on August 7, 2023.

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.

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.

Debt assumed in the acquisition was valued based on observable market prices for PDC’s debt.

date of acquisition, as information necessary to complete the analysis is obtained.

The fair value of the noncontrolling interest was determined based on the quoted market price of HESM on the acquisition date.

Debt assumed in the acquisition was valued based on observable market prices for Hess’s debt.

As a result of measuring the assets acquired and the liabilities assumed at fair value, there was no goodwill or bargain purchase recognized.

The following table summarizes the fair values assigned to assets acquired and liabilities assumed:

At August 7, 2023

At July 18, 2025

(Billions of dollars)

Current assets $ 3.4

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Long-term debt (1)

Deferred income tax 1,397

Deferred income taxes 11.0

Other liabilities 2.4

Total liabilities assumed 26.5

Purchase Price $ 6,520

Pro forma financial information is not disclosed as the acquisition was deemed not to have a material impact on the company’s results of operations.

Agreement to Acquire Hess Corporation

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.

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.

Noncontrolling interest (2)

Net assets acquired / purchase price $ 48.0

(1) Includes finance leases

(2) Related to HESM

The long-term debt assumed in the transaction is detailed in the table below:

Hess Corporation Principal

4.300 % due 2027

7.875 % due 2029

7.300 % due 2031

7.125 % due 2033

6.000 % due 2040

5.600 % due 2041

5.800 % due 2047

Total Hess Corporation Debt $ 5,138

Hess Midstream Operations LP

5.125 % due 2028

5.875 % due 2028

6.500 % due 2029

4.250 % due 2030

5.500 % due 2030

Term loan and credit facility borrowings 646

Total Hess Midstream Operations LP Debt $ 3,746

Unamortized discounts and debt issuance costs ( 61 )

Total Long-Term Debt Assumed $ 8,823

Fair market value adjustment for debt acquired in the acquisition 247

Fair Market Value of Long-Term Debt Assumed $ 9,070

The following table presents revenue and earnings for Hess since the acquisition date (July 18, 2025), for the year ended December 31, 2025.

Year Ended December 31,

Sales and other operating revenue $ 5,957

Net Income (Loss) Attributable to Chevron Corporation $ 193

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

The following unaudited pro forma information presents the results of operations as if the acquisition of Hess had occurred January 1, 2024:

Year Ended December 31,

Sales and other operating revenue $ 189,416 $ 204,300

Net Income (Loss) Attributable to Chevron Corporation $ 12,464 $ 19,003

The unaudited pro forma information uses estimates and assumptions based on information available at the time.

Management believes the estimates and assumptions to be reasonable;

however, actual results may differ significantly from this pro forma financial information.

The pro forma information does not reflect any synergistic savings that might be achieved from combining the operations and is not intended to reflect the actual results that would have occurred had the companies actually been combined during the periods presented.

The pro forma results reflect pro forma adjustments primarily related to conforming Hess’ accounting policies to Chevron’s, additional depreciation expense related to the fair value adjustment of the acquired property, plant and equipment, elimination of intercompany transactions and applicable income tax impacts.

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

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Tables I through IV provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development, capitalized costs and results of operations.

Tables V through VII present information on the company’s estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to

Tables V through VII present information on the company’s

Table I - Costs Incurred in Exploration, Property Acquisitions and Development 1

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Property acquisitions 2,3

Proved - Other 11 — 95 — — — 106 — —

Unproved - Other 69 38 22 — — — 129 — —

Proved 19,947 22,987 — 838 — — 43,772 — —

Unproved 1,783 28,141 15 — — — 29,939 — —

Total property acquisitions 21,730 51,128 15 838 — — 73,711 — —

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Does not include properties acquired in nonmonetary transactions.

3 Majority of proved and unproved property acquisitions represent assets acquired from Hess Corporation.

4 Includes $89, $59 and $208 of costs incurred on major capital projects prior to assignment of proved reserves for consolidated companies in 2025, 2024, and 2023, respectively.

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Total cost incurred by Consolidated Companies $ 89.5 $ 14.6 $ 24.6

Acquisitions (73.5) — (10.5) (2025:

Hess Corporation;

PDC Energy, Inc.)

(PDC) acquisition — (10.5) —

Expensed exploration costs (0.7) (0.6) (0.5) (Geological and geophysical and other exploration costs)

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Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

proved reserves, and changes in estimated discounted future net cash flows.

The amounts for consolidated companies are organized by geographic areas including the United States, Other Americas, Africa, Asia, Australia/Oceania and Europe.

estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.

The amounts for consolidated companies are organized by geographic areas including the United States, Other Americas, Africa, Asia, Australia and Europe.

Amounts for affiliated companies include Chevron’s equity interests in Tengizchevroil (TCO) in the Republic of Kazakhstan and in other affiliates, principally in Angola.

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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 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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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 decommissioning obligations from certain previously divested oil and gas production assets in the Gulf of America.

Table IV - Results of Operations for Oil and Gas Producing Activities - Unit Prices and Costs 1

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Proved reserves are estimated by company asset teams composed of earth scientists and engineers.

As part of the internal control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired by the Manager of Global Reserves, an organization that is separate from the business units that estimate reserves.

The Manager of Global Reserves has more than 35 years of experience working in the oil and gas industry and holds both undergraduate and graduate degrees in geoscience.

As part of the internal control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired by the Manager of Reserves and Storage, an organization that is separate from the business organizations that estimate reserves.

The Manager of Reserves and Storage has more than 35 years of experience working in the oil and gas industry and holds both undergraduate and graduate degrees in geoscience.

His experience includes various technical and management roles in providing reserve and resource estimates in support of major capital and exploration projects, and more than 10 years of overseeing oil and gas reserves processes.

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The RAC has the following primary responsibilities:

establish the policies and processes used within the business units to estimate reserves;

establish the policies and processes used within the business organizations to estimate reserves;

provide independent reviews and oversight of the business units’ recommended reserves estimates and changes;

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and maintain the Chevron Corporation Reserves Manual , which provides standardized procedures used corporatewide for classifying and reporting hydrocarbon reserves.

During the year, the RAC is represented in meetings with each of the company’s business units to review and discuss reserve changes recommended by the various asset teams.

During the year, the RAC is represented in meetings with each of the company’s business organizations and regions to review and discuss reserve changes recommended by the various asset teams.

Major changes are also reviewed with the company’s senior leadership team including the Chief Executive Officer and the Chief Financial Officer.

The company’s annual reserves activity is also reviewed with the company’s Audit Committee and Board of Directors.

The company’s annual reserves activity is also reviewed with the company’s Board 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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These reviews include an examination of the proved reserve records and documentation of their compliance with the Chevron Corporation Reserves Manual .

The acquisition of Hess Corporation (Hess) was completed on July 18, 2025.

Given the timing of the acquisition, Chevron has continued to rely on legacy Hess reserves staff and processes for reviewing reserves with input and guidance from the Chevron RAC.

The processes include internal reviews and an external audit.

Accordingly, the company continued to retain DeGolyer and MacNaughton, an independent petroleum engineering consulting firm, to complete an audit of the legacy Hess proved reserves at December 31, 2025 (representing approximately 13 percent of Chevron’s total proved reserves).

Based upon their evaluation, DeGolyer and MacNaughton issued an unqualified audit opinion, and their report is attached as Exhibit 99.2 to this Annual Report on Form 10-K.

Technologies Used in Establishing Proved Reserves Additions In 2025, additions to Chevron’s proved reserves were based on a wide range of geologic and engineering technologies.

Information generated from wells, such as well logs, wire line sampling, production and pressure testing, fluid analysis, and core analysis, was integrated with seismic data, regional geologic studies, and information from analogous reservoirs to provide “reasonably certain” proved reserves estimates.

Both proprietary and commercially available analytic tools, including reservoir simulation, geologic modeling and seismic processing, have been used in the interpretation of the subsurface data.

Information generated from subsurface data and geoscience and engineering analysis was used in both proprietary and commercially available analytic tools, including reservoir simulation, geologic modeling and seismic processing, to provide “reasonably certain” proved reserves estimates.

These technologies have been utilized extensively by the company in the past, and the company believes that they provide a high degree of confidence in establishing reliable and consistent reserves estimates.

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

Proved Undeveloped Reserves

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Quantity at January 1 2,761

Revisions (154)

Improved recovery 2

Extension and discoveries 440

Purchases 417

Transfers to proved developed (800)

Quantity at December 31 2,835

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

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 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.

In 2025, revisions include an increase of 55 million BOE in Israel, primarily at the Leviathan field, based on production performance-driven reservoir model changes that resulted in a re-allocation of proved developed and proved undeveloped reserves estimates.

In Australia, there was an increase of 40 million BOE, largely attributable to positive reservoir performance at Jansz Io.

The net decrease of 34 million BOE in the United States was primarily from the Denver-Julesburg (DJ) Basin with a decrease of 49 million BOE mainly due to portfolio optimization, partially offset by positive revisions in the Midland and Delaware basins.

In Argentina, a negative revision of 33 million BOE was primarily attributable to shale and tight portfolio optimization.

In 2025, extensions and discoveries in the United States totaled 214 million BOE, primarily attributable to planned development of new locations in shale and tight assets in the Midland and Delaware basins (136 million BOE) and in the DJ Basin (73 million BOE).

In Australia, additions of 128 million BOE resulted from the sanctioning of the Gorgon Stage 3 project.

In Other Americas, extensions and discoveries totaled 95 million BOE, primarily attributable to the Hammerhead project sanctioned in Guyana (52 million BOE) and to additions from shale and tight assets in Argentina (40 million BOE).

In 2025, purchases of 221 million BOE in the United States are primarily attributable to the acquisition of Hess assets in North Dakota.

In Other Americas, purchases of 193 million BOE are attributable to the acquisition of Hess interests in the Stabroek block in Guyana.

The difference in 2025 extensions and discoveries of 167 million BOE, between the net quantities of proved reserves of 607 million BOE as reflected on pages 116 through 118 and net quantities of proved undeveloped reserves of 440 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 2025.

Transfers to proved developed reserves in 2025 include 544 million BOE in the United States, from the Midland and Delaware basins (279 million BOE), Gulf of America (153 million BOE), and DJ Basin (112 million BOE).

Other significant transfers to proved developed were 170 million BOE in Kazakhstan, largely driven by the startup of the Future Growth Project at TCO.

A combined 86 million BOE of transfers to proved developed were recorded in Argentina, the Partitioned Zone, Australia, Nigeria, Angola, Canada, and other international locations.

These transfers are the consequence of development expenditures on completing wells and facilities.

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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.

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

At year-end 2025, the company held approximately 396 million BOE of proved undeveloped reserves that have remained undeveloped for five years or more.

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In Africa, approximately 137 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 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.

In 2025, the positive impacts of higher natural gas prices in North America and of lower oil prices in production sharing contracts more than offset the negative impact of lower oil prices in tax and royalty assets, resulting in a proved reserve increase of approximately 57 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 27 percent and 31 percent.

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

Proved Reserve Quantities For the three-year period ended December 31, 2025, the pattern of net reserve changes shown in the following tables is not necessarily indicative of future trends.

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Noteworthy changes in crude oil, condensate and synthetic oil proved reserves for 2023 through 2025 are discussed below and shown in the table on the following page:

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.

In 2023, the 257 million barrels decrease in United States was primarily in the Midland and Delaware basins and California.

Revisions In 2023, the 257 million barrels decrease in United States was primarily in the Midland and Delaware basins and California.

Reservoir performance led to the decrease of 101 million barrels, and portfolio optimization led to a decrease of 59 million barrels in the Midland and Delaware basins.

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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.

In 2023, extensions and discoveries of 124 million barrels in the Midland and Delaware basins were primarily responsible for the 170 million barrels increase in the United States.

In 2025, the 46 million barrels increase in Asia was due to reservoir performance, primarily in the Partitioned Zone.

Extensions and Discoveries In 2023, extensions and discoveries of 124 million barrels in the Midland and Delaware basins were primarily responsible for the 170 million barrels increase in the United States.

In Other Americas, the 55 million barrels of extensions and discoveries increase was mainly from shale and tight assets in Argentina.

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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.

The extension of deepwater licenses in Nigeria and the Republic of Congo contributed 36 million barrels in Africa.

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.

In 2025, extensions and discoveries of 121 million barrels in the Midland and Delaware basins were primarily responsible for the 148 million barrels increase in the United States.

In Other Americas, the 89 million barrels of extensions and discoveries increase was primarily from the sanctioning of the Hammerhead project in Guyana (50 million barrels) and shale and tight assets in Argentina (35 million barrels).

Purchases 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.

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

In 2025, the acquisition of Hess interests in the Stabroek block in Guyana was responsible for the 473 million barrels in Other Americas.

The acquisition of Hess assets in North Dakota (362 million barrels) and the Gulf of America (29 million barrels) was mainly responsible for the 392 million barrels in the United States.

In 2025, sales of 35 million barrels in Africa were from the divestment of assets in the Republic of Congo.

Net Proved Reserves of Crude Oil, Condensate and Synthetic Oil

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Extensions and Discoveries 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 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.

Sales In 2022, sales of 35 million barrels in the United States were primarily from the divestment of the Eagle Ford shale assets and some properties in the Midland and Delaware basins.

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

In 2024, extensions and discoveries in the Midland and Delaware basins (72 million barrels), and in the DJ Basin (52 million barrels), were responsible for the 124 million barrels increase in the United States.

In 2025, extensions and discoveries in the Midland and Delaware basins of 81 million barrels were primarily responsible for the 103 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.

In 2025, acquisition of Hess assets in North Dakota was primarily responsible for the 273 million barrels in the United States

Net Proved Reserves of Natural Gas Liquids

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Revisions (110) — (6) — — — (116) 12 2 (102)

Improved recovery — — — — — — — — — —

Extensions and discoveries 92 — — — — — 92 — — 92

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Revisions (41) — (7) — — — (48) 1 1 (46)

Improved recovery — — — — — — — — — —

Extensions and discoveries 124 — — — — — 124 — — 124

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Revisions 3 — (15) — — — (12) (1) 4 (9)

Improved recovery — — — — — — — — — —

Extensions and discoveries 103 — — — — — 103 — — 103

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Noteworthy changes in natural gas proved reserves for 2023 through 2025 are discussed below and shown in the table on the following page:

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.

In TCO, entitlement effects and changes in operating assumptions were primarily responsible for the 285 BCF decrease.

In 2023, portfolio optimization decrease of 276 BCF and a reservoir performance decrease of 186 BCF in the Midland and Delaware basins along with a reduction in planned development activities leading to a decrease of 485 BCF in the Haynesville shale formation of east Texas, were mainly responsible for the 1.2 TCF decrease in the United States.

Revisions In 2023, portfolio optimization decrease of 276 BCF and a reservoir performance decrease of 186 BCF in the Midland and Delaware basins along with a reduction in planned development activities leading to a decrease of 485 BCF in the Haynesville shale formation of East Texas, were mainly responsible for the 1.2 TCF decrease in the United States.

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.

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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 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.

In 2025, an increase of 497 BCF in Australia was mainly attributable to reservoir performance of the Gorgon and Jansz Io fields.

In Asia, the 479 BCF increase was primarily driven by reservoir performance in Bangladesh (285 BCF), and Thailand (112 BCF).

The 227 BCF increase in the United States was primarily attributable to portfolio optimization in the Midland and Delaware basins.

Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents

Extensions and Discoveries 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 (476 BCF), and the Midland and Delaware basins (432 BCF).

In 2025, extensions and discoveries of 734 BCF in the United States were mainly in the Midland and Delaware basins (532 BCF), and the DJ Basin (199 BCF).

The 715 BCF in Australia was primarily driven by the sanctioning of the Gorgon Stage 3 project.

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.

In 2025, the 1.1 TCF in the United States was primarily attributable to the acquisition of Hess assets in North Dakota.

The acquisition of Hess interests in the Stabroek block in Guyana was the primary driver for the 213 BCF in Other Americas.

The 210 BCF in Asia was primarily from the acquisition of Hess assets in Malaysia.

Sales 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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Table VII - Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves

The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs.

The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities, prices and assumptions used in forecasting production volumes and costs.

Changes in the timing of production are included with “Revisions of previous quantity estimates.”

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Notes to the Consolidated Financial Statements

70 through 107

(2) Financial Statement Schedules:

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2.1 Agreement and Plan of Merger, dated as of October 22, 2023 among Chevron Corporation, Yankee Merger Sub Inc., and Hess Corporation, filed as Exhibit 2.1 to Chevron Corporation’s Current Report on Form 8-K filed October 23, 2023, and incorporated herein by reference.

3.1 Restated Certificate of Incorporation of Chevron Corporation, dated May 30, 2008, filed as Exhibit 3.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, and incorporated herein by reference.

3.1 Restated Certificate of Incorporation of Chevron Corporation, dated May 2 8 , 20 25 , filed as Exhibit 3.1 to Chevron Corporation’s Current Report on Form 8-K filed May 30, 20 25 , and incorporated herein by reference.

3.2 By-Laws of Chevron Corporation, as amended and restated December 3 , 202 5 , filed as Exhibit 3.2 to Chevron Corporation’s Current Report on Form 8-K filed December 5 , 202 5 , and incorporated herein by reference.

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4.5 Description of Securities Registered under Section 12 of the Exchange Act, filed as Exhibit 4.4 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2019, and incorporated herein by reference.

4.6 Fifth Supplemental Indenture, dated as of December 9, 2025, among Chevron U.S.A.

Inc., Chevron Corporation, as guarantor, and Deutsche Bank Trust Company Americas, as trustee, filed as Exhibit 4.2 to Chevron Corporation’s Current Report on Form 8-K filed December 9, 2025, and incorporated herein by reference.

4.7 Form of Floating Rate Notes Due 2075 (contained in Exhibit 4.6 hereto) .

Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.1 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.

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 .

10.3+ Amendment Number Two to the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan , filed as Exhibit 10.3 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2024, and incorporated herein by reference.

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.

10.5+ Form of Stock Units Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.19 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.

10.6+ Chevron Incentive Plan, 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, 202 4 , and incorporated herein by reference.

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.

10.6+* Chevron Incentive Plan, amended and restated effective January 1, 2026.

10.7+* Summary of Chevron Incentive Plan Award Criteria .

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.

10.9+ 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, 2014, 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.

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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.

10.14+ 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.

10.14+ 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.

10.16+ 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.

10.15+* Chevron Corporation Deferred Compensation Plan for Management Employees II, amended and restated effective January 1, 2026.

10.16+* Chevron Corporation Retirement Restoration Plan, amended and restated effective January 1, 2026.

10.17+* Chevron Corporation ESIP Restoration Plan, a mended and r estated effective January 1, 2026.

10.18+ Agreement between Chevron Corporation and R.

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10.19+ Agreement between Chevron Corporation and R.

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 .

Hewitt Pate, dated December 13, 2018, filed as Exhibit 10.19 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2023, and incorporated herein by reference .

10.20+ Amended and Restated Aircraft Time-Sharing Agreement, dated as of November 16, 2024, between Chevron U.S.A.

and Michael K.

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.

Wirth , filed as Exhibit 10.21 to Chevron Corporation ’ s Annual Report on Form 10-K for the year ended December 31, 2024, and incorporated here in by reference .

10.21+ Aircraft Time-Sharing Agreement, dated as of February 24, 2015, between Hess Corporation and John B.

Hess, filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2025, and incorporated herein by reference .

10.22+* Aircraft Time-Sharing Agreement, dated as of December 9, 2025, between JBH Ventures, LLC and Chevron Corporation.

10.23 Transition Services Agreement, dated as of July 14, 2025, between Chevron U.S.A.

and HFO Holdings LLC, filed as Exhibit 10.2 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2025, and incorporated herein by reference .

10.24 Amendment One to Transition Services Agreement, dated as of August 27, 2025, between Chevron U.S.A.

and HFO Holdings LLC, filed as Exhibit 10.3 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2025, and incorporated herein by reference .

10.25 Membership Interest Purchase Agreement, dated as of September 10, 2025, between Hess Corporation and JBH Ventures, LLC, filed as Exhibit 10.4 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2025, and incorporated herein by referenc e .

10.26* Membership Interest Purchase Agreement (Membership Interest in HLOGO LLC), dated as of December 17, 2025, between Hess Corporation and John B.

10.27* Membership Interest Purchase Agreement (Membership Interest in Hess Toy Truck LLC), dated as of December 17, 2025, between Hess Corporation and John B.

10.28+* 2022 Long-Term Incentive Plan of Chevron Corporation, amended and restated effective January 1, 2026.

10.29+ 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.

10.30+ 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.

10.31+ 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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10.33+ Form of Performance Share Award Agreement (share settled) 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 February 2, 2024, and incorporated herein by reference.

10.29+ Form of Performance Share Award Agreement (cash 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 February 2, 2024, and incorporated herein by reference.

10.34+ Form of Standard Restricted Stock Unit Award Agreement (share 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 February 2, 2024, and incorporated herein by reference .

10.31+ Form of Standard Restricted Stock Unit Award Agreement (cash 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 February 2, 2024, and incorporated herein by reference.

10.32+ Form of Special Restricted Stock Unit Award Agreement (share 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 February 2, 2024, and incorporated herein by reference.

10.33+ Form of Special Restricted Stock Unit Award Agreement (cash settled) 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 February 2, 2024, and incorporated herein by reference.

10.35+ Form of Non-Qualified Stock Options Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.7 to Chevron Corporation’s Current Report on Form 8-K filed February 2, 2024, and incorporated herein by reference.

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10.37+ 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+* Form of Performance Share Award Agreement (share settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation.

10.39+* Form of Performance Share Award Agreement (cash settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation.

10.40+* Form of Standard Restricted Stock Unit Award Agreement (share settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation.

10.41+* Form of Standard Restricted Stock Unit Award Agreement (cash settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation.

19* Insider Trading Policies and Procedures .

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Consent of PricewaterhouseCoopers LLP (page E-2).

Power of Attorney for certain directors of Chevron Corporation, authorizing the signing of the Annual Report on Form 10-K on their behalf.

23.2* Consent of DeGolyer and MacNaughton .

P ower of Attorney for certain directors of Chevron Corporation, authorizing the signing of the Annual Report on Form 10-K on their behalf.

Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Executive Officer (page E-3).

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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 , 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 .

Chevron Corporation Dodd-Frank Clawback Policy, filed as Exhibit 97.1 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2023, and incorporated herein by reference.

99.1* Definitions of Selected Energy and Financial Terms (pages E-7 through E-1 1 ) .

99.2* Report of DeGolyer and MacNaughton.

101* Interactive data files (formatted as Inline XBRL).

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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 21st day of February, 2025.

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 21st day of February, 2025.

Principal Executive Officer

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/s/ EIMEAR P.

Bonner, Vice President

and Chief Financial Officer

Bonner, Chief Financial Officer

Principal Accounting Officer

Knowles, Vice President

and Controller

Knowles, Controller

Attorney-in-Fact

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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