What changed in this filing

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Item 9A. Controls and Procedures

2024-02-26 compared with 2023-02-23 · 896 added, 602 removed, 2823 unchanged (35% 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, 2023.

The company excluded PDC Energy, Inc.

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

Total assets and total

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

The effectiveness of the company’s internal control over financial reporting as of December 31, 2023, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein.

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Rule 10b5-1 Plan Elections

Wirth , Chairman of the Board and Chief Executive Officer , entered into a pre-arranged stock trading plan on November 22, 2023 .

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

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

Pate’s plan provides for the potential exercise of vested stock options and the associated sale of up to 250,742 shares of Chevron common stock between February 27, 2024 and February 7, 2025.

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

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

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

Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

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Chief Executive Officer

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

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

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

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

President, Chevron Eurasia Pacific Exploration & Production (July

2020 - Oct 2022)

President, Chevron Asia Pacific Exploration & Production (Jan 2019

- June 2020 )

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

Upstream - Worldwide Exploration and Production;

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

Midstream - Worldwide

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

Investor Relations

Nelson 60 Vice Chairman (since Feb 2023)

Executive Vice President, Strategy, Policy & Development (Oct

2022 - Feb 2023)

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

2022 - Sept 2023)

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

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

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Corporate Business Development;

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

President of Chevron Technical Center (since Feb 2021)

General Director of Tengizchevroil (Dec 2018 - Jan 2021)

General Manager of Operations of Tengizchevroil (Nov 2015 - Nov

Procurement/Supply Chain Management;

Information Technology

Global Reserves;

Nigel Hearne 56 Executive Vice President, Oil, Products & Gas (since Oct 2022)

President, Chevron Eurasia Pacific Exploration & Production (July

2020 - Oct 2022)

President, Chevron Asia Pacific Exploration & Production (Jan 2019

- June 2020) Upstream - Worldwide Exploration and Production;

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

Midstream - Worldwide;

Asset Performance and Process Safety;

Health, Safety and Environment

49 Vice President (since Aug 2021)

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

General Director, Tengizchevroil (Dec 2018 - Jan 2021)

Investor Relations

Gustavson 51 Vice President, Lower Carbon Energies (since Aug 2021)

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

Balaji Krishnamurthy 47 Vice President (since Oct 2022);

Vice President, Chevron Technical Center (since Jan 2024)

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

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

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

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

Global Reserves;

Facilities Designs and Solutions;

Capital Projects;

Health, Safety and Environment;

Downstream Technology

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

Vice President, Chevron North America Exploration & Production

(Feb 2018 - July 2021) Lower Carbon Solutions

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

Vice President, Human Resources (Oct 2016 - Jan 2019) Human Resources;

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

Diversity and Inclusion

Hewitt Pate 61 Vice President and General Counsel (since Aug 2009) Law, Governance and Compliance

* Effective March 1, 2024, Ms.

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

The information about directors required by Item 401(a), (d), (e) and (f) of Regulation S-K and contained under the heading “Election of Directors” in the Notice of the 2024 Annual Meeting of Stockholders and 2024 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act in connection with the company’s 2024 Annual Meeting (the 2024 Proxy Statement), is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 406 of Regulation S-K and contained under the heading “Corporate governance — Business conduct and ethics code” in the 2023 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

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

The information required by Item 406 of Regulation S-K and contained under the heading “Business Conduct and Ethics Code” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 407(d)(4) and (5) of Regulation S-K and contained under the heading “Corporate Governance — Board Committees” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 408(b) of Regulation S-K and contained under the heading “Insider Trading and Prohibited Transactions Involving Chevron Securities” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

Executive Compensation

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Certain Relationships and Related Transactions, and Director Independence

The information required by Item 404 of Regulation S-K and contained under the heading “Corporate governance — Related person transactions” in the 2023 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 404 of Regulation S-K and contained under the heading “Related Person Transactions” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 407(a) of Regulation S-K and contained under the heading “Corporate Governance — Director Independence” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

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Financial Instruments - Credit Losses

Acquisition of Renewable Energy Group, Inc.

Acquisition of PDC Energy , Inc.

Agreement to Acquire Hess Corporation

Supplemental Information on Oil and Gas Producing Activities

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Business Environment and Outlook

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

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

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

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

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

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

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

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California’s Cap-and-Trade Program;

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

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

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

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

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

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

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

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

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

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

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

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

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.

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.

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

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

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

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

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

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

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

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

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

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

The targeted 2028 reductions from 2016 on an equity ownership basis include a:

• 40 percent reduction in oil production GHG intensity to 24 kilograms (kg) carbon dioxide equivalent per barrel of oil-equivalent (CO 2 e/boe),

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

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

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

• 66 percent reduction in flaring GHG intensity to 3 kg CO 2 e/boe.

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

• Gas production GHG intensity of 24 kg CO 2 e/boe,

• Methane intensity of 2 kg CO 2 e/boe, and

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

The company also targets no routine flaring by 2030.

We have set 2016 as our baseline to align with the year the Paris Agreement entered into force, and the company plans to update the metrics every five years in line with the Paris Agreement stocktakes.

We believe these updates will provide additional transparency on the company’s progress toward its net zero aspiration.

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

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

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

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

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

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

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

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

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

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

Since 2021, the company has spent $6.5 billion in lower carbon investments, including $2.9 billion associated with the acquisition of REG in 2022.

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

changes in its portfolio;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Lead times for key capital equipment remain long.

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

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

Onshore drilling activity in the United States declined;

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

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.

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.

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

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

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

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

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

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

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

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

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

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

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

Demand has largely recovered as of year-end 2022;

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

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

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

Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry production and inventory levels, technology advancements, production quotas or other actions imposed by OPEC+ countries, actions of regulators, weather-related damage and disruptions, competing fuel prices, natural and human causes beyond the company’s control such as the COVID-19 pandemic, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty.

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

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

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

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

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

The company has begun to experience regulatory challenges and delays in obtaining permits to conduct operations in certain jurisdictions.

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

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

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

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

Chevron has interests in Venezuelan assets operated by independent affiliates.

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

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

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

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

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

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

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

Repairs were completed in fourth quarter 2022.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The company’s average realization for U.S.

crude oil and natural gas liquids in 2022 was $77 per barrel, up 37 percent from 2021.

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

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

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

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

In the United States, prices at Henry Hub averaged $2.56 per thousand cubic feet (MCF) during 2023, compared with $6.36 per MCF during 2022.

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

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

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

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

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

International natural gas realizations averaged $7.69 per MCF during 2023, compared with $9.75 per MCF during 2022, mainly due to lower LNG prices.

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

(PDC) and growth in the Permian Basin.

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

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

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

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

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

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start-up or ramp-up of projects;

acquisition and divestment of assets;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Additionally, the company has a growing presence in renewable fuels in the United States after acquiring REG in 2022.

Refer to the “Results of Operations” section on page 42 for additional discussion of the company’s downstream operations.

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

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

Noteworthy Developments

Key noteworthy developments and other events during 2023 and early 2024 included the following:

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

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

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

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

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

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

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

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

Nigeria Extended Agbami and Usan leases to 2042.

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

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

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

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

Gulf of Mexico.

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

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

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

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

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

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

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

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

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

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

Gulf Coast at its 50 percent owned affiliate, CPChem.

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

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

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

United States Announced collaboration with Raven SR Inc.

and Hyzon Motors to produce hydrogen from green waste.

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

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

(carbon capture).

Angola Received approvals to extend Block 0 concession through 2050.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

and PetroIndependiente, S.A.

through 2041.

Common Stock Dividends The 2023 annual dividend was $6.04 per share, making 2023 the 36th consecutive year that the company increased its annual per share dividend payout.

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

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

Common Stock Repurchase Program The company repurchased $14.9 billion of its common stock in 2023 under its stock repurchase program.

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

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

Results of Operations

4 unchanged sentences

A discussion of variances between 2022 and 2021 can be found in the “Results of Operations” section on pages 39 through 40 of the company’s 2022 Annual Report on Form 10-K filed with the SEC on February 23, 2023.

Millions of dollars 2022 2021 2020

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

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

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

The company’s average realization for U.S.

crude oil and natural gas liquids in 2022 was $76.71 per barrel compared with $56.06 in 2021.

The average natural gas realization was $5.55 per thousand cubic feet in 2022, compared with $3.11 in 2021.

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

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

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

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

2023 2022 2021

Earnings $MM $ 4,148 $ 12,621 $ 7,319

Net Oil-Equivalent Production MBOED 1,349 1,181 1,139

Liquids Production MBD 997 888 858

Natural Gas Production MMCFD 2,112 1,758 1,689

Liquids Realization $/BBL $ 59.19 $ 76.71 $ 56.06

Natural Gas Realization $/MCF $ 1.67 $ 5.55 $ 3.11

* MBD — thousands of barrels per day;

MMCFD — millions of cubic feet per day;

BBL — Barrel;

MCF — thousands of cubic feet;

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

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

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

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

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

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

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

International Upstream

Millions of dollars 2022 2021 2020

Earnings (Loss) *

2023 2022 2021

$MM $ 13,290 $ 17,663 $ 8,499

Net Oil-Equivalent Production MBOED 1,771 1,818 1,960

Liquids Production MBD 833 831 956

Natural Gas Production MMCFD 5,632 5,919 6,020

Liquids Realization $/BBL $ 71.70 $ 90.71 $ 64.53

Natural Gas Realization $/MCF $ 7.69 $ 9.75 $ 5.93

(1) Includes foreign currency effects:

$ 376 $ 816 $ 302

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

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

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

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

The company’s average realization for international crude oil and natural gas liquids in 2022 was $90.71 per barrel compared with $64.53 in 2021.

The average natural gas realization was $9.75 per thousand cubic feet in 2022 compared with $5.93 in 2021.

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

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

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

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

Millions of dollars 2022 2021 2020

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

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

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

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

(2) MBD — thousands of barrels per day;

MMCFD — millions of cubic feet per day;

BBL — Barrel;

MCF — thousands of cubic feet;

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

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

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

Net oil-equivalent production was down 47,000 barrels per day, or 3 percent.

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

2023 2022 2021

Earnings $MM $ 3,904 $ 5,394 $ 2,389

Refinery Crude Oil Inputs MBD 934 866 903

Refined Product Sales MBD 1,287 1,228 1,139

* MBD — thousands of barrels per day.

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

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

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

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

International Downstream

Millions of dollars 2022 2021 2020

2023 2022 2021

$MM $ 2,233 $ 2,761 $ 525

Refinery Crude Oil Inputs MBD 626 639 576

Refined Product Sales MBD 1,445 1,386 1,315

(1) Includes foreign currency effects:

$ (12) $ 235 $ 185

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

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

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

Millions of dollars 2022 2021 2020

(2) MBD — thousands of barrels per day.

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

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

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

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

Unit 2023 2022 2021

Net charges *

$ (2,974) $ (3,107) $ (3,157)

$MM $ (2,206) $ (2,974) $ (3,107)

* Includes foreign currency effects:

1 unchanged sentence

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

Net charges in 2022 decreased $133 million from 2021.

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

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

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

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

Consolidated Statement of Income

3 unchanged sentences

Sales and other operating revenues $ 196,913 $ 235,717 $ 155,606

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

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

Millions of dollars 2023 2022 2021

Income (loss) from equity affiliates $ 5,131 $ 8,585 $ 5,657

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

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

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

Millions of dollars 2023 2022 2021

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

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

Other income (loss) $ (1,095) $ 1,950 $ 1,202

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

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

Millions of dollars 2023 2022 2021

Purchased crude oil and products $ 119,196 $ 145,416 $ 92,249

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

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

Millions of dollars 2023 2022 2021

Operating, selling, general and administrative expenses $ 29,028 $ 29,026 $ 24,740

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

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

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

Millions of dollars 2023 2022 2021

Exploration expense $ 914 $ 974 $ 549

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

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

Millions of dollars 2023 2022 2021

Depreciation, depletion and amortization $ 17,326 $ 16,319 $ 17,925

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

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

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

Millions of dollars 2023 2022 2021

Taxes other than on income $ 4,220 $ 4,032 $ 3,963

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

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

Millions of dollars 2023 2022 2021

Interest and debt expense $ 469 $ 516 $ 712

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

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

Millions of dollars 2023 2022 2021

Other components of net periodic benefit costs $ 212 $ 295 $ 688

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

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

Millions of dollars 2023 2022 2021

Income tax expense (benefit) $ 8,173 $ 14,066 $ 5,950

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

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

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

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

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

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

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

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

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

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

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

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

income before tax decreased from $21.0 billion in 2022 to $8.6 billion in 2023.

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

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

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

International income before tax decreased from $28.7 billion in 2022 to $21.0 billion in 2023.

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

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

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

1 unchanged sentence

Selected Operating Data 1,2

2022 2021 2020

Net Crude Oil and Natural Gas Liquids Production (MBPD) 888 858 789

Net Natural Gas Production (MMCFPD) 3

1,758 1,689 1,607

Net Oil-Equivalent Production (MBOEPD) 1,181 1,139 1,058

Sales of Natural Gas (MMCFPD) 4

4,354 3,986 3,873

Sales of Natural Gas Liquids (MBPD) 276 201 208

Unit 2023 2022 2021

Net Crude Oil and Natural Gas Liquids (NGLs) Production MBD 997 888 858

Net Natural Gas Production 3

MMCFD 2,112 1,758 1,689

Net Oil-Equivalent Production MBOED 1,349 1,181 1,139

Sales of Natural Gas 4

MMCFD 4,637 4,354 3,986

Sales of NGLs MBD 354 276 201

Revenues from Net Production

Liquids ($/Bbl) $ 76.71 $ 56.06 $ 30.53

Crude $/BBL $ 75.04 $ 92.41 $ 65.29

NGLs $/BBL $ 20.04 $ 33.80 $ 28.46

Liquids (weighted average of Crude and NGLs) $/BBL $ 59.19 $ 76.71 $ 56.06

Natural Gas $/MCF $ 1.67 $ 5.55 $ 3.11

International Upstream

Net Crude Oil and Natural Gas Liquids Production (MBPD) 5

831 956 1,078

Net Natural Gas Production (MMCFPD) 3

5,919 6,020 5,683

Net Oil-Equivalent Production (MBOEPD) 4

1,818 1,960 2,025

Sales of Natural Gas (MMCFPD) 5,786 5,178 5,634

Sales of Natural Gas Liquids (MBPD) 107 84 46

Net Crude Oil and NGLs Production 5

MBD 833 831 956

Net Natural Gas Production 3

MMCFD 5,632 5,919 6,020

Net Oil-Equivalent Production 5

MBOED 1,771 1,818 1,960

Sales of Natural Gas MMCFD 6,025 5,786 5,178

Sales of NGLs MBD 94 107 84

Revenues from Liftings

Liquids ($/Bbl) $ 90.71 $ 64.53 $ 36.07

Crude $/BBL $ 74.29 $ 93.73 $ 65.77

NGLs $/BBL $ 24.01 $ 37.56 $ 40.35

Liquids (weighted average of Crude and NGLs) $/BBL $ 71.70 $ 90.71 $ 64.53

Natural Gas $/MCF $ 7.69 $ 9.75 $ 5.93

Worldwide Upstream

Net Oil-Equivalent Production (MBOEPD) 5

United States 1,181 1,139 1,058

International 1,818 1,960 2,025

Total 2,999 3,099 3,083

Gasoline Sales (MBPD) 6

Other Refined Product Sales (MBPD) 589 484 422

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

Sales of Natural Gas (MMCFPD) 4

Sales of Natural Gas Liquids (MBPD) 27 29 25

Refinery Crude Oil Input (MBPD) 866 903 793

Net Oil-Equivalent Production 5

United States MBOED 1,349 1,181 1,139

International MBOED 1,771 1,818 1,960

Total MBOED 3,120 2,999 3,099

Gasoline Sales 6

MBD 642 639 655

Other Refined Product Sales MBD 645 589 484

Total Refined Product Sales MBD 1,287 1,228 1,139

Sales of Natural Gas 4

MMCFD 32 24 21

Sales of NGLs MBD 22 27 29

Refinery Crude Oil Input MBD 934 866 903

International Downstream

Gasoline Sales (MBPD) 5

Other Refined Product Sales (MBPD) 1,050 994 957

Total Refined Product Sales (MBPD) 7

1,386 1,315 1,221

Sales of Natural Gas (MMCFPD) 4

Sales of Natural Gas Liquids (MBPD) 127 96 74

Refinery Crude Oil Input (MBPD) 639 576 584

Gasoline Sales 6

MBD 353 336 321

Other Refined Product Sales MBD 1,092 1,050 994

Total Refined Product Sales 7

MBD 1,445 1,386 1,315

Sales of Natural Gas 4

Sales of NGLs MBD 153 127 96

Refinery Crude Oil Input MBD 626 639 576

1 Includes company share of equity affiliates.

2 MBPD – thousands of barrels per day;

MMCFPD – millions of cubic feet per day;

MBOEPD – thousands of barrels of oil-equivalents per day;

2 MBD – thousands of barrels per day;

MMCFD – millions of cubic feet per day;

MBOED – thousands of barrels of oil-equivalents per day;

Bbl – barrel;

1 unchanged sentence

Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil;

3 Includes natural gas consumed in operations (MMCFPD):

United States 53 44 37

International 517 548 566

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

3 Includes natural gas consumed in operations:

United States MMCFD 64 53 44

International MMCFD 532 517 548

4 Downstream sales of Natural Gas separately identified from Upstream.

5 Includes net production of synthetic oil:

Canada 45 55 54

Canada MBD 51 45 55

6 Includes branded and unbranded gasoline.

7 Includes sales of affiliates (MBPD):

7 Includes sales of affiliates:

MBD 389 389 357

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

2 unchanged sentences

Cash, Cash Equivalents and Marketable Securities Total balances were $8.2 billion and $17.9 billion at December 31, 2023 and 2022, respectively.

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

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

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

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

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

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

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

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

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

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

Capital expenditures totaled $15.8 billion in 2023 compared to $12.0 billion in 2022.

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

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

Restricted cash of $1.1 billion and $1.4 billion at December 31, 2023 and 2022, respectively, was held in cash and short-term marketable securities and recorded as “Deferred charges and other assets” and “Prepaid expenses and other current assets” on the Consolidated Balance Sheet.

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

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

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

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 $5.1 billion at December 31, 2023, compared with $6.0 billion at year-end 2022.

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

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

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

The company also irrevocably deposited sufficient U.S.

Treasury securities with U.S.

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

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

The company had no commercial paper outstanding as of December 31, 2023.

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

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

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

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

The company has outstanding public bonds issued by Chevron Corporation, Chevron U.S.A.

(CUSA), Noble Energy, Inc.

(Noble), and Texaco Capital Inc.

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Net income (loss) $ 12,190 $ 15,043

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

At December 31,

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Total net equity (deficit) $ (89,896) $ (76,681)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The timing of the

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

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

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

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

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Capex $ 11,729 $ 4,100 $ 15,829 $ 8,856 $ 3,118 $ 11,974 $ 5,581 $ 2,475 $ 8,056

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

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

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

Capex excludes the acquisition cost of PDC.

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

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

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

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

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

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

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

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

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

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

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

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

Year ended December 31

Millions of dollars 2022 2021 2020

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

Expensed exploration expenditures 488 431 500

Assets acquired through finance leases and other obligations 3 64 53

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

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

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

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

Year ended December 31

C&E 2022 2021 2020

Millions of dollars U.S.

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

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

All Other 310 25 335 221 20 241 226 13 239

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

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

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

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

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

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

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

Affiliate Capex by business segment for 2023, 2022 and 2021 is as follows:

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

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

The acquisitions of Renewable Energy Group Inc.

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

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

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

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

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

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

Year ended December 31

Affiliate C&E 2022 2021 2020

Affiliate Capex 2023 2022 2021

Millions of dollars U.S.

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All Other — — — — — — — — —

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

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

Affiliate Capex $ 983 $ 2,551 $ 3,534 $ 768 $ 2,598 $ 3,366 $ 367 $ 2,800 $ 3,167

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

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

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

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

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Current Ratio Current assets divided by current liabilities, which indicates the company’s ability to repay its short-term liabilities with short-term assets.

The current ratio in all periods was adversely affected by the fact that Chevron’s inventories are valued on a last-in, first-out basis.

The current ratio in all periods is adversely affected by the fact that Chevron’s inventories are valued on a last-in, first-out basis.

At year-end 2023, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $6.5 billion.

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This ratio indicates the company’s ability to pay interest on outstanding debt.

The company’s interest coverage ratio in 2022 was higher than 2021 due to higher income.

Year ended December 31

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The estimates of financial exposure to market risk do not represent the company’s projection of future market changes.

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

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

Risk Factors .

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

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

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.

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

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The foreign currency derivative contracts, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.

There were no material open foreign currency derivative contracts at December 31, 2022.

There were no open foreign currency derivative contracts at December 31, 2023.

Interest Rates The company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt.

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Refer to the discussion below for additional information on environmental matters and their impact on Chevron, and on the company’s 2023 environmental expenditures.

Refer to Note 24 Other Contingencies and Commitments under the heading “Environmental” for additional discussion of environmental remediation provisions and year-end reserves.

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

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

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

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

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

Refer to Item 1A.

Risk Factors for a discussion of some of the inherent risks of increasingly restrictive environmental and other regulation that could materially impact the company’s results of operations or financial condition.

Refer to Business Environment and Outlook on pages 34 through 36 for a discussion of legislative and regulatory efforts to address climate change.

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

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Using definitions and guidelines established by the American Petroleum Institute, Chevron estimated its worldwide environmental spending in 2023 at approximately $2.5 billion for its consolidated companies.

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

Included in these expenditures were approximately $0.5 billion of environmental capital expenditures and $2.0 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.

For 2024, total worldwide environmental capital expenditures are estimated at $0.5 billion.

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

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

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

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

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

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

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

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

Amortization - Capitalized exploratory drilling and development costs are depreciated on a unit-of-production (UOP) basis using proved developed reserves.

Depreciation, Depletion and Amortization (DD&A) - Capitalized exploratory drilling and development costs are depreciated on a unit-of-production (UOP) basis using proved developed reserves.

Acquisition costs of proved properties are amortized on a UOP basis using total proved reserves.

During 2022, Chevron’s UOP Depreciation, Depletion and Amortization (DD&A) for oil and gas properties was $10.8 billion, and proved developed reserves at the beginning of 2022 were 6.6 billion barrels for consolidated companies.

During 2023, Chevron’s UOP DD&A for oil and gas properties was $10.8 billion, and proved developed reserves at the beginning of 2023 were 6.5 billion barrels for consolidated companies.

If the estimates of proved reserves used in the UOP calculations for consolidated operations had been lower by five percent across all oil and gas properties, UOP DD&A in 2023 would have increased by approximately $600 million.

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

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

Refer to Table V , “Proved Reserve Quantity Information,” for the changes in proved reserve estimates for each of the three years ended December 31, 2021, 2022 and 2023, and to Table VII , “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” for estimates of proved reserve values for each of the three years ended December 31, 2021, 2022 and 2023.

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

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

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

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.

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

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

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

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

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

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

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

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

As an indication of the sensitivity of pension expense to the long-term rate of return assumption, a 1 percent increase in this assumption for the company’s primary U.S.

As an indication of the sensitivity of pension expense to the long-term rate of return assumption, a one percent increase in this assumption for the company’s primary U.S.

pension plan, which accounted for about 55 percent of companywide pension expense, would have reduced total pension plan expense for 2023 by approximately $78 million.

A 1 percent increase in the discount rates for this same plan would have reduced pension expense for 2022 by approximately $177 million.

A one percent increase in the discount rates for this same plan would have reduced pension expense for 2023 by approximately $105 million.

The aggregate funded status recognized at December 31, 2023, was a net liability of approximately $1.5 billion.

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

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

For the company’s OPEB plans, expense for 2023 was $86 million, and the total liability, all unfunded at the end of 2023, was $2.0 billion.

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In addition, information related to company contributions is included on page 96 in Note 23 Employee Benefit Plans under the heading “Cash Contributions and Benefit Payments.”

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

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

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

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

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

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

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

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Under the accounting rules, a liability is generally recorded for these types of contingencies if management determines the loss to be both probable and estimable.

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

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

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

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

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

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

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

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

more likely than not (i.e., likelihood greater than 50 percent) to be allowed by the tax jurisdiction.

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.

Risk Factors , on page 26.

New Accounting Standards

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990 1,313 1,240 1,588 1,623 2,410 2,467 2,085

327 726 923 (26) 611 511 38 42

Other income (loss) (2,743) 845 440 363 327 726 923 (26)

Total Revenues and Other Income 47,180 54,080 48,896 50,793 56,473 66,644 68,762 54,373

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Net Income (Loss) $ 2,243 $ 6,555 $ 6,008 $ 6,605 $ 6,378 $ 11,238 $ 11,715 $ 6,277

Net income attributable to noncontrolling interests

25 7 93 18 27 4 12 21

Net income (loss) attributable to noncontrolling interests (16) 29 (2) 31 25 7 93 18

Net Income (Loss) Attributable to Chevron Corporation $ 2,259 $ 6,526 $ 6,010 $ 6,574 $ 6,353 $ 11,231 $ 11,622 $ 6,259

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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, 2023.

The company excluded PDC Energy, Inc.

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

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

/s/ MICHAEL K.

WIRTH /s/ PIERRE R.

BREBER /s/ ALANA K.

Wirth Pierre R.

Breber David A.

Breber Alana K.

Chairman of the Board Vice President Vice President

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

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

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

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

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

Definition and Limitations of Internal Control over Financial Reporting

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

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

Financial Table of Contents

transactions and dispositions of the assets of the company;

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

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

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

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

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

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 $135.0 billion as of December 31, 2023, and depreciation, depletion and amortization expense was $15.8 billion for the year ended December 31, 2023.

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

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

As disclosed by management, variables impacting the Company’s estimated volumes of proved crude oil 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.

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

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

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.

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

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

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

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.

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

The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ findings.

PricewaterhouseCoopers LLP

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.

/s/ PricewaterhouseCoopers LLP

San Francisco, California

8 unchanged sentences

Income (loss) from equity affiliates 5,131 8,585 5,657

Other income 1,950 1,202 693

Other income (loss) ( 1,095 ) 1,950 1,202

Total Revenues and Other Income 200,949 246,252 162,465

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Reclassification to net income 33 ( 80 ) 6

Income taxes on derivatives transactions 3 — —

Income tax benefit (cost) on derivatives transactions ( 5 ) 3 —

Total 17 ( 12 ) —

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Treasury stock transactions 315 — — — 315 — 315

Noble acquisition 2

( 520 ) — — 4,629 4,109 779 4,888

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

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

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Treasury stock transactions 63 — — — 63 — 63

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

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

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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

4 unchanged sentences

Purchases of treasury shares 2

— — — ( 15,085 ) ( 15,085 ) — ( 15,085 )

Issuances of treasury shares 17 — — 246 263 — 263

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Changes reflect capital in excess of par.

2 Includes $ 120 redeemable noncontrolling interest.

2 Includes excise tax on share repurchases.

3 Beginning and ending total issued share balances include 14,168,000 shares associated with Chevron’s Benefit Plan Trust.

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

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

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

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

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

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

Revenue is recognized when the performance obligation is satisfied, which typically occurs at the point in time when control of the product transfers to the customer.

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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, 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.

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

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

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

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

Commencing for grants issued in January 2023

Standard restricted stock unit awards have cliff vesting by which the total award will vest on January 31 on or after

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

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

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

Commencing for grants issued in January 2023 and after, standard restricted stock units vest ratably on an annual basis over a three-year period.

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

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Net borrowings (repayments) of short-term obligations consisted of the following gross and net amounts:

Proceeds from issuances of short-term obligations $ — $ 4,448 $ 10,846

Repayments of short-term obligations $ — $ — $ ( 6,906 )

Proceeds from issuances of short-term debt obligations — — 4,448

Net borrowings (repayments) of short-term obligations with three months or less maturity 135 263 ( 3,114 )

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

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

The company did not have any material impairments in 2021.

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

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

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

Gulf of Mexico.

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

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

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

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Payments for other assets and liabilities, net

169 ( 2 ) ( 33 )

Capital expenditures $ 15,829 $ 11,974 $ 8,056

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New Accounting Standards

There are not currently any new or pending accounting standards that have a significant impact on Chevron.

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

The standard requires companies to disclose significant segment expenses.

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

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

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

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

Lease Commitments

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

Notes to the Consolidated Financial Statements

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At December 31, 2023 At December 31, 2022

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

Notes to the Consolidated Financial Statements

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Year-ended December 31

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Year 2024 $ 1,673 $ 84

2025 1,153 79

Thereafter 1,364 443

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Additionally, the company has $ 232 in future undiscounted cash flows for operating leases not yet commenced.

These leases are primarily for drill ships and drilling rigs.

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

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

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

Notes to the Consolidated Financial Statements

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Summarized Financial Data – Chevron U.S.A.

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4,598 13,315 6,904

Notes to the Consolidated Financial Statements

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At December 31

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

Notes to the Consolidated Financial Statements

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At December 31

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The fair values reflect the cash that would have been received if the instruments were sold at December 31, 2023.

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

Notes to the Consolidated Financial Statements

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amount to the Consolidated Statement of Income.

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

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The company does not materially adjust this information.

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

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

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

The company did not have any individually material impairments of long-lived assets measured at fair value on a nonrecurring basis to report in 2022.

Investments and Advances The company did not have any material impairments of investments and advances measured at fair value on a nonrecurring basis to report in 2023 or 2022.

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Derivatives - not designated 152 24 128 — 184 111 73 —

Derivatives - designated 7 7 — — — — — —

Total assets at fair value $ 204 $ 76 $ 128 $ — $ 407 $ 334 $ 73 $ —

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

The carrying value of these assets were written down to fair value based on estimates derived from internal 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.

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

Notes to the Consolidated Financial Statements

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

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

3 unchanged sentences

“Cash and cash equivalents” do not include investments with a carrying/fair value of $ 1,097 and $ 1,443 at December 31, 2023, and December 31, 2022, respectively.

At December 31, 2022, these investments are classified as Level 1 and include restricted funds related to certain upstream decommissioning activities, tax payments and a financing program.

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

Long-term debt, excluding finance lease liabilities, of $ 14,612 and $ 16,258 at December 31, 2023, and December 31, 2022, respectively, had estimated fair values of $ 13,709 and $ 14,959 , respectively.

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Fair value remeasurements of other financial instruments at December 31, 2023 and 2022, were not material.

Notes to the Consolidated Financial Statements

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Financial and Derivative Instruments

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Depending on the nature of the derivative transactions, bilateral collateral arrangements may also be required.

Derivative instruments measured at fair value at December 31, 2022, 2021 and 2020, and their classification on the Consolidated Balance Sheet below and Consolidated Statement of Income on the following page:

Derivative instruments measured at fair value at December 31, 2023, 2022 and 2021, and their classification on the Consolidated Balance Sheet and Consolidated Statement of Income are as follows:

Consolidated Balance Sheet:

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Type of Contract Balance Sheet Classification 2023 2022

Commodity Accounts and notes receivable, net

Commodity Accounts and notes receivable $ 151 $ 175

Commodity Long-term receivables, net

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( 154 ) ( 226 ) ( 64 )

Commodity Other income 10 ( 46 ) 7

Commodity Other income (loss) ( 47 ) 10 ( 46 )

$ ( 505 ) $ ( 867 ) $ ( 795 )

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

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

Notes to the Consolidated Financial Statements

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

At December 31, 2023, before-tax deferred gains in AOCL related to outstanding crude oil price hedging contracts were $ 7 , all of which is expected to be reclassified into earnings during the next 12 months as the hedged crude oil sales are recognized in earnings.

The table below represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated Balance Sheet at December 31, 2023 and 2022.

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

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

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

Notes to the Consolidated Financial Statements

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

Amounts not offset on the Consolidated Balance Sheet represent positions that do not meet all the conditions for “a right of offset.”

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

Derivative assets and liabilities are classified on the Consolidated Balance Sheet as “Accounts and notes receivable,” “Long-term receivables,” “Accounts payable,” and “Deferred credits and other noncurrent obligations.” Amounts not offset on the Consolidated Balance Sheet represent positions that do not meet all the conditions for “a right of offset.”

Concentrations of Credit Risk The company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, marketable securities, derivative financial instruments and trade receivables.

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

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

Year ended December 31

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Weighted-average number of common shares outstanding 1,873 1,931 1,916

1,931 1,916 1,870

Deferred awards held as stock units

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Weighted-average number of common shares outstanding 1,873 1,931 1,916

1,931 1,916 1,870

Deferred awards held as stock units

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* There was no effect of dividend equivalents paid on stock units or dilutive impact of employee stock-based awards on earnings.

2 Millions of shares;

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

Notes to the Consolidated Financial Statements

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Operating Segments and Geographic Data

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processing, transporting, storage and marketing of natural gas;

carbon capture and storage;

and a gas-to-liquids plant.

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

Notes to the Consolidated Financial Statements

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Year ended December 31

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$ 21,369 $ 35,465 $ 15,625

Notes to the Consolidated Financial Statements

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

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Tengizchevroil $ 26,954 $ 26,534 $ 3,375 $ 4,386 $ 2,831

Petropiar — — — — ( 1,396 )

Petroboscan — — — — ( 1,112 )

Caspian Pipeline Consortium 797 761 158 128 155

17 unchanged sentences

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

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

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

Petroboscan Chevron has a 39.2 percent interest in Petroboscan, a joint stock company which operates the Boscan Field in Venezuela.

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

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

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

2 unchanged sentences

Included in the investment balance is a loan with a principal balance of $ 387 to fund a portion of the Golden Triangle Polymers Project in Orange, Texas, in which Chevron Phillips Chemical Company LLC owns 51 percent.

Notes to the Consolidated Financial Statements

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

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

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

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income i ncludes $ 13,623 , $ 16,286 and $ 10,796 with affiliated companies for 2023, 2022 and 2021, respectively.

“Purchased crude oil and products” includes $ 7,404 , $ 10,171 and $ 5,778 with affiliated companies for 2023, 2022 and 2021, respectively.

1 unchanged sentence

“Accounts payable” includes $ 591 and $ 709 due to affiliated companies at December 31, 2023 and 2022, respectively.

Notes to the Consolidated Financial Statements

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The following table provides summarized financial information on a 100 percent basis for all equity affiliates as well as Chevron’s total share, which includes Chevron’s net loans to affiliates of $ 4,494 , $ 4,278 and $ 4,704 at December 31, 2023, 2022 and 2021, respectively.

15 unchanged sentences

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

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

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

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

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

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

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

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

The Second Circuit affirmed, and the U.S.

Supreme Court denied certiorari in 2017.

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

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

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

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

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

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

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

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

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

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

In 2018, the tribunal ruled in Chevron’s favor, finding that the Ecuadorian judgment was procured through fraud, bribery, and corruption and was based on environmental claims that Ecuador had already settled and released.

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

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

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

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

2022, Ecuador appealed to the Dutch Supreme Court.

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

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

Climate Change

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

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

cities and counties, three U.S.

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

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

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

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

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

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

Chevron entities are or were among the codefendants in 29 separate lawsuits filed by various U.S.

cities and counties, four U.S.

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

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

The lawsuits have asserted various causes of action, including public nuisance, private nuisance, failure to warn, fraud, conspiracy to commit fraud, design defect, product defect, trespass, negligence, impairment of public trust, equitable relief for pollution, impairment and destruction of natural resources, unjust enrichment, violations of consumer protection statutes, violations of unfair competition statutes, violations of a federal antitrust statute, and violations of federal and state RICO statutes, based upon, among other things, the company’s production of oil and gas products and alleged misrepresentations or omissions relating to climate change risks associated with those products.

Further such proceedings 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.

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.

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.

1 The cases are:

Exxon Mobil Corp., et al.

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

City of Annapolis v.

BP P.L.C., et al.

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

County of Anne Arundel v.

BP P.L.C., et al.

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

Mayor and City Council of Baltimore v.

BP P.L.C., et al.

24-C-18-004219 (Md.

People ex rel.

Exxon Mobil Corp., et al.

CGC-23-609134 (Cal.

City of Charleston v.

Brabham Oil Co., et al.

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

of Common Pleas);

District of Columbia v.

Exxon Mobil Corp., et al.

2020-CA-002892-B (D.C.

Delaware ex rel.

BP America Inc., et al.

N20C-09-097 (Del.Super.

City of Hoboken v.

Exxon Mobil Corp., et al.

HUD-L-003179-20 (N.J.

City and County of Honolulu, et al.

Sunoco LP, et al.

1CCV-20-0000380 (Haw.

City of Imperial Beach v.

Chevron Corp., et al.

C17-01227 (Cal.

King County v.

, et al., No.

18-2-11859-0 (Wash.

Ct.) (voluntarily dismissed);

Makah Indian Tribe v.

Exxon Mobil Corp., et al.

23-25216-1-SEA (Wash.

County of Marin v.

Chevron Corp., et al.

17-cv-02586 (Cal.

County of Maui v.

Sunoco LP, et al.

2CCV-20-0000283 (Haw.

County of Multnomah v.

Exxon Mobil Corp., et al.

23-cv-25164 (Or.

Municipality of San Juan, Puerto Rico v.

Exxon Mobil Corp., et al.

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

City of Oakland v.

BP p.l.c., et al.

RG17875889 (Cal.

Platkin, et al.

Exxon Mobil Corp., et al.

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

City of New York v.

Chevron Corp., et al.

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

Pacific Coast Federation of Fishermen’s Associations v.

Chevron Corp., et al.

CGC-18-571285 (Cal.

Ct.) (voluntarily dismissed);

State of Rhode Island v.

Chevron Corp., et al ., No.

PC-2018-4716 (R.I.

City of Richmond v.

Chevron Corp., et al.

C18-00055 (Cal.

City of San Francisco v.

BP P.L.C., et al.

CGC-17-561370 (Cal.

County of San Mateo v.

Chevron Corp., et al.

17-CIV-03222 (Cal.

City of Santa Cruz v.

Chevron Corp., et al.

17-cv-03243 (Cal.

County of Santa Cruz v.

Chevron Corp., et al ., No.

17-cv-03242 (Cal.

Shoalwater Bay Indian Tribe v.

Exxon Mobil Corp., et al.

23-2-25215-2-SEA (Wash.

City of Chicago v.

BP p.l.c., et al.

2024-CH-01024 (Ill.

Notes to the Consolidated Financial Statements

Financial Table of Contents

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).

1 unchanged sentence

2 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.

Plaintiffs’ SLCRMA theories are unprecedented;

thus, there remains significant uncertainty about the scope of the claims and alleged damages and any potential effects on the company’s results of operations and financial condition.

Further such proceedings may be filed by other parties.

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

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

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

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

2 The cases are:

Jefferson Parish v.

Atlantic Richfield Company, et al ., No.

732-768 (24th Jud.

Ct., Jefferson Par.);

Jefferson Parish v.

Chevron U.S.A.

Holdings, Inc., et al.

732-769 (24th Jud.

Ct., Jefferson Par.);

Jefferson Parish v.

Destin Operating Company, Inc., et al .

732-770 (24th Jud.

Ct., Jefferson Par.);

Jefferson Parish v.

Canlan Oil Company, et al.

732-771 (24th Jud.

Ct., Jefferson Par.);

Jefferson Parish v.

Anadarko E&P Onshore LLC, et al.

732-772 (24th Jud.

Ct., Jefferson Par.);

Jefferson Parish v.

ExxonMobil Corporation, et al.

732-774 (24th Jud.

Ct., Jefferson Par.);

Jefferson Parish v.

Equitable Petroleum Corporation, et al., No.

732-775 (24th Jud.

Ct., Jefferson Par.);

Plaquemines Parish v.

ConocoPhillips Co., et al.

60-982 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

HHE Energy Co., et al.

60-983 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

Exchange Oil & Gas Corp.

60-984 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

LLOG Exploration & Production Co.

60-985 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

Equitable Petroleum Corporation, et al.

60-986 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

June Energy, et al.

60-987 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

Linder Oil Company, et al.

60-988 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

Riverwood Production Company, et al.

60-989 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

Helis Oil & Gas Company, et al ., No.

60-990 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

Northcoast Oil Company, et al.

60-992 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

Goodrich Petroleum Company, L.L.C., et al.

60-994 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

Devon Energy Production Company, L.P., et al.

60-995 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

Rozel Operating Co., et al.

60-996 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

Palm Energy Offshore, L.L.C., et al.

60-997 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

Great Southern Oil & Gas Company, Inc., et al.

60-998 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

Hilcorp Energy Company, et al.

60-999 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

Apache Oil Corporation, et al.

61-000 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

Campbell Energy Corporation, et al.

61-001 (25th Jud.

Ct., Plaquemines Par.);

Plaquemines Parish v.

TotalPetrochemicals & Refining USA, Inc.

61-002 (25th Jud.

Ct., Plaquemines Par.);

Cameron Parish v.

Alpine Exploration Companies, Inc., et al.

10-19580 (38th Jud.

Ct., Cameron Par.);

Cameron Parish v.

Anadarko E&P Onshore, LLC, et al.

10-19578 (38th Jud.

Ct., Cameron Par.);

Cameron Parish v.

Apache Corporation (of Delaware), et al.

10-19579 (38th Jud.

Ct., Cameron Par.);

Cameron Parish v .

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

10-19582 (38th Jud.

Ct., Cameron Par.);

Cameron Parish v .

Ballard Exploration Company, Inc., et al.

10-19574 (38th Jud.

Ct., Cameron Par.);

Cameron Parish v.

Bay Coquille, Inc., et al.

10-19581 (38th Jud.

Ct., Cameron Par.);

Cameron Parish v.

BEPCO, LP, et al.

10-19572 (38th Jud.

Ct., Cameron Par.);

Cameron Parish v.

BP America Production Company, et al.

10-19576 (38th Jud.

Ct., Cameron Par.);

Cameron Parish v.

Brammer Engineering, Inc., et al ., No.

10-19573 (38th Jud.

Ct., Cameron Par.);

Cameron Parish v .

Burlington Resources, et al.

10-19575 (38th Jud.

Ct., Cameron Par.);

Gulfport Energy Corporation, et al.

102,146 (15th Jud.

Ct., Vermilion Par.);

Bernard Parish v.

Atlantic Richfield, et al.

16-1228 (34th Jud.

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

Financial Table of Contents

Millions of dollars, except per-share amounts

Year ended December 31

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

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

Year ended December 31

2023 2022 2021

9 unchanged sentences

federal income tax benefit

508 216 ( 65 )

Prior year tax adjustments, claims and settlements 1

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Chevron’s share of its equity affiliates’ total income tax expense in 2023 was $ 1,724 .

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

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

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

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

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

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

18 unchanged sentences

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

Deferred tax liabilities increased by $ 1,513 from year-end 2021, primarily driven by an increase to properties, plant and equipment.

Deferred tax assets decreased by $ 226 from year-end 2021.

This decrease was primarily related to decreases in employee benefits and tax loss carryforwards for various locations, partially offset by the increase in foreign tax credits.

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

Deferred tax assets increased by $ 628 from year-end 2022.

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

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

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foreign tax credit carryforwards of $ 13,560 will expire between 2024 and 2033.

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

At December 31, 2023 and 2022, deferred taxes were classified on the Consolidated Balance Sheet as follows:

4 unchanged sentences

Income taxes, including U.S.

state and foreign withholding taxes, are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely.

state and foreign withholding taxes, are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely, or where no taxable temporary differences exist that are attributable to unremitted earnings from an investment in a foreign entity.

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

state and foreign withholding tax purposes.

Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for possible future remittances totaled approximately $ 51,300 at December 31, 2022.

This amount represents earnings reinvested as part of the company’s ongoing international business.

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

3 unchanged sentences

The following table indicates the changes to the company’s unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021.

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.

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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Millions of dollars, except per-share amounts

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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Additions for tax positions taken in prior years

Reductions based on tax positions taken in current year ( 104 ) — —

Reductions for tax positions taken in prior years

3 unchanged sentences

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

— ( 87 ) ( 16 )

Balance at December 31 $ 5,452 $ 5,323 $ 5,288

1 unchanged sentence

Certain of these unrecognized tax benefits relate to tax carryforwards that may require a full valuation allowance at the time of any such recognition.

Tax positions for Chevron and its subsidiaries and affiliates are subject to income tax audits by many tax jurisdictions throughout the world.

For the company’s major tax jurisdictions, examinations of tax returns for certain prior tax years had not been completed as of December 31, 2022.

For these jurisdictions, the latest years for which income tax examinations had been finalized were as follows:

United States – 2016, Nigeria – 2007, Australia – 2009, Kazakhstan – 2012 and Saudi Arabia – 2016.

The company and its subsidiaries are subject to income taxation and audits throughout the world.

With certain exceptions, income tax examinations are completed through 2016 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, 2022, it is reasonably possible that developments on tax matters in certain tax jurisdictions may result in decreases of approximately 20 percent within the next 12 months.

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 beyond the next 12 months.

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

and penalties was included on the Consolidated Balance Sheet, compared with accrued benefit of $( 76 ) as of year-end 2021.

On the Consolidated Statement of Income, the company reports interest and penalties related to liabilities for uncertain tax positions as “Income Tax Expense (Benefit).” As of December 31, 2023, accrued expense of $ 229 for anticipated interest and penalties was included on the Consolidated Balance Sheet, compared with accrued benefit of $ 112 as of year-end 2022.

Income tax expense (benefit) associated with interest and penalties was $ 124 , $ 152 and $ 19 in 2023, 2022 and 2021, respectively.

16 unchanged sentences

Total taxes other than on income $ 4,220 $ 4,032 $ 3,963

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

Properties, Plant and Equipment 1

17 unchanged sentences

Australia had PP&E of $ 41,409 , $ 44,012 and $ 46,687 in 2023, 2022 and 2021, respectively.

Gross Investment at Cost, Net Investment and Additions at Cost for 2020 each include $ 16,703 associated with the Noble acquisition.

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

2 Net of dry hole expense related to prior years’ expenditures of $ 110 , $ 177 and $ 35 in 2023, 2022 and 2021, respectively.

3 Depreciation expense includes accretion expense of $ 593 , $ 560 and $ 616 in 2023, 2022 and 2021, respectively, and impairments and write-offs of $ 2,180 , $ 950 and $ 414 in 2023, 2022 and 2021, respectively.

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

Short-Term Debt

31 unchanged sentences

$ 1,650 $ 1,650

Floating rate notes due 2023 3.384 3.121 - 3.821

Notes due 2025 1.724 0.687 - 3.326

4 unchanged sentences

Notes due 2030 2.236 1,500 1,500

Debentures due 2031 8.625 102 102

21 unchanged sentences

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

Chevron has an automatic shelf registration statement that expires in August 2023.

This registration statement is for an unspecified amount of nonconvertible debt securities issued or guaranteed by Chevron Corporation or CUSA.

Long-term debt excluding finance lease liabilities with a principal balance of $ 16,281 matures as follows:

5 unchanged sentences

and after 2028 – $ 5,781 .

In addition to the $ 4.9 billion in long-term debt that matured in 2022, the company also early-redeemed $ 3.0 billion in notes at face value that were scheduled to mature in the second quarter of 2023.

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

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

The company also irrevocably deposited sufficient U.S.

Treasury securities with U.S.

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

See Note 9 Fair Value Measurements for information concerning the fair value of the company’s long-term debt.

14 unchanged sentences

Ending balance at December 31 $ 1,648 $ 1,627 $ 2,109

* 2020 represents fair value of well costs acquired in the Noble acquisition.

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:

9 unchanged sentences

Of the $ 1,570 of exploratory well costs capitalized for more than one year at December 31, 2023, $ 844 is related to seven projects that had drilling activities underway or firmly planned for the near future.

The $ 609 balance is related to five projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not underway or firmly planned for the near future.

The $ 726 balance is related to six projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not underway or firmly planned for the near future.

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 $ 726 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability:

(a) $ 194 ( three projects) – undergoing front-end engineering and design with final investment decision expected within four years ;

(a) $ 311 ( 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 13 projects, the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations associated with the projects.

More than three-quarters of these decisions are expected to occur in the next five years .

Approximately three-quarters of these decisions are expected to occur in the next five years .

The $ 1,570 of suspended well costs capitalized for a period greater than one year as of December 31, 2023, represents 71 exploratory wells in 13 projects.

14 unchanged sentences

Compensation expense for stock options for 2023, 2022 and 2021 was $ 85 ($ 65 after tax), $ 60 ($ 46 after tax) and $ 60 ($ 47 after tax), respectively.

In addition, compensation expense for stock appreciation rights, restricted stock, performance shares and restricted stock units was $ 1,013 ($ 770 after tax), $ 701 ($ 554 after tax) and $ 96 ($ 76 after tax) for 2022, 2021 and 2020, respectively.

In addition, compensation expense for stock appreciation rights, restricted stock, performance shares and restricted stock units resulted in a net benefit of $( 100 ) ($( 76 ) after tax) for 2023, primarily as a result of reductions in the fair value of outstanding liability-classified performance shares that are remeasured each reporting period.

Compensation expense for stock appreciation rights, restricted stock, performance shares and restricted stock units was $ 1,013 ($ 770 after tax) and $ 701 ($ 554 after tax) for 2022 and 2021, respectively.

No significant stock-based compensation cost was capitalized at December 31, 2023, or December 31, 2022.

14 unchanged sentences

Forfeitures of stock options are estimated using historical forfeiture data dating back to 1990.

Noble Share-Based Plans (Noble Plans) When Chevron acquired Noble in October 2020, outstanding stock options granted under various Noble Plans were exchanged for Chevron options.

These awards retained the same provisions as the original Noble Plans.

Awards issued may be exercised for up to five years after termination of employment, depending upon the termination type, or the original expiration date, whichever is earlier.

Other awards issued under the Noble Plans included restricted stock awards, restricted stock units, and performance shares, which retained the same provisions as the original Noble Plans.

Upon termination of employment due to change-in-control, all unvested awards issued under the Noble Plans, including stock options, restricted stock awards, restricted stock units and performance shares vested on the termination date.

If not exercised, awards will expire between 2023 and 2029.

Fair Value and Assumptions The fair market values of stock options and stock appreciation rights granted in 2023, 2022 and 2021 were measured on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions:

21 unchanged sentences

During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

As of December 31, 2023, there was $ 181 of total unrecognized before-tax compensation cost related to nonvested share-based compensation arrangements granted under the plan.

4 unchanged sentences

The fair value of the liability recorded for these instruments was $ 360 and was measured largely using the Monte Carlo simulation method.

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

At January 1, 2023, the number of restricted stock units outstanding was equivalent to 4,287,826 shares.

During 2023, 1,739,120 restricted stock units were granted, 866,494 units vested with cash proceeds distributed to recipients and 100,210 units were forfeited.

At December 31, 2022, there were 4,287,826 restricted stock units outstanding that are payable in cash.

The fair value of the liability recorded for the vested portion of these instruments was $ 548 , valued at the stock price as of December 31, 2022.

At December 31, 2023, there were 5,060,242 restricted stock units outstanding, of which 3,905,243 are payable in cash and 1,154,999 are payable in shares.

The fair value of the liability recorded for the vested portion of these instruments payable in cash was $ 457 , valued at the stock price as of December 31, 2023.

In addition, outstanding stock appreciation rights that were granted under the LTIP totaled 652,493 equivalent shares as of December 31, 2023.

12 unchanged sentences

The company recognizes the overfunded or underfunded status of each of its defined benefit pension and OPEB plans as an asset or liability on the Consolidated Balance Sheet.

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

The funded status of the company’s pension and OPEB plans for 2023 and 2022 follows:

12 unchanged sentences

Curtailment — 2 — — — —

Special termination costs — 2 — — — —

Benefit obligation at December 31 10,392 3,605 9,713 3,354 2,017 1,938

8 unchanged sentences

Funded status at December 31 $ ( 1,255 ) $ ( 207 ) $ ( 1,771 ) $ ( 68 ) $ ( 2,017 ) $ ( 1,938 )

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

Amounts recognized on the Consolidated Balance Sheet for the company’s pension and OPEB plans at December 31, 2023 and 2022, include:

5 unchanged sentences

Net amount recognized at December 31 $ ( 1,255 ) $ ( 207 ) $ ( 1,771 ) $ ( 68 ) $ ( 2,017 ) $ ( 1,938 )

For the year ended December 31, 2023, the increase in benefit obligations was primarily due to actuarial losses caused by lower discount rates used to value the obligations.

For the year ended December 31, 2022, the decrease in benefit obligations was primarily due to actuarial gains caused by higher discount rates used to value the obligations and benefit payments paid to retirees in 2022.

For the year ended December 31, 2021, the decrease in benefit obligations was primarily due to actuarial gains caused by higher discount rates used to value the obligations and large benefit payments paid to retirees in 2021.

Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $ 3,792 and $ 3,446 at the end of 2023 and 2022, respectively.

9 unchanged sentences

and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2023 and 2022, was:

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

Pension Benefits

3 unchanged sentences

The components of net periodic benefit cost and amounts recognized in the Consolidated Statement of Comprehensive Income for 2023, 2022 and 2021 are shown in the table below:

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

Pension Benefits

9 unchanged sentences

Curtailment losses (gains) — 2 — ( 5 ) — ( 1 ) — — —

Special termination benefits — 2 — — — — — — —

Acquisition/Divestiture losses (gains) — ( 2 ) — — — — — — —

Total net periodic benefit cost 492 65 709 54 1,072 149 86 89 85

24 unchanged sentences

For 2023, the company used an expected long-term rate of return of 7.0 percent for U.S.

pension plan assets, which account for 67 percent of the company’s pension plan assets.

pension plan assets, which account for 71 percent of the company’s pension plan assets at the beginning of the year.

The market-related value of assets of the main U.S.

2 unchanged sentences

For other plans, market value of assets as of year-end is used in calculating the pension expense.

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

Discount Rate The discount rate assumptions used to determine the U.S.

5 unchanged sentences

pension and OPEB plans.

Notes to the Consolidated Financial Statements

Financial Table of Contents

Millions of dollars, except per-share amounts

Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2023, for the main U.S.

42 unchanged sentences

Total at December 31, 2023 $ 9,137 $ 2,831 $ 1,067 $ 57 $ 5,182 $ 3,398 $ 505 $ 625 $ 81 $ 2,187

equities include investments in the company’s common stock in the amount of $ 0 at December 31, 2022, and $ 0 at December 31, 2021.

1 There were no investments in the company’s common stock at December 31, 2023 or December 31, 2022.

2 Collective Trusts/Mutual Funds for U.S.

12 unchanged sentences

The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below:

Equity Fixed Income

International Corporate Bank Loans Real Estate Other Total

International Real Estate Other Total

Total at December 31, 2021 $ — $ 1 $ 42 $ 161 $ 204

24 unchanged sentences

The other significant international pension plans also have established maximum and minimum asset allocation ranges that vary by plan.

Actual asset allocation within approved ranges is based on a variety of factors, including market conditions and illiquidity constraints.

Actual asset allocation within approved ranges is based on a variety of factors, including market conditions and liquidity constraints.

To mitigate concentration and other risks, assets are invested across multiple asset classes with active investment managers and passive index funds.

27 unchanged sentences

The shares held in the trust are not considered outstanding for earnings-per-share purposes until distributed or sold by the trust in payment of benefit obligations.

Prior to its acquisition by Chevron, Unocal established various grantor trusts to fund obligations under some of its benefit plans, including the deferred compensation and supplemental retirement plans.

At December 31, 2022 and 2021, trust assets of $ 35 and $ 36 , respectively, were invested primarily in interest-earning accounts.

Employee Incentive Plans The Chevron Incentive Plan is an annual cash bonus plan for eligible employees that links awards to corporate, business unit and individual performance in the prior year.

Employee Incentive Plans The Chevron Incentive Plan is an annual cash bonus plan for eligible employees that links awards to corporate and individual performance in the prior year.

Charges to expense for cash bonuses were $ 809 , $ 1,169 and $ 1,165 in 2023, 2022 and 2021, respectively.

32 unchanged sentences

Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances by the company or other parties.

Such contingencies may exist for various operating, closed and divested sites,

Such contingencies may exist for various operating, closed and divested sites, including, but not limited to, U.S.

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

Notes to the Consolidated Financial Statements

1 unchanged sentence

Millions of dollars, except per-share amounts

including, but not limited to, U.S.

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

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.

2 unchanged sentences

Chevron’s environmental reserve as of December 31, 2023, was $ 936 .

Included in this balance was $ 218 related to remediation activities at approximately 143 sites for which the company had been identified as a potentially responsible party under the provisions of the U.S.

federal Superfund law or analogous state laws which provide for joint and several liability for all responsible parties.

Included in this balance was $ 232 related to remediation activities at sites for which the company had been identified as a potentially responsible party under the provisions of the U.S.

federal Superfund law which provide for joint and several liability for all responsible parties.

Any future actions by regulatory agencies to require Chevron to assume other potentially responsible parties’ costs at designated hazardous waste sites are not expected to have a material effect on the company’s results of operations, consolidated financial position or liquidity.

13 unchanged sentences

These activities, individually or together, may result in significant gains or losses in future periods.

In addition, some assets are sold along with their related liabilities and in certain instances, such transferred obligations have reverted and may in the future revert to the company and result in losses that could be significant.

In fourth quarter 2023, the company recognized an after-tax loss of $ 1,950 related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S.

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

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

Asset Retirement Obligations

6 unchanged sentences

No significant AROs associated with any legal obligations to retire downstream long-lived assets have been recognized, as indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the associated ARO.

The company performs periodic reviews of its downstream long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation.

The company performs periodic

Notes to the Consolidated Financial Statements

1 unchanged sentence

Millions of dollars, except per-share amounts

reviews of its downstream long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation.

The following table indicates the changes to the company’s before-tax asset retirement obligations in 2023, 2022 and 2021:

1 unchanged sentence

Balance at January 1 $ 12,701 $ 12,808 $ 13,616

Liabilities assumed in the Noble acquisition — — 630

Liabilities assumed in the PDC acquisition 220 — —

Liabilities incurred 183 9 31

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Balance at December 31 $ 13,833 $ 12,701 $ 12,808

In the table above, the amount associated with “Revisions in estimated cash flows” in 2021 primarily reflects increased cost estimates and scope changes to decommission wells, equipment and facilities.

In the table above, the amount associated with “Revisions in estimated cash flows” primarily reflects increased cost estimates and scope changes to decommission wells, equipment and facilities.

The long-term portion of the $ 13,833 balance at the end of 2023 was $ 12,122 .

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Refer to Note 14 Operating Segments and Geographic Data for additional information on the company’s segmentation of revenue.

Receivables related to revenue from contracts with customers are included in “Accounts and notes receivable, net” on the Consolidated Balance Sheet, net of the allowance for doubtful accounts.

Receivables related to revenue from contracts with customers are included in “Accounts and notes receivable” on the Consolidated Balance Sheet, net of the allowance for doubtful accounts.

The net balance of these receivables was $ 13,641 and $ 14,219 at December 31, 2023 and 2022, respectively.

Other items included in “Accounts and notes receivable, net” represent amounts due from partners for their share of joint venture operating and project costs and amounts due from others, primarily related to derivatives, leases, buy/sell arrangements and product exchanges, which are accounted for outside the scope of ASC 606 .

Other items included in “Accounts and notes receivable” represent amounts due from partners for their share of joint venture operating and project costs and amounts due from others, primarily related to derivatives, leases, buy/sell arrangements and product exchanges, which are accounted for outside the scope of ASC 606 .

Contract assets and related costs are reflected in “Prepaid expenses and other current assets” and contract liabilities are reflected in “Accrued liabilities” and “Deferred credits and other noncurrent obligations” on the Consolidated Balance Sheet.

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Earnings in 2021 included after-tax gains of approximately $ 785 relating to the sale of certain properties, of which approximately $ 30 and $ 755 related to downstream and upstream assets, respectively.

Earnings in 2022 included after-tax charges of approximately $ 1,075 for impairments and other asset write-offs and $ 600 for an early contract termination in upstream, and $ 271 for pension settlement costs.

Earnings in 2021 included after-tax charges of approximately $ 519 for pension settlement costs, $ 260 for early retirement of debt, $ 120 relating to upstream remediation and $ 110 relating to downstream legal reserves.

Earnings in 2020 included after-tax charges of approximately $ 4,800 for impairments and other asset write-offs related to upstream.

Earnings in 2023 included after-tax charges of approximately $ 1,950 for abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S.

Gulf of Mexico and $ 1,765 for upstream impairments, mainly in California, and several tax items with a net benefit of $ 655 .

Earnings in 2022 included after-tax charges of approximately $ 1,075 for impairments and other asset write-offs related to upstream, $ 600 for an early contract termination in upstream, and $ 271 for pension settlement costs.

Earnings in 2021 included after-tax charges of approximately $ 519 for pension settlement c osts, $ 260 for early retirement of debt, $ 120 relating to upstream remediation and $ 110 relating to downstream legal reserves.

Notes to the Consolidated Financial Statements

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Financial Instruments - Credit Losses

Chevron’s expected credit loss allowance balance was $ 1.0 billion as of December 31, 2022 and $ 745 million as of December 31, 2021, with a majority of the allowance relating to non-trade receivable balances.

The majority of the company’s receivable balance is concentrated in trade receivables, with a balance of $ 18.2 billion as of December 31, 2022, which reflects the company’s diversified sources of revenues and is dispersed across the company’s broad worldwide customer base.

Chevron’s expected credit loss allowance balance was $ 641 and $ 1,009 at December 31, 2023 and December 31, 2022, respectively, with a majority of the allowance relating to non-trade receivable balances.

The majority of the company’s receivable balance is concentrated in trade receivables, with a balance of $ 17,640 at December 31, 2023, which reflects the company’s diversified sources of revenues and is dispersed across the company’s broad worldwide customer base.

As a result, the company believes the concentration of credit risk is limited.

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This statistical approach becomes the basis of the company’s expected credit loss allowance for current trade receivables with payment terms that are typically short-term in nature, with most due in less than 90 days.

Chevron’s non-trade receivable balance was $ 4.3 billion as of December 31, 2022, which includes receivables from certain governments in their capacity as joint venture partners.

Chevron’s non-trade receivable balance was $ 3,864 at December 31, 2023, which includes receivables from certain governments in their capacity as joint venture partners.

Joint venture partner balances that are paid as per contract terms or not yet due are subject to the statistical analysis described above while past due balances are subject to additional qualitative management quarterly review.

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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 $ 560 million are included within “Investments and Advances” on the Consolidated Balance Sheet at both December 31, 2022 and December 31, 2021.

Acquisition of Renewable Energy Group, Inc.

On June 13, 2022, the company acquired Renewable Energy Group, Inc.

(REG), an independent company focused on converting natural fats, oils and greases into advanced biofuels.

REG utilizes a global integrated production, procurement, distribution and logistics network to operate 11 biorefineries in the U.S.

Ten biorefineries produce biodiesel and one produces renewable diesel.

The acquisition combines REG’s growing renewable fuels production and leading feedstock capabilities with Chevron’s large manufacturing, distribution and commercial marketing position.

Chevron acquired outstanding shares of REG in an all-cash transaction valued at $ 3.15 billion, or $ 61.50 per share.

As part of the transaction, the company recognized long-term debt and finance leases with a fair value of $ 590 million.

The acquisition was accounted for as a business combination under ASC 805, which requires assets acquired and liabilities assumed to be measured at their acquisition date fair values.

Provisional fair value measurements were made for acquired assets and liabilities, and adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as information necessary to complete the analysis is obtained.

Tangible and intangible assets were valued using a combination of replacement cost approach and discounted cash flows that incorporated internally generated price assumptions and production profiles together with appropriate operating and capital cost assumptions.

Debt assumed in the

Loans to equity affiliates and non-equity investees are also considered non-trade and associated allowances of $ 219 and $ 560 at December 31, 2023 and December 31, 2022, respectively, are included within “Investments and advances” on the Consolidated Balance Sheet.

Notes to the Consolidated Financial Statements

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Millions of dollars, except per-share amounts

acquisition was valued based on observable market prices for REG’s debt.

As a result of measuring the assets acquired and the liabilities assumed at fair value, the company recognized $ 293 million of goodwill.

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

At June 13, 2022

(Millions of dollars)

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.

Provisional fair value measurements were made for acquired assets and liabilities, and adjustments to those measurements may be made in subsequent periods, up to one year from the date of acquisition, as information necessary to complete the analysis is obtained.

Oil and gas properties were valued using a discounted cash flow approach that incorporated internally generated price assumptions and production profiles together with appropriate operating cost and development cost assumptions.

Debt assumed in the acquisition was valued based on observable market prices for PDC’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 provisional fair values assigned to assets acquired and liabilities assumed:

At August 7, 2023

Current assets $ 630

Properties, plant and equipment

Deferred tax 92

Other assets 118

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Current liabilities 1,376

Long-term debt and finance leases 590

Long-term debt 1,473

Deferred income tax 1,397

Other liabilities 469

Total liabilities assumed 4,715

Net assets acquired $ 2,862

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 and is anticipated to close around the middle of 2024.

The acquisition is subject to Hess stockholder approval.

It is also subject to regulatory approvals and other closing conditions.

Risk Factors for a discussion of risks related to the Hess acquisition.

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

In accordance with FASB and SEC disclosure requirements for oil and gas producing activities, this section provides supplemental information on oil and gas exploration and producing activities of the company in seven separate tables.

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 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

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Property acquisitions 2

Proved - Noble 3,463 — 438 7,945 — — 11,846 — —

Proved - Other 98 — 15 53 — — 166 — —

Unproved - Noble 2,845 2 113 129 — — 3,089 — —

Unproved - Other 13 16 — — — — 29 — —

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Total cost incurred by Consolidated Companies $ 24.6 $ 9.8 $ 7.4

Noble acquisition — — (14.9)

PDC Energy, Inc.

(PDC) acquisition (10.5) — —

Expensed exploration costs (0.5) (0.5) (0.4) (Geological and geophysical and other exploration costs)

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

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

Refer to Note 15 Investments and Advances for a discussion of the company’s major equity affiliates.

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Unproved properties valuation (71) (68) (44) — — — (183) — —

Other income (expense) 3

Other income (loss) 3

(2,673) (69) 45 89 (52) 4 (2,656) 32 (185)

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Unproved properties valuation (38) (250) (15) (124) — — (427) — —

Other income (expense) 3

Other income (loss) 3

92 21 300 180 51 105 749 195 (27)

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3 Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses.

2023 also includes a loss related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S.

Gulf of Mexico.

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

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Unproved properties valuation (43) (95) (5) — — — (143) — —

Other income (expense) 3

Other income (loss) 3

990 (33) (72) (124) 26 2 789 98 (332)

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2 Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel.

3 2020 unit prices have been conformed to current presentation.

Crude and NGL realizations were previously combined and disclosed as liquids.

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

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

The company’s annual reserve activity is also reviewed with the Board of Directors.

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

If major changes to reserves were to occur between the annual reviews, those matters would also be discussed with the Board.

RAC subteams also conduct in-depth reviews during the year of many of the fields that have large proved reserves quantities.

RAC sub-teams also conduct in-depth reviews during the year of many of the fields that have large proved reserves quantities.

These reviews include an examination of the proved reserve records and documentation of their compliance with the Chevron Corporation Reserves Manual .

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Proved Undeveloped Reserves

Noteworthy changes in proved undeveloped reserves are shown in the table below and discussed on the following page.

Noteworthy changes in proved undeveloped reserves are shown in the table below and discussed below.

Proved Undeveloped Reserves (Millions of BOE)

Quantity at January 1 3,907

Revisions (481)

Improved recovery —

Extension and discoveries 314

Purchases 312

Transfers to proved developed (596)

Quantity at December 31 3,456

In 2022, revisions include an increase of 257 million BOE in Israel, due to new wells and performance revisions in the Leviathan and Tamar fields.

This increase was largely offset by decreases of 145 million BOE from the United States primarily from portfolio optimizations in the Midland and Delaware basins, 69 million BOE in Kazakhstan primarily at TCO as higher prices reduced entitlement (Entitlement effects) and changes in operating assumptions reduced estimated

In 2023, revisions include a net decrease of 407 million BOE in the United States.

Revisions in Midland and Delaware basins yielded a decrease of 275 million BOE mainly due to a decrease of 186 million BOE from portfolio optimization and a reduction of 74 million BOE from reservoir performance.

Reduced development activities contributed to a net decrease of 114 million BOE in east Texas and California.

In Kazakhstan, primarily at TCO, performance-driven reservoir model changes led to a net decrease of 107 million BOE to proved undeveloped reserves with a largely offsetting increase

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

undeveloped reserves, and 31 million BOE in Nigeria due to lower expected offtake of natural gas relative to contracted volumes.

In 2022, extensions and discoveries of 578 million BOE in the United States were primarily due to the increase of activity and planned development of new locations in shale and tight assets in the Midland, Delaware and DJ basins.

In Other Americas, 34 million BOE of extensions and discoveries were from shale and tight assets in Argentina and Canada.

to proved developed reserves in existing wells.

These reductions were partially offset by an increase of 49 million BOE in Israel mainly due to the final investment decision on a new gas pipeline project.

In 2023, extensions and discoveries of 258 million BOE in the United States were primarily due to planned development of new locations in shale and tight assets in the Midland and Delaware basins of 173 million BOE and the DJ basin of 49 million BOE, and deepwater assets in the Gulf of Mexico of 36 million BOE.

In Other Americas, 57 million BOE of extensions and discoveries were mainly from shale and tight assets in Argentina.

In 2023, purchases of 301 million BOE in the United States are primarily from the acquisition of PDC.

The difference in 2023 extensions and discoveries of 127 million BOE, between the net quantities of proved reserves of 441 million BOE as reflected on pages 110 to 112 and net quantities of proved undeveloped reserves of 314 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 2023.

Purchases of 61 million BOE in 2022 are primarily from the acquisition of various properties in the Midland and Delaware basins in the United States.

Transfers to proved developed reserves in 2022 include 309 million BOE in the United States, primarily from the Midland, Delaware and DJ basin developments, 207 million BOE in Australia, and 141 million BOE in Kazakhstan, Angola, Canada, Argentina and other international locations.

Transfers to proved developed reserves in 2023 include 395 million BOE in the United States, primarily from 268 million BOE in the Midland and Delaware basins, 83 million BOE in the DJ basin, and 44 million BOE in the Gulf of Mexico.

Other significant transfers to proved developed are 114 million BOE in Israel and a combined 87 million BOE in Bangladesh, Argentina, Canada, Kazakhstan, and other international locations.

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

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In Africa, about $0.7 billion was expended on various offshore development and natural gas projects in Nigeria, Angola and Republic of Congo.

Development activities in Canada and other international locations were primarily responsible for about $0.5 billion of expenditures.

Development activities in other international locations were primarily responsible for about $0.6 billion of expenditures.

Reserves that remain proved undeveloped for five or more years are a result of several factors that affect optimal project development and execution.

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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 2022, improvements in commodity prices positively impacted the economic limits of oil and gas properties, resulting in proved reserve increases, and negatively impacted proved reserves due to entitlement effects.

In 2023, lower commodity prices negatively impacted the economic limits of oil and gas properties, resulting in a proved reserve decrease of approximately 135 million BOE, and positively impacted proved reserves due to entitlement effects, resulting in a proved reserves increase of approximately 89 million BOE.

The year-end reserves quantities have been updated for these circumstances and significant changes have been discussed in the appropriate reserves sections.

Over the past three years, the ratio of proved undeveloped reserves to total proved reserves has ranged between 31 percent and 35 percent.

Proved Reserve Quantities For the three years ending December 31, 2022, the pattern of net reserve changes shown in the following tables are not necessarily indicative of future trends.

Apart from acquisitions, the company’s ability to add proved reserves can be affected by events and circumstances that are outside the company’s control, such as delays in government permitting, partner approvals of development plans, changes in oil and gas prices, OPEC constraints, geopolitical uncertainties, and civil unrest.

Proved Reserve Quantities For the three years ended December 31, 2023, the pattern of net reserve changes shown in the following tables is not necessarily indicative of future trends.

Apart from acquisitions, the company’s ability to add proved reserves can be affected by events and circumstances that are outside the company’s control, such as delays in government

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

permitting, partner approvals of development plans, changes in oil and gas prices, OPEC constraints, geopolitical uncertainties, civil unrest, events of war or military conflicts.

At December 31, 2023, proved reserves for the company were 11 billion BOE.

The company’s estimated net proved reserves of liquids, including crude oil, condensate and synthetic oil for the years 2021, 2022 and 2023, are shown in the table on page 110.

The company’s estimated net proved reserves of natural gas liquids are shown on page 108, and the company’s estimated net proved reserves of natural gas are shown on page 109.

The company’s estimated net proved reserves of natural gas liquids (NGLs) are shown on page 111, and the company’s estimated net proved reserves of natural gas are shown on page 112.

Noteworthy changes in crude oil, condensate and synthetic oil proved reserves for 2021 through 2023 are discussed below and shown in the table on the following page:

Revisions In 2020, capital reductions and commodity price effects in the Midland and Delaware basins and Anchor in the Gulf of Mexico were primarily responsible for the 279 million barrels decrease in the United States.

Reserves in Venezuela affiliates decreased by 149 million barrels, primarily due to impairments and accounting methodology change.

Entitlement effects and performance revisions in TCO were primarily responsible for the 180 million barrels increase.

Entitlement effects primarily contributed to an increase of 77 million barrels of synthetic oil at the Athabasca Oil Sands in Canada and 74 million barrels at multiple locations in Asia.

In 2021, the 206 million barrels increase in United States was primarily in the Gulf of Mexico and the Midland and Delaware basins.

Revisions In 2021, the 206 million barrels increase in United States was primarily in the Gulf of Mexico and the Midland and Delaware basins.

The higher commodity price environment led to the increase of 126 million barrels in the Gulf of Mexico primarily from Anchor and a 68 million barrels increase in the Midland and Delaware basins due to higher planned development activity.

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In TCO, entitlement effects and changes in operating assumptions were primarily responsible for the 35 million barrels decrease in Kazakhstan.

Extensions and Discoveries In 2020, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 105 million barrels increase in the United States.

In 2021, extensions and discoveries in the Midland and Delaware basins, and at the Whale Project in the Gulf of Mexico, were primarily responsible for the 349 million barrels increase in the United States.

In 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.

A reduction in planned development activities led to a decrease of 58 million barrels in California.

In Other Americas, entitlement effects primarily contributed to an increase of 42 million barrels of synthetic oil at the Athabasca Oil Sands project in Canada.

In Asia, reservoir performance, mainly in the Partitioned Zone of Saudi Arabia/Kuwait, was responsible for the 48 million barrels increase.

Reservoir performance in Nigeria was mainly responsible for the 37 million barrels increase in Africa.

Extensions and Discoveries In 2021, extensions and discoveries in the Midland and Delaware basins, and at the Whale Project in the Gulf of Mexico, were primarily responsible for the 349 million barrels increase in the United States.

In 2022, extensions and discoveries in the Midland, Delaware and DJ basins, and approval of the Ballymore Project in the Gulf of Mexico, were primarily responsible for the 264 million barrels increase in the United States.

In Other Americas, the 32 million barrels of extensions and discoveries were from Argentina and Canada.

Purchases In 2020, the acquisition of Noble assets contributed 227 million barrels in the DJ basin, Midland and Delaware basins in the United States.

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.

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.

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.

Sales In 2020, sales of 99 million barrels in Asia were in Azerbaijan.

In 2021, sales of 32 million barrels in the United States were in the Midland and Delaware basins.

In 2023, the acquisition of PDC in the DJ and Delaware basins was primarily responsible for the 207 million barrels increase in the United States.

Sales In 2021, sales of 32 million barrels in the United States were in the Midland and Delaware basins.

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

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5 Reserve quantities include synthetic oil projected to be consumed in operations of 27, 28 and 17 millions of barrels as of December 31, 2023, 2022 and 2021, respectively.

Noteworthy changes in natural gas liquids proved reserves for 2020 through 2022 are discussed below and shown in the table on the following page:

Revisions In 2020, capital reductions and commodity price effects in various fields in Midland and Delaware basins were primarily responsible for the 71 million barrels decrease in the United States.

In 2021, higher commodity prices resulting in the increase of planned development activity in the Midland and Delaware basins were primarily responsible for the 107 million barrels increase in the United States.

Extensions and Discoveries In 2020, extensions and discoveries in various fields in Midland and Delaware basins were primarily responsible for the 60 million barrels increase in the United States.

Noteworthy changes in NGLs proved reserves for 2021 through 2023 are discussed below and shown in the table on the following page:

Revisions In 2021, higher commodity prices resulting in the increase of planned development activity in the Midland and Delaware basins were primarily responsible for the 107 million barrels increase in the United States.

In 2023, the 110 million barrels decrease in the United States was primarily in the Midland and Delaware basins with a decrease of 49 million barrels due to portfolio optimization and a decrease of 29 million barrels due to reservoir performance.

Extensions and Discoveries In 2021, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 190 million barrels increase in the United States.

In 2022, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 163 million barrels increase in the United States.

In 2023, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 92 million barrels increase in the United States.

Purchases In 2020, the acquisition of Noble assets contributed 198 million barrels primarily in the DJ basin, Midland and Delaware basins and Eagle Ford shale in the United States.

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.

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Noteworthy changes in natural gas proved reserves for 2021 through 2023 are discussed below and shown in the table on the following page:

Revisions In 2020, the demotion of Jansz Io compression project reserves and lower field performance, partially offset by positive revisions at Gorgon, were mainly responsible for the net 2.5 TCF decrease in Australia.

Capital reductions and commodity price effects in various fields of the Midland and Delaware basins were mainly responsible for the 509 BCF decrease in the United States.

In Africa, a 229 BCF decrease was primarily due to reduced demand and development plan changes at Meren in Nigeria.

In 2021, the approval of the Jansz Io Compression project was mainly responsible for the 1.2 TCF increase in Australia.

Higher commodity prices, resulting in the increase of planned development activity in the Midland and Delaware basins, were mainly responsible for the 829 BCF increase in the United States.

Revisions In 2021, the approval of the Jansz Io Compression project was mainly responsible for the 1.2 trillion cubic feet (TCF) increase in Australia.

Higher commodity prices, resulting in the increase of planned development activity in the Midland and Delaware basins, were mainly responsible for the 829 billion cubic feet (BCF) increase in the United States.

In TCO, entitlement effects and technical changes in field operating assumptions, reservoir model, and project schedule were primarily responsible for the 179 BCF decrease.

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

Extensions and Discoveries In 2020, extensions and discoveries of 385 BCF in the United States were primarily in the Midland and Delaware basins.

In 2021, extensions and discoveries of 1.4 TCF in the United States were primarily in the Midland and Delaware basins.

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.

Extensions and Discoveries In 2021, extensions and discoveries of 1.4 TCF in the United States were primarily in the Midland and Delaware basins.

In 2022, extensions and discoveries of 1.6 TCF in the United States were primarily in the Midland and Delaware basins.

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

Purchases In 2020, the acquisition of Noble assets contributed 5.4 TCF in Israel in Asia, 1.5 TCF in the DJ basin, Midland and Delaware basins and Eagle Ford Shale in the United States and 441 BCF in Equatorial Guinea in Africa.

Sales In 2020, sales of 1.3 TCF were primarily in the Appalachian basin in the United States and 264 BCF primarily in Azerbaijan in Asia.

In 2022, sales of 243 BCF in the United States were primarily in the Eagle Ford shale and Midland and Delaware basins.

In 2023, extensions and discoveries of 660 BCF in the United States were primarily in the Midland and Delaware basins.

Purchases In 2023, the acquisition of PDC in the DJ basin was primarily responsible for the 2.2 TCF in the United States.

Sales In 2022, sales of 243 BCF in the United States were primarily in the Eagle Ford shale and Midland and Delaware basins.

Net Proved Reserves of Natural Gas

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Additions to deferred income tax expense 2,348 3,533 3,691

3,533 3,691 2,892

Reduction of deferred income tax expense ( 1,464 ) ( 1,652 ) ( 3,802 )

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* See also Note 17 Taxes .

2 Includes $ 974 of additions associated with the purchase of Noble in 2020.

Form 10-K Summary

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EXHIBIT INDEX

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.

3.2 By-Laws of Chevron Corporation, as amended and restated December 7 , 202 2 , filed as Exhibit 3.

2 to Chevron Corporation’s Current Report on Form 8-K filed December 8, 2022 , and incorporated herein by reference.

3.2 By-Laws of Chevron Corporation, as amended and restated December 7, 2022, filed as Exhibit 3.2 to Chevron Corporation’s Current Report on Form 8-K filed December 8, 2022, and incorporated herein by reference.

4.1 Indenture, dated as of June 15, 1995, filed as Exhibit 4.1 to Chevron Corporation’s Amendment Number 1 to Registration Statement on Form S-3 filed June 14, 1995, and incorporated herein by reference.

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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.

10.5+ Chevron Incentive Plan, amended and restated effective January 1, 2021, filed as Exhibit 10.5 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2020, and incorporated herein by reference.

10.6+* Summary of Chevron Incentive Plan Award Criteria .

10.7+ Long-Term Incentive Plan of Chevron Corporation, filed as Appendix B to Chevron Corporation’s Notice of the 2013 Annual Meeting and 2013 Proxy Statement filed April 11, 2013, and incorporated herein by reference.

10.5+ Chevron Incentive Plan, amended and restated effective October 2, 2023 , filed as Exhibit 10.

3 to Chevron Corporation’s Quarterly Report on Form 10- Q for the quarter ended September 30 , 202 3 , and incorporated herein by reference.

10.6+ Summary of Chevron Incentive Plan Award Criteria, filed as Exhibit 10.6 to Chevron Corporation's Annual Report on Form 10-K for the year ended December 31, 2022, and incorporated herein by reference.

10.7+ Long-Term Incentive Plan of Chevron Corporation, amended and restated effective Octo ber 2 , 2023, filed as Exhibit 10.5 to Chevron Corporation ’ s Quarterly Report on Form 10-Q for the quarter ended September 3 0, 2023, and incorporated herein by reference.

10.8+ Form of Performance Share Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed February 1, 2021, and incorporated herein by reference.

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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.

10.15+ Chevron Corporation Deferred Compensation Plan for Management Employees II, filed as Exhibit 10.5 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.

10.16+ Chevron Corporation Retirement Restoration Plan, filed as Exhibit 10.6 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.

10.17+ Amendment Number One to the Chevron Corporation Retirement Restoration Plan, filed as Exhibit 10.23 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2017, and incorporated herein by reference.

10.15+ Chevron Corporation Deferred Compensation Plan for Management Employees II, amended and restated effective October 2, 2023, filed as Exhibit 10.

1 to Chevron Corporation’s Quarterly Report on Form 10- Q for the quarter ended September 30, 2023 , and incorporated herein by reference.

10.16+ Chevron Corporation Retirement Restoration Plan, amended and restated effective October 2, 2023, filed as Exhibit 10.

2 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 ESIP Restoration Plan, Amended and Restated as of January 1, 2018, filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017, and incorporated herein by reference.

10.18+ Agreement between Chevron Corporation and R.

Hewitt Pate, filed as Exhibit 10.16 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2011, and incorporated herein by reference.

Hewitt Pate, dated February 21, 2012, filed as Exhibit 10.16 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2011, and incorporated herein by reference.

10.19+* Agreement between Chevron Corporation and R.

Hewitt Pate, dated De cember 13, 2018 .

10.20+ Amended and Restated Aircraft Time-Sharing Agreement, dated as of April 1, 2020, between Chevron U.S.A.

1 unchanged sentence

Wirth, filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, and incorporated herein by reference.

10.21+ 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed May 27, 2022, and incorporated herein by reference.

10.21+ 2022 Long-Term Incentive Plan of Chevron Corporation, amended and restated effective October 2, 2023, filed as Exhibit 10.

4 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2023, and incorporated herein by reference.

10.22+ Form of Performance Share Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.

10.23+ Form of Standard Restricted Stock Unit Award Agreement (stock settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.2 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.

10.23+ Form of Standard Restricted Stock Unit Award Agreement (s hare settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.2 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.

10.24+ Form of Standard Restricted Stock Unit Award Agreement (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.

3 unchanged sentences

10.28+ Form of Stock Appreciation Right Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.7 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.

10.29+ Letter Agreement, dated May 25, 2022, by and between Chevron Corporation and Joseph C.

Geagea, filed as Exhibit 10.1 to Chevron Corporation's Current Report on Form 8-K filed May 27, 2022, and incorporated herein by reference.

10.29+ 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.

10.30+ 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.

10.31+ 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 .

10.32+ 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.

10.33+ 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.

10.34+ 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.

10.36+ Form of Non-Qualified Stock Options Award Agreement (cashless) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.8 to Chevron Corporation’s Current Report on Form 8-K filed February 2, 2024, and incorporated herein by reference.

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+ General Release and Separation Agreement, dated February 15, 2023, by and between Chevron Corporation and James W.

Johnson , filed as Exhibit 10.30 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2022 and incorporated herein by reference.

19* Insider Trading Policies and Procedures.

Subsidiaries of Chevron Corporation (page E-1).

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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.

99.1* Definitions of Selected Energy and Financial Terms (pages E-7 through E-10).

99.2 Report of Netherland, Sewell & Associates, Inc., filed as Exhibit 99.3 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2020, and incorporated herein by reference.

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 23rd day of February, 2023.

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 23rd day of February, 2023.

Principal Executive Officer

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Principal Accounting Officer

Inchausti, Vice President

Knowles, Vice President

and Controller

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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