CHEVRON CORP 10-K

Item 9A. Controls and Procedures (a) Evaluation of Disclosure Controls and Procedures The company’s management has evaluated, with the participation of the Chief Executive Officer and the Chief Financial Officer, the effectiveness of the company’s disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (Exchange Act)) as of the end of the period covered by this report. Based on this evaluation, management concluded that the company’s disclosure controls and procedures were effective as of December 31, 2023. (b) Management’s Report on Internal Control Over Financial Reporting The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in the Exchange Act Rules 13a-15(f) and 15d-15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s internal control over financial reporting based on the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 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 29 Table of Contents 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. (c) Changes in Internal Control Over Financial Reporting During the quarter ended December 31, 2023, there were no changes in the company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the company’s internal control over financial reporting. Item 9B. Other Information Rule 10b5-1 Plan Elections Michael K. Wirth , Chairman of the Board and Chief Executive Officer , entered into a pre-arranged stock trading plan on November 22, 2023 . Mr. 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. R. Hewitt Pate , Vice President and General Counsel , entered into a pre-arranged stock trading plan on November 27, 2023 . Mr. 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. Alana K. Knowles , Vice President and Controller , entered into a pre-arranged stock trading plan on November 27, 2023 . Ms. 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. Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections Not applicable. 30 Table of Contents PART III Item 10. Directors, Executive Officers and Corporate Governance Information about our Executive Officers at February 26, 2024 Members of the Corporation’s Executive Committee are the Executive Officers of the Corporation: Name Age Current and Prior Positions (up to five years) Primary Areas of Responsibility Michael K. Wirth 63 Chairman of the Board and Chief Executive Officer (since Feb 2018) Chairman of the Board and Chief Executive Officer Pierre R. Breber * 59 Vice President and Chief Financial Officer (since Apr 2019) Executive Vice President, Downstream (Jan 2016 - Mar 2019) Finance; Investor Relations Mark A. Nelson 60 Vice Chairman (since Feb 2023) Executive Vice President, Strategy, Policy & Development (Oct 2022 - Sept 2023) Executive Vice President, Downstream (Mar 2019 - Sep 2022) Vice President, Midstream, Strategy and Policy (Feb 2018 - Feb 2019) Strategy & Sustainability; Corporate Affairs; Corporate Business Development; Procurement/Supply Chain Management; Information Technology A. 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 Eimear P. Bonner * 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) Finance; Investor Relations Jeff B. 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) Subsurface; Global Reserves; Wells; Facilities Designs and Solutions; Capital Projects; Downstream Technology Rhonda J. Morris 58 Vice President and Chief Human Resources Officer (since Feb 2019) Human Resources; Diversity and Inclusion R. 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 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. 31 Table of Contents 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. Item 11. Executive Compensation The information required by Item 402 of Regulation S-K and contained under the headings “Executive Compensation,” “Director Compensation” and “CEO Pay Ratio” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K. The information required by Item 407(e)(5) of Regulation S-K and contained under the heading “Corporate Governance — Management Compensation Committee Report” in the 2024 Proxy Statement is incorporated herein by reference into this Annual Report on Form 10-K. Pursuant to the rules and regulations of the SEC under the Exchange Act, the information under such caption incorporated by reference from the 2024 Proxy Statement shall not be deemed to be “soliciting material,” or to be “filed” with the Commission, or subject to Regulation 14A or 14C or the liabilities of Section 18 of the Exchange Act, nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters The information required by Item 403 of Regulation S-K and contained under the heading “Stock Ownership Information — Security Ownership of Certain Beneficial Owners and Management” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K. The information required by Item 201(d) of Regulation S-K and contained under the heading “Equity Compensation Plan Information” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K. Item 13. Certain Relationships and Related Transactions, and Director Independence 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. Item 14. Principal Accountant Fees and Services The information required by Item 9(e) of Schedule 14A and contained under the heading “Board Proposal to Ratify PricewaterhouseCoopers LLP as the Independent Registered Public Accounting Firm for 2024” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K. 32 Financial Table of Contents Table of Contents Management’s Discussion and Analysis of Financial Condition and Results of Operations Key Financial Results 34 Earnings by Major Operating Area 34 Business Environment and Outlook 34 Noteworthy Developments 40 Results of Operations 41 Consolidated Statement of Income 43 Selected Operating Data 45 Liquidity and Capital Resources 46 Financial Ratios and Metrics 50 Financial and Derivative Instrument Market Risk 51 Transactions With Related Parties 52 Litigation and Other Contingencies 52 Environmental Matters 53 Critical Accounting Estimates and Assumptions 54 New Accounting Standards 57 Quarterly Results 58 Consolidated Financial Statements Reports of Management 59 Report of Independent Registered Public Accounting Firm (PCAOB ID: 238 ) 60 Consolidated Statement of Income 62 Consolidated Statement of Comprehensive Income 63 Consolidated Balance Sheet 64 Consolidated Statement of Cash Flows 65 Consolidated Statement of Equity 66 Notes to the Consolidated Financial Statements Note 1 Summary of Significant Accounting Policies 67 Note 2 Changes in Accumulated Other Comprehensive Losses 70 Note 3 Information Relating to the Consolidated Statement of Cash Flows 71 Note 4 New Accounting Standards 72 Note 5 Lease Commitments 72 Note 6 Summarized Financial Data - Chevron U.S.A. Inc. 74 Note 7 Summarized Financial Data - Tengizchevroil LLP 74 Note 8 Summarized Financial Data - Chevron Phillips Chemical Company LLC 74 Note 9 Fair Value Measurements 75 Note 10 Financial and Derivative Instruments 76 Note 11 Assets Held for Sale 77 Note 12 Equity 77 Note 13 Earnings Per Sha re 77 Note 14 Operating Segments and Geographic Data 78 Note 15 Investments and Advances 81 Note 16 Litigation 82 Note 17 Taxes 85 Note 18 Properties, Plant and Equipment 88 Note 19 Short-Term Debt 88 Note 20 Long-Term Debt 89 Note 21 Accounting for Suspended Exploratory Wells 89 Note 22 Stock Options and Other Share-Based Compensation 90 Note 23 Employee Benefit Plans 92 Note 24 Other Contingencies and Commitments 97 Note 25 Asset Retirement Obligations 98 Note 26 Revenue 99 Note 27 Other Financial Information 99 Note 28 Financial Instruments - Credit Losses 100 Note 29 Acquisition of PDC Energy , Inc. 101 Note 30 Agreement to Acquire Hess Corporation 101 Supplemental Information on Oil and Gas Producing Activities 102 33 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents Key Financial Results Millions of dollars, except per-share amounts 2023 2022 2021 Net Income (Loss) Attributable to Chevron Corporation $ 21,369 $ 35,465 $ 15,625 Per Share Amounts: Net Income (Loss) Attributable to Chevron Corporation – Basic $ 11.41 $ 18.36 $ 8.15 – Diluted $ 11.36 $ 18.28 $ 8.14 Dividends $ 6.04 $ 5.68 $ 5.31 Sales and Other Operating Revenues $ 196,913 $ 235,717 $ 155,606 Return on: Capital Employed 11.9 % 20.3 % 9.4 % Stockholders’ Equity 13.3 % 23.8 % 11.5 % Earnings by Major Operating Area Millions of dollars 2023 2022 2021 Upstream United States $ 4,148 $ 12,621 $ 7,319 International 13,290 17,663 8,499 Total Upstream 17,438 30,284 15,818 Downstream United States 3,904 5,394 2,389 International 2,233 2,761 525 Total Downstream 6,137 8,155 2,914 All Other (2,206) (2,974) (3,107) Net Income (Loss) Attributable to Chevron Corporation 1,2 $ 21,369 $ 35,465 $ 15,625 1 Includes foreign currency effects: $ (224) $ 669 $ 306 2 Income net of tax, also referred to as “earnings” in the discussions that follow. Refer to the Results of Operations section for a discussion of financial results by major operating area for the three years ended December 31, 2023. Throughout the document, certain totals and percentages may not sum to their component parts due to rounding. Business Environment and Outlook Chevron Corporation is a global energy company with 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. The company’s objective is to safely deliver higher returns, lower carbon and superior shareholder value in any business environment. Earnings of the company depend mostly on the profitability of its upstream business segment. The most significant factor affecting the results of operations for the upstream segment is the price of crude oil, which is determined in global markets outside of the company’s control. In the company’s downstream business, crude oil is the largest cost component of refined products. Periods of sustained lower commodity prices could result in the impairment or write-off of specific assets in future periods and cause the company to adjust operating expenses, including employee reductions, and capital expenditures, along with other measures intended to improve financial performance. Governments, companies, communities and other stakeholders are increasingly supporting efforts to address climate change. International initiatives and national, regional and state legislation and regulations that aim to directly or indirectly reduce GHG emissions are in various stages of design, adoption and implementation. These policies and programs, some of which support the global net zero emissions ambitions of the Paris Agreement, can change the amount of energy consumed, the rate of energy-demand growth, the energy mix and the relative economics of one fuel versus another. Implementation of jurisdiction-specific policies and programs can be dependent on, and can affect the pace of, technological advancements, the granting of necessary permits by governing authorities, the availability of cost-effective, verifiable carbon credits, the availability of suppliers that can meet sustainability and other standards, evolving regulatory or other requirements affecting ESG standards or other disclosures and evolving standards for tracking, reporting, marketing and advertising relating to emissions and emission reductions and removals. Some of these policies and programs include renewable and low carbon fuel standards, such as the Renewable Fuel Standard program in the U.S. and California’s Low Carbon Fuel Standard; programs that price GHG emissions, including 34 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents California’s Cap-and-Trade Program; performance standards, including methane-specific regulations such as the 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. Inflation Reduction Act. Requirements for these and other similar policies and programs are complex, ever changing, program specific and encompass: (1) the blending of renewable fuels into transportation fuels; (2) the purchasing, selling, utilizing and retiring of allowances and carbon credits; and (3) other emissions reduction measures including efficiency improvements and capturing GHG emissions. These compliance policies and programs have had and may continue to have negative impacts on the company now and in the future including, but not limited to, the displacement of hydrocarbon and other products and/or the impairment of assets. These policies have also enabled opportunities for Chevron in its lower carbon businesses. For example, the acquisition of Renewable Energy Group, Inc. (REG) in 2022 grew the company’s renewable fuels production capacity and increased the company’s carbon credit generation activities. Although we expect the company’s costs to comply with these policies and programs to continue to increase, these costs currently do not have a material impact on the company’s financial condition or results of operations. Significant uncertainty remains as to the pace and extent to which the transition to a lower carbon future will progress, which is dependent, in part, on further advancements and changes in policy, technology, and customer and consumer preferences. The level of expenditure required to comply with new or potential climate change-related laws and regulations and the amount of additional investments needed in new or existing technology or facilities, such as carbon capture and storage, is difficult to predict with certainty and is expected to vary depending on the actual laws and regulations enacted, available technology options, customer and consumer preferences, the company’s activities and market conditions. As discussed below, in 2021, the company announced planned capital spend of approximately $10 billion through 2028 in lower carbon investments. Although the future is uncertain, many published outlooks conclude that fossil fuels will remain a significant part of an energy system that increasingly incorporates lower carbon sources of supply for many years to come. Chevron supports the Paris Agreement’s global approach to governments addressing climate change and continues to take actions to help lower the carbon intensity of its operations while continuing to meet the demand for energy. Chevron believes that broad, market-based mechanisms are the most efficient approach to addressing GHG emission reductions. Chevron integrates climate change-related issues and the regulatory and other responses to these issues into its strategy and planning, capital investment reviews and risk management tools and processes, where it believes they are applicable. They are also factored into the company’s long-range supply, demand and energy price forecasts. These forecasts reflect estimates of long-range effects from climate change-related policy actions, such as electric vehicle and renewable fuel penetration, energy efficiency standards and demand response to oil and natural gas prices. The company will continue to develop oil and gas resources to meet customers’ and consumers’ demand for energy. At the same time, Chevron believes that the future of energy is lower carbon. The company will continue to maintain flexibility in its portfolio to be responsive to changes in policy, technology and customer and consumer preferences. Chevron aims to grow its oil and gas business, lower the carbon intensity of its operations and grow lower carbon businesses in renewable fuels, carbon capture and offsets, hydrogen and other emerging technologies. To grow its lower carbon businesses, Chevron plans to target sectors of the economy where emissions are harder to abate or that cannot be easily electrified, while leveraging the company’s capabilities, assets, partnerships and customer relationships. The company’s oil and gas business may increase or decrease depending upon regulatory or market forces, among other factors. In 2021, Chevron announced the following aspirations and targets that are aligned with its lower carbon strategy: 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 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: 35 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents • Oil production GHG intensity of 24 kilograms (kg) carbon dioxide equivalent per barrel of oil-equivalent (CO 2 e/boe), • 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. 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. 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. Income Taxes The effective tax rate for the company can change substantially during periods of significant earnings volatility. This is due to the mix effects that are impacted by both the absolute level of earnings or losses and whether they arise in higher or lower tax rate jurisdictions. As a result, a decline or increase in the effective income tax rate in one period may not be indicative of expected results in future periods. Additional information related to the company’s effective income tax rate is included in Note 17 Taxes to the Consolidated Financial Statements. The Inflation Reduction Act (IRA), enacted in the United States on August 16, 2022, imposes several new taxes that were effective in 2023, including a 15 percent minimum tax on book income and a one percent excise tax on stock repurchases. The IRA also implements various incentives for lower carbon activities, including carbon capture and storage and the production of hydrogen and sustainable aviation fuel, and extends the federal biodiesel mixture excise tax credit through December 31, 2024. The IRA has not had a material impact on our results of operations. 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 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. 36 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents While macroeconomic inflation is easing, trends in the costs of goods and services vary by spend category. 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. 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. Earnings trends for the company’s major business areas are described as follows: Upstream Earnings for the upstream segment are closely aligned with industry prices for crude oil and natural gas. Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry production and inventory levels, technology advancements, production quotas or other actions imposed by OPEC+ countries, actions of regulators, weather-related damage and disruptions, competing fuel prices, natural and human causes beyond the company’s control, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. Any of these factors could also inhibit the company’s production capacity in an affected region. The company closely monitors developments in the countries in which it operates and holds investments and seeks to manage risks in operating its facilities and businesses. The longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to efficiently find, acquire and produce crude oil and natural gas, changes in fiscal terms of contracts, the pace of energy transition, and changes in tax, environmental and other applicable laws and regulations. The company has begun to experience regulatory challenges and delays in obtaining permits to conduct operations in certain jurisdictions. These challenges have, and may continue to, impact the company’s plans for future investments. For example, during fourth quarter 2023, the company impaired a portion of its U.S. upstream assets, primarily in California, due to continuing regulatory challenges in the state that have resulted in lower anticipated future investment levels in its business plans. The company expects to continue operating the impacted assets for many years to come. 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 General License 41 from the United States government, enabling the company to resume activity in Venezuela subject to certain limitations, and the company continues such activities under this General License. The financial results for Chevron’s business in Venezuela are being recorded as non-equity investments since 2020, where income is only recognized when cash is received and production and reserves are not included in the company's results. Crude oil liftings in Venezuela started in first quarter 2023, which have positively impacted the company’s 2023 results, but future results remain uncertain. 37 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents Governments (including Russia) have imposed and may impose additional sanctions and other trade laws, restrictions and regulations that could lead to disruption in our ability to produce, transport and/or export crude in the region around Russia. An adverse effect on the Caspian Pipeline Consortium (CPC) operations could have a negative impact on the Tengiz field in Kazakhstan and the company’s results of operations and financial position. The financial impacts of such risks, including presently imposed sanctions, are not currently material for the company; however, it remains uncertain how long these conditions may last or how severe they may become. Chevron holds a 39.7 percent interest in the Leviathan field and a 25 percent interest in the Tamar gas field in Israel. In early October 2023, due to a war between Israel and Hamas, the Government of Israel directed the company to shut down production at the Tamar gas field. Approximately one month later, the company resumed production, and the Tamar gas field is currently operational. The Leviathan gas field was not impacted by the war and is currently operational. The financial impacts of the Tamar shutdown and other operational impacts were not material for the company. However, given the ongoing conflict, the future impacts on the company’s results of operations and financial condition remain uncertain. Commodity Prices The following chart shows the trend in benchmark prices for Brent crude oil, West Texas Intermediate (WTI) crude oil and U.S. Henry Hub natural gas. The Brent price averaged $83 per barrel for the full-year 2023, compared to $101 in 2022. As of mid-February 2024, the Brent price was $85 per barrel. The WTI price averaged $78 per barrel for the full-year 2023, compared to $95 in 2022. As of mid-February 2024, the WTI price was $77 per barrel. The majority of the company’s equity crude production is priced based on the Brent benchmark. Crude prices were volatile in 2023 due to tapering of post-pandemic demand resurgence, OPEC+ supply cuts, Federal Reserve interest rate action, and the proliferation of geopolitical conflict. The company’s average realization for U.S. crude oil and NGLs in 2023 was $59 per barrel, down 23 percent from 2022. The company’s average realization for international crude oil and NGLs in 2023 was $72 per barrel, down 21 percent from 2022. In contrast to price movements in the global market for crude oil, prices for natural gas are also impacted by regional supply and demand and infrastructure conditions in local markets. In the United States, prices at Henry Hub averaged $2.56 per thousand cubic feet (MCF) during 2023, compared with $6.36 per MCF during 2022. High storage levels and strong production resulted in these lower prices. As of mid-February 2024, the Henry Hub spot price was $1.73 per MCF. (See page 45 for the company’s average natural gas realizations for the U.S.) Outside the United States, prices for natural gas also depend on a wide range of supply, demand and regulatory circumstances. The company’s long-term contract prices for liquefied natural gas (LNG) are typically linked to crude oil prices. Most of the equity LNG offtake from the operated Australian LNG projects is committed under binding long-term contracts, with some sold in the Asian spot LNG market. International natural gas realizations averaged $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. 38 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+; price effects on entitlement volumes; changes in fiscal terms or restrictions on the scope of company operations; delays in construction; reservoir performance; greater-than-expected declines in production from mature fields; start-up or ramp-up of projects; acquisition and divestment of assets; fluctuations in demand for crude oil and natural gas in various markets; weather conditions that may shut in production; civil unrest; changing geopolitics; delays in completion of maintenance turnarounds; storage constraints or economic conditions that could lead to shut-in production; or other disruptions to operations. The outlook for future production levels is also affected by the size and number of economic investment opportunities and the time lag between initial exploration and the beginning of production. The company has increased its investment emphasis on short-cycle projects. Proved Reserves Net proved reserves for consolidated companies and affiliated companies totaled 11.1 billion barrels of oil-equivalent at year-end 2023, a slight decrease from year-end 2022. The reserve replacement ratio in 2023 was 86 percent. The 5 and 10 year reserve replacement ratios were 82 percent and 99 percent, respectively. Refer to Table V for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2021 and each year-end from 2021 through 2023, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2023. Refer to the “Results of Operations” section on pages 41 and 42 for additional discussion of the company’s upstream business. Downstream Earnings for the downstream segment are closely tied to margins on the refining, manufacturing and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil, fuel and lubricant additives, petrochemicals and renewable fuels. Industry margins are sometimes volatile and can be affected by the global and regional supply-and-demand balance for refined products and petrochemicals, and by changes in the price of crude oil, other refinery and petrochemical feedstocks, and natural gas. Industry margins can also be influenced by inventory levels, geopolitical events, costs of materials and services, refinery or chemical plant capacity utilization, maintenance programs, and disruptions at refineries or chemical plants resulting from unplanned outages due to severe weather, fires or other operational events. 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 39 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 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. Noteworthy Developments Key noteworthy developments and other events during 2023 and early 2024 included the following: Angola Received approvals to extend Block 0 concession through 2050. Australia Achieved first natural gas production from the Gorgon Stage 2 development, supporting long-term energy supply in the Asia-Pacific region. Israel Reached final investment decision to construct a third gathering pipeline that is expected to increase natural gas production capacity from approximately 1.2 to nearly 1.4 billion cubic feet per day from the Leviathan reservoir. Japan Announced agreements to conduct pilot tests on advanced closed loop geothermal technology. Kazakhstan Achieved mechanical completion on the Future Growth Project at the company’s 50 percent-owned affiliate, Tengizchevroil. United States Announced an agreement to install new technologies on the company’s LNG vessels that are intended to reduce the carbon intensity of its LNG fleet operations. United States Expanded the Bayou Bend carbon capture and sequestration hub on the U.S. Gulf Coast through an acquisition of nearly 100,000 acres, and became the operator of the hub. United States Announced commercial collaboration to purchase next generation renewable feedstocks that are intended to benefit farmers and increase supplies to meet a growing demand for lower carbon renewable fuels. United States Acquired 73 exploration blocks in Gulf of Mexico lease sale 259 and submitted winning bids on an additional 28 exploration blocks in Gulf of Mexico lease sale 261, subject to final government approval. United States Achieved first oil at the Mad Dog 2 project in the Gulf of Mexico. United States Started operations of a solar power project with a joint venture partner in New Mexico to provide lower carbon energy for the Permian Basin. United States Converted the diesel hydrotreater at the El Segundo, California refinery to process either 100 percent renewable or traditional feedstocks. United States Completed the acquisition of PDC, adding 275,000 net acres in the Denver-Julesburg (DJ) Basin and 25,000 net acres in the Permian Basin. United States Completed the acquisition of a majority stake in ACES Delta, LLC, which is developing a green hydrogen production and storage hub in Utah. United States Announced a definitive agreement to acquire Hess Corporation (Hess), which is expected to strengthen Chevron’s long-term performance by adding world-class assets and people. Venezuela Received approval to extend licenses with PetroBoscan, S.A. and PetroIndependiente, S.A. through 2041. 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 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 . 40 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents Results of Operations The following section presents the results of operations and variances on an after-tax basis for the company’s business segments – Upstream and Downstream – as well as for “All Other.” Earnings are also presented for the U.S. and international geographic areas of the Upstream and Downstream business segments. Refer to Note 14 Operating Segments and Geographic Data for a discussion of the company’s “reportable segments.” This section should also be read in conjunction with the discussion in Business Environment and Outlook . Refer to the Selected Operating Data for a three-year comparison of production volumes, refined product sales volumes and refinery inputs. A discussion of variances between 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. U.S. Upstream Unit * 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. U.S. 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. 41 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents International Upstream Unit (2) 2023 2022 2021 Earnings (1) $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 (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. U.S. Downstream Unit * 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. U.S. 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 Unit (2) 2023 2022 2021 Earnings (1) $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 (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. 42 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents All Other Unit 2023 2022 2021 Net charges * $MM $ (2,206) $ (2,974) $ (3,107) * Includes foreign currency effects: $ (588) $ (382) $ (181) All Other consists of worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology companies. Net charges decreased by $768 million primarily due to lower employee benefit costs and higher interest income, partially offset by an unfavorable swing of $206 million in foreign currency effects. Consolidated Statement of Income Comparative amounts for certain income statement categories are shown below. A discussion of variances between 2022 and 2021 can be found in the “Consolidated Statement of Income” section on pages 41 and 42 of the company’s 2022 Annual Report on Form 10-K. Millions of dollars 2023 2022 2021 Sales and other operating revenues $ 196,913 $ 235,717 $ 155,606 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 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 (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 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 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 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 increased in 2023 primarily due to higher impairment charges and higher production, partially offset by lower rates. 43 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 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 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 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 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. U.S. 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 . 44 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents Selected Operating Data 1,2 Unit 2023 2022 2021 U.S. Upstream 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 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 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 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 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 U.S. Downstream 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 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 MMCFD 1 3 — Sales of NGLs MBD 153 127 96 Refinery Crude Oil Input MBD 626 639 576 1 Includes company share of equity affiliates. 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; MCF – thousands of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil; 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 MBD 51 45 55 6 Includes branded and unbranded gasoline. 7 Includes sales of affiliates: MBD 389 389 357 45 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents Liquidity and Capital Resources Sources and Uses of Cash The strength of the company’s balance sheet enables it to fund any timing differences throughout the year between cash inflows and outflows. Cash, Cash Equivalents and Marketable Securities Total balances were $8.2 billion and $17.9 billion at December 31, 2023 and 2022, respectively. 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. 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. These amounts are generally associated with upstream decommissioning activities, tax payments and funds held in escrow for tax-deferred exchanges. Dividends Dividends paid to common stockholders were $11.3 billion in 2023 and $11.0 billion in 2022. Debt and Finance Lease Liabilities Total debt and finance lease liabilities were $20.8 billion at December 31, 2023, down from $23.3 billion at year-end 2022. The $2.5 billion decrease in total debt and finance lease liabilities during 2023 was primarily due to the repayment of long-term notes that matured during the year. 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. Of these amounts, $4.5 billion and $4.1 billion were reclassified to long-term debt at the end of 2023 and 2022, respectively. At year-end 2023, settlement of these obligations was not expected to require the use of working capital in 2024, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis. During third quarter 2023, the company assumed $1.5 billion of debt in conjunction with the PDC acquisition, including balances outstanding under the revolving credit facility, PDC’s 6.125% notes due 2024 (2024 notes) and PDC’s 5.75% notes due 2026 (2026 notes). The outstanding balances under the revolving credit facility and the 2024 notes were repaid during third quarter 2023. The company also irrevocably deposited sufficient U.S. Treasury securities with U.S. Bank Trust Company, N.A., as trustee, to fund the redemption of the 2026 notes, resulting in the indenture being satisfied and discharged. 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. 46 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, Chevron U.S.A. Inc. (CUSA), Noble Energy, Inc. (Noble), and Texaco Capital Inc. Most of these securities are the obligations of, or guaranteed by, Chevron Corporation and are rated AA- by Standard and Poor’s Corporation and Aa2 by Moody’s Investors Service. The company’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and P-1 by Moody’s. All of these ratings denote high-quality, investment-grade securities. The company’s future debt level is dependent primarily on results of operations, cash that may be generated from asset dispositions, the capital program, lending commitments to affiliates and shareholder distributions. Based on its high-quality debt ratings, the company believes that it has substantial borrowing capacity to meet unanticipated cash requirements. During extended periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, the company has the ability to modify its capital spending plans and discontinue or curtail the stock repurchase program. This provides the flexibility to continue paying the common stock dividend and remain committed to retaining the company’s high-quality debt ratings. Committed Credit Facilities Information related to committed credit facilities is included in Note 19 Short-Term Debt . Summarized Financial Information for Guarantee of Securities of Subsidiaries CUSA issued bonds that are fully and unconditionally guaranteed on an unsecured basis by Chevron Corporation (together, the “Obligor Group”). The tables below contain summary financial information for Chevron Corporation, as Guarantor, excluding its consolidated subsidiaries, and CUSA, as the issuer, excluding its consolidated subsidiaries. The summary financial information of the Obligor Group is presented on a combined basis, and transactions between the combined entities have been eliminated. Financial information for non-guarantor entities has been excluded. Year Ended December 31, 2023 Year Ended December 31, 2022 (Millions of dollars) (unaudited) Sales and other operating revenues $ 100,405 $ 126,911 Sales and other operating revenues - related party 44,553 50,082 Total costs and other deductions 102,773 121,757 Total costs and other deductions - related party 35,781 43,042 Net income (loss) $ 12,190 $ 15,043 47 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents At December 31, 2023 At December 31, 2022 (Millions of dollars) (unaudited) Current assets $ 19,006 $ 28,781 Current assets - related party 18,375 12,326 Other assets 54,558 50,505 Current liabilities 20,512 22,663 Current liabilities - related party 132,474 118,277 Other liabilities 28,849 27,353 Total net equity (deficit) $ (89,896) $ (76,681) 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. 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 repurchases and the actual amount repurchased will depend on a variety of factors, including the market price of the company’s shares, general market and economic conditions, and other factors. The stock repurchase program does not obligate the company to acquire any particular amount of common stock and may be suspended or discontinued at any time. Capital Expenditures Capital expenditures (Capex) primarily includes additions to fixed asset or investment accounts for the company’s consolidated subsidiaries and is disclosed in the Consolidated Statement of Cash Flows. Capex by business segment for 2023, 2022 and 2021 is as follows: Year ended December 31 Capex 2023 2022 2021 Millions of dollars U.S. Int’l. Total U.S. Int’l. Total U.S. Int’l. Total Upstream $ 9,842 $ 3,836 $ 13,678 $ 6,847 $ 2,718 $ 9,565 $ 4,554 $ 2,221 $ 6,775 Downstream 1,536 237 1,773 1,699 375 2,074 806 234 1,040 All Other 351 27 378 310 25 335 221 20 241 Capex $ 11,729 $ 4,100 $ 15,829 $ 8,856 $ 3,118 $ 11,974 $ 5,581 $ 2,475 $ 8,056 Capex for 2023 was $15.8 billion, 32 percent higher than 2022 due to higher investments in the United States, including about $450 million invested in PDC assets post-acquisition and approximately $650 million of inorganic spend, mainly due to the acquisition of a majority stake in ACES Delta, LLC. Capex excludes the acquisition cost of PDC. The company estimates that 2024 Capex will be approximately $16 billion. In the upstream business, Capex is estimated to be $14 billion, two-thirds of which is expected to be in the U.S., and includes around $5 billion for Permian Basin development and roughly $1.5 billion for other shale & tight assets in the U.S. About 25 percent of U.S upstream Capex is planned for projects in the Gulf of Mexico. Worldwide downstream spending in 2024 is estimated to be $1.5 billion with 80 percent allocated in the U.S. In addition, investments in technology businesses and other corporate operations in 2024 are projected to be about $0.5 billion. Lower carbon Capex included in the upstream and downstream segments totals around $2 billion, including investments to lower the carbon intensity of Chevron’s traditional operations and grow new energy business lines. 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: 48 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents Year ended December 31 Affiliate Capex 2023 2022 2021 Millions of dollars U.S. Int’l. Total U.S. Int’l. Total U.S. Int’l. Total Upstream $ — $ 2,310 $ 2,310 $ — $ 2,406 $ 2,406 $ 2 $ 2,404 $ 2,406 Downstream 983 241 1,224 768 192 960 365 396 761 All Other — — — — — — — — — 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. Noncontrolling Interests The company had noncontrolling interests of $972 million at December 31, 2023 and $960 million at December 31, 2022. Distributions to noncontrolling interests net of contributions totaled $40 million and $114 million in 2023 and 2022, respectively. Included within noncontrolling interests at December 31, 2023 is $166 million of redeemable noncontrolling interest. Pension Obligations Information related to pension plan contributions is included in Note 23 Employee Benefit Plans , under the heading “Cash Contributions and Benefit Payments.” Contractual Obligations Information related to the company’s significant contractual obligations is included in Note 19 Short-Term Debt , in Note 20 Long-Term Debt and in Note 5 Lease Commitments . The aggregate amount of interest due on these obligations, excluding leases, is: 2024 – $554; 2025 – $494; 2026 – $413; 2027 – $358; 2028 – $319; after 2028 – $3,212. Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements Information related to these off-balance sheet matters is included in Note 24 Other Contingencies and Commitments , under the heading “Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements.” Direct Guarantees Information related to guarantees is included in Note 24 Other Contingencies and Commitments under the heading “Guarantees.” Indemnifications Information related to indemnifications is included in Note 24 Other Contingencies and Commitments under the heading “Indemnifications.” 49 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents Financial Ratios and Metrics The following represent several metrics the company believes are useful measures to monitor the financial health of the company and its performance over time: 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 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. At December 31 Millions of dollars 2023 2022 2021 Current assets $ 41,128 $ 50,343 $ 33,738 Current liabilities 32,258 34,208 26,791 Current Ratio 1.3 1.5 1.3 Interest Coverage Ratio Income before income tax expense, plus interest and debt expense and amortization of capitalized interest, less net income attributable to noncontrolling interests, divided by before-tax interest costs. This ratio indicates the company’s ability to pay interest on outstanding debt. Year ended December 31 Millions of dollars 2023 2022 2021 Income (Loss) Before Income Tax Expense $ 29,584 $ 49,674 $ 21,639 Plus: Interest and debt expense 469 516 712 Plus: Before-tax amortization of capitalized interest 223 199 215 Less: Net income attributable to noncontrolling interests 42 143 64 Subtotal for calculation 30,234 50,246 22,502 Total financing interest and debt costs $ 617 $ 630 $ 775 Interest Coverage Ratio 49.0 79.8 29.0 Free Cash Flow The cash provided by operating activities less capital expenditures, which represents the cash available to creditors and investors after investing in the business. Year ended December 31 Millions of dollars 2023 2022 2021 Net cash provided by operating activities $ 35,609 $ 49,602 $ 29,187 Less: Capital expenditures 15,829 11,974 8,056 Free Cash Flow $ 19,780 $ 37,628 $ 21,131 Debt Ratio Total debt as a percentage of total debt plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage. At December 31 Millions of dollars 2023 2022 2021 Short-term debt $ 529 $ 1,964 $ 256 Long-term debt 20,307 21,375 31,113 Total debt 20,836 23,339 31,369 Total Chevron Corporation Stockholders’ Equity 160,957 159,282 139,067 Total debt plus total Chevron Corporation Stockholders’ Equity $ 181,793 $ 182,621 $ 170,436 Debt Ratio 11.5 % 12.8 % 18.4 % 50 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents Net Debt Ratio Total debt less cash and cash equivalents and marketable securities as a percentage of total debt less cash and cash equivalents and marketable securities, plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage, net of its cash balances. At December 31 Millions of dollars 2023 2022 2021 Short-term debt $ 529 $ 1,964 $ 256 Long-term debt 20,307 21,375 31,113 Total Debt 20,836 23,339 31,369 Less: Cash and cash equivalents 8,178 17,678 5,640 Less: Marketable securities 45 223 35 Total adjusted debt 12,613 5,438 25,694 Total Chevron Corporation Stockholders’ Equity 160,957 159,282 139,067 Total adjusted debt plus total Chevron Corporation Stockholders’ Equity $ 173,570 $ 164,720 $ 164,761 Net Debt Ratio 7.3 % 3.3 % 15.6 % Capital Employed The sum of Chevron Corporation Stockholders’ Equity, total debt and noncontrolling interests, which represents the net investment in the business. At December 31 Millions of dollars 2023 2022 2021 Chevron Corporation Stockholders’ Equity $ 160,957 $ 159,282 $ 139,067 Plus: Short-term debt 529 1,964 256 Plus: Long-term debt 20,307 21,375 31,113 Plus: Noncontrolling interest 972 960 873 Capital Employed at December 31 $ 182,765 $ 183,581 $ 171,309 Return on Average Capital Employed (ROCE) Net income attributable to Chevron (adjusted for after-tax interest expense and noncontrolling interest) divided by average capital employed. Average capital employed is computed by averaging the sum of capital employed at the beginning and end of the year. ROCE is a ratio intended to measure annual earnings as a percentage of historical investments in the business. Year ended December 31 Millions of dollars 2023 2022 2021 Net income attributable to Chevron $ 21,369 $ 35,465 $ 15,625 Plus: After-tax interest and debt expense 432 476 662 Plus: Noncontrolling interest 42 143 64 Net income after adjustments 21,843 36,084 16,351 Average capital employed $ 183,173 $ 177,445 $ 174,175 Return on Average Capital Employed 11.9 % 20.3 % 9.4 % Return on Stockholders ’ Equity (ROSE) Net income attributable to Chevron divided by average Chevron Corporation Stockholders’ Equity. Average stockholders’ equity is computed by averaging the sum of stockholders’ equity at the beginning and end of the year. ROSE is a ratio intended to measure earnings as a percentage of shareholder investments. Year ended December 31 Millions of dollars 2023 2022 2021 Net income attributable to Chevron $ 21,369 $ 35,465 $ 15,625 Chevron Corporation Stockholders’ Equity at December 31 160,957 159,282 139,067 Average Chevron Corporation Stockholders’ Equity 160,120 149,175 135,378 Return on Average Stockholders’ Equity 13.3 % 23.8 % 11.5 % Financial and Derivative Instrument Market Risk The market risk associated with the company’s portfolio of financial and derivative instruments is discussed below. 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 Item 1A. Risk Factors . 51 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents Derivative Commodity Instruments Chevron is exposed to market risks related to the price volatility of crude oil, refined products, NGLs, natural gas, liquefied natural gas and refinery feedstocks. The company uses derivative commodity instruments to manage these exposures on a portion of its activity, including firm commitments and anticipated transactions for the purchase, sale and storage of crude oil, refined products, NGLs, natural gas, liquefied natural gas and feedstock for company refineries. The company also uses derivative commodity instruments for limited trading purposes. The results of these activities were not material to the company’s financial position, results of operations or cash flows in 2023. The company’s market exposure positions are monitored on a daily basis by an internal Risk Control group in accordance with the company’s risk management policies. The company’s risk management practices and its compliance with policies are reviewed by the Audit Committee of the company’s Board of Directors. Derivatives beyond those designated as normal purchase and normal sale contracts are recorded at fair value on the Consolidated Balance Sheet with resulting gains and losses reflected in income. Fair values are derived principally from published market quotes and other independent third-party quotes. The change in fair value of Chevron’s derivative commodity instruments in 2023 was not material to the company’s results of operations. The company uses the Monte Carlo simulation method as its Value-at-Risk (VaR) model to estimate the maximum potential loss in fair value, at the 95 percent confidence level with a one-day holding period, from the effect of adverse changes in market conditions on derivative commodity instruments held or issued. Based on these inputs, the VaR for the company’s primary risk exposures in the area of derivative commodity instruments at December 31, 2023 and 2022 was not material to the company’s cash flows or results of operations. Foreign Currency The company may enter into foreign currency derivative contracts to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments. 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 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. Interest rate swaps, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. At year-end 2023, the company had no interest rate swaps. Transactions With Related Parties Chevron enters into a number of business arrangements with related parties, principally its equity affiliates. These arrangements include long-term supply or offtake agreements and long-term purchase agreements. Refer to “Other Information” in Note 15 Investments and Advances for further discussion. Management believes these agreements have been negotiated on terms consistent with those that would have been negotiated with an unrelated party. Litigation and Other Contingencies Ecuador Information related to Ecuador matters is included in Note 16 Litigation under the heading “Ecuador.” Climate Change Information related to climate change-related matters is included in Note 16 Litigation under the heading “Climate Change.” Louisiana Information related to Louisiana coastal matters is included in Note 16 Litigation under the heading “Louisiana.” Environmental The following table displays the annual changes to the company’s before-tax environmental remediation reserves, including those for U.S. federal Superfund sites and analogous sites under state laws. Millions of dollars 2023 2022 2021 Balance at January 1 $ 868 $ 960 $ 1,139 Net additions 327 182 114 Expenditures (259) (274) (293) Balance at December 31 $ 936 $ 868 $ 960 The company records asset retirement obligations when there is a legal obligation associated with the retirement of long-lived assets and the liability can be reasonably estimated. These asset retirement obligations include costs related to 52 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents environmental issues. The liability balance of approximately $13.8 billion for asset retirement obligations at year-end 2023 is related primarily to upstream properties. For the company’s other ongoing operating assets, such as refineries and chemicals facilities, no provisions are made for exit or cleanup costs that may be required when such assets reach the end of their useful lives unless a decision to sell or otherwise decommission the facility has been made, as the indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the asset retirement obligation. 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 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. Suspended Wells Information related to suspended wells is included in Note 21 Accounting for Suspended Exploratory Wells . Income Taxes Information related to income tax contingencies is included in Note 17 Taxes and in Note 24 Other Contingencies and Commitments under the heading “Income Taxes.” Other Contingencies Information related to other contingencies is included in Note 24 Other Contingencies and Commitments under the heading “Other Contingencies.” Environmental Matters The company is subject to various international and U.S. federal, state and local environmental, health and safety laws, regulations and market-based programs. These laws, regulations and programs continue to evolve and are expected to increase in both number and complexity over time and govern not only the manner in which the company conducts its operations, but also the products it sells. Consideration of environmental issues and the responses to those issues through international agreements and national, regional or state legislation or regulations are integrated into the company’s strategy and planning, capital investment reviews and risk management tools and processes, where applicable. They are also factored into the company’s long-range supply, demand and energy price forecasts. These forecasts reflect long-range effects from renewable fuel penetration, energy efficiency standards, climate-related policy actions, and demand response to oil and natural gas prices. In addition, legislation and regulations intended to address hydraulic fracturing also continue to evolve in many jurisdictions where we operate. 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. However, it is not possible to predict with certainty the amount of additional investments in new or existing technology or facilities or the amounts of increased operating costs to be incurred in the future to prevent, control, reduce or eliminate releases of hazardous materials or other pollutants into the environment; remediate and restore areas damaged by prior releases of hazardous materials; or comply with new environmental laws or regulations. Although these costs may be significant to the results of operations in any single period, the company does not presently expect them to have a material adverse effect on the company’s liquidity or financial position. Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. The company may incur expenses for corrective actions at various owned and previously owned facilities and at third-party-owned waste disposal sites used by the company. An obligation may arise when operations are closed or sold or at non-Chevron sites where company products have been handled or disposed of. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered acceptable at the time but now require investigative or remedial work or both to meet current standards. 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 $0.5 billion of environmental capital expenditures and $2.0 billion of costs associated 53 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. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites. Critical Accounting Estimates and Assumptions Management makes many estimates and assumptions in the application of accounting principles generally accepted in the United States of America (GAAP) that may have a material impact on the company’s consolidated financial statements and related disclosures and on the comparability of such information over different reporting periods. Such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on management’s experience and other information available prior to the issuance of the financial statements. Materially different results can occur as circumstances change and additional information becomes known. The discussion in this section of “critical” accounting estimates and assumptions is according to the disclosure guidelines of the SEC, wherein: 1. the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters, or the susceptibility of such matters to change; and 2. the impact of the estimates and assumptions on the company’s financial condition or operating performance is material. The development and selection of accounting estimates and assumptions, including those deemed “critical,” and the associated disclosures in this discussion have been discussed with the Audit Committee of the Board of Directors. The areas of accounting and the associated “critical” estimates and assumptions made by the company are as follows: Oil and Gas Reserves Crude oil, 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. Proved reserves include both developed and undeveloped volumes. Proved developed reserves represent volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for recompletion. Variables impacting Chevron’s estimated volumes of crude oil and natural gas reserves include field performance, available technology, commodity prices, and development, production and carbon costs. 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: 1. 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 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. 2. Impairment - Oil and gas reserves are used in assessing oil and gas producing properties for impairment. A significant reduction in the estimated reserves of a property would trigger an impairment review. Proved reserves (and, in some cases, a portion of unproved resources) are used to estimate future production volumes in the cash flow model. 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 , “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. 54 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents This Oil and Gas Reserves commentary should be read in conjunction with the Properties, Plant and Equipment section of Note 1 Summary of Significant Accounting Policies , which includes a description of the “successful efforts” method of accounting for oil and gas exploration and production activities. Impairment of Properties, Plant and Equipment and Investments in Affiliates The company assesses its properties, plant and equipment (PP&E) for possible impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of the carrying value of the asset over its estimated fair value. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters, such as future commodity prices, operating expenses, carbon costs, production profiles, the pace of the energy transition, and the outlook for global or regional market supply-and-demand conditions for crude oil, NGLs, natural gas, commodity chemicals and refined products. 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. Refer also to the discussion of impairments of properties, plant and equipment in Note 18 Properties, Plant and Equipment and to the section on Properties, Plant and Equipment in Note 1 Summary of Significant Accounting Policies . 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, 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. Also, if the expectation of sale of a particular asset or asset group in any period has been deemed more likely than not, an impairment review is performed, and if the estimated net proceeds exceed the carrying value of the asset or asset group, no impairment charge is required. Such calculations are reviewed each period until the asset or asset group is disposed. Assets that are not impaired on a held-and-used basis could possibly become impaired if a decision is made to sell such assets. That is, the assets would be impaired if they are classified as held-for-sale and the estimated proceeds from the sale, less costs to sell, are less than the assets’ associated carrying values. Investments in common stock of affiliates that are accounted for under the equity method, as well as investments in other securities of these equity investees, are reviewed for impairment when the fair value of the investment falls below the company’s carrying value. When this occurs, a determination must be made as to whether this loss is other-than-temporary, in which case the investment is impaired. Because of the number of differing assumptions potentially affecting whether an investment is impaired in any period or the amount of the impairment, a sensitivity analysis is not practicable. A sensitivity analysis of the impact on earnings for these periods if other assumptions had been used in impairment reviews and impairment calculations is not practicable, given the broad range of the company’s PP&E and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired, or resulted in larger impacts on impaired assets. Asset Retirement Obligations In the determination of fair value for an asset retirement obligation (ARO), the company uses various assumptions and judgments, including such factors as the existence of a legal obligation, estimated amounts and timing of settlements, discount and inflation rates, and the expected impact of advances in technology and process improvements. A sensitivity analysis of the ARO impact on earnings for 2023 is not practicable, given the broad range of the company’s long-lived assets and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions would have reduced estimated future obligations, thereby lowering accretion expense and amortization costs, whereas unfavorable changes would have the opposite effect. Refer to Note 25 Asset Retirement Obligations for additional discussions on asset retirement obligations. Pension and Other Postretirement Benefit Plans Note 23 Employee Benefit Plans includes information on the funded status of the company’s pension and other postretirement benefit (OPEB) plans reflected on the Consolidated Balance Sheet; the components of pension and OPEB expense reflected on the Consolidated Statement of Income; and the related underlying assumptions. 55 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents The determination of pension plan expense and obligations is based on a number of actuarial assumptions. Two critical assumptions are the expected long-term rate of return on plan assets and the discount rate applied to pension plan obligations. Critical assumptions in determining expense and obligations for OPEB plans, which provide for certain health care and life insurance benefits for qualifying retired employees and which are not funded, are the discount rate and the assumed health care cost-trend rates. Information related to the company’s processes to develop these assumptions is included in Note 23 Employee Benefit Plans under the relevant headings. Actual rates may vary significantly from estimates because of unanticipated changes beyond the company’s control. For 2023, the company used an expected long-term rate of return of 7.0 percent and a discount rate for service costs of 5.2 percent and a discount rate for interest cost of 5.0 percent for the primary U.S. pension plan. The actual return for 2023 was 10.9 percent. For the 10 years ended December 31, 2023, actual asset returns averaged 5.3 percent for this plan. Additionally, with the exception of three years within this 10-year period, actual asset returns for this plan equaled or exceeded 7.0 percent during each year. Total pension expense for 2023 was $557 million. 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 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 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. An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan. At December 31, 2023, the company used a discount rate of 5.0 percent to measure the obligations for the primary U.S. pension plan. As an indication of the sensitivity of pension liabilities to the discount rate assumption, a 0.25 percent increase in the discount rate applied to the company’s primary U.S. pension plan, which accounted for about 65 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $279 million, and would have changed the plan’s funded status from a deficit of $80 million to a surplus of $199 million. 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. For the primary U.S. OPEB plan, the company used a discount rate for service cost of 5.3 percent and a discount rate for interest cost of 5.1 percent to measure expense in 2023, and a 5.0 percent discount rate to measure the benefit obligations at December 31, 2023. Discount rate changes, similar to those used in the pension sensitivity analysis, resulted in an immaterial impact on 2023 OPEB expense and OPEB liabilities at the end of 2023. Differences between the various assumptions used to determine expense and the funded status of each plan and actual experience are included in actuarial gain/loss. Refer to page 93 in Note 23 Employee Benefit Plans for more information on the $3.7 billion of before-tax actuarial losses recorded by the company as of December 31, 2023. 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.” 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. For example, the costs for settlement of claims and litigation can vary from estimates based on differing interpretations of laws, opinions on culpability and assessments on the amount of damages. Similarly, liabilities for environmental remediation are subject to change because of changes in laws, regulations and their interpretation, the determination of additional information on the extent and nature of site contamination, and improvements in technology. 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,” “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 56 Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents more likely than not (i.e., likelihood greater than 50 percent) to be allowed by the tax jurisdiction. For additional discussion of income tax uncertainties, refer to Note 24 Other Contingencies and Commitments under the heading “Income Taxes.” Refer also to the business segment discussions elsewhere in this section for the effect on earnings from losses associated with certain litigation, environmental remediation and tax matters for the three years ended December 31, 2023. An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in recording these liabilities is not practicable because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss. For further information, refer to “Changes in management’s estimates and assumptions may have a material impact on the company’s consolidated financial statements and financial or operational performance in any given period” in Item 1A. Risk Factors , on page 26. New Accounting Standards Refer to Note 4 New Accounting Standards for information regarding new accounting standards. 57 Financial Table of Contents Quarterly Results Unaudited 2023 2022 Millions of dollars, except per-share amounts 4th Q 3rd Q 2nd Q 1st Q 4th Q 3rd Q 2nd Q 1st Q Revenues and Other Income Sales and other operating revenues $ 48,933 $ 51,922 $ 47,216 $ 48,842 $ 54,523 $ 63,508 $ 65,372 $ 52,314 Income from equity affiliates 990 1,313 1,240 1,588 1,623 2,410 2,467 2,085 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 Costs and Other Deductions Purchased crude oil and products 28,477 32,328 28,984 29,407 32,570 38,751 40,684 33,411 Operating expenses 6,510 6,299 6,057 6,021 6,401 6,357 6,318 5,638 Selling, general and administrative expenses 969 1,163 1,128 881 1,454 1,028 863 967 Exploration expenses 254 301 169 190 453 116 196 209 Depreciation, depletion and amortization 6,254 4,025 3,521 3,526 4,764 4,201 3,700 3,654 Taxes other than on income 1,062 1,021 1,041 1,096 864 1,046 882 1,240 Interest and debt expense 120 114 120 115 123 128 129 136 Other components of net periodic benefit costs 44 91 39 38 36 208 (13) 64 Total Costs and Other Deductions 43,690 45,342 41,059 41,274 46,665 51,835 52,759 45,319 Income (Loss) Before Income Tax Expense 3,490 8,738 7,837 9,519 9,808 14,809 16,003 9,054 Income Tax Expense (Benefit) 1,247 2,183 1,829 2,914 3,430 3,571 4,288 2,777 Net Income (Loss) $ 2,243 $ 6,555 $ 6,008 $ 6,605 $ 6,378 $ 11,238 $ 11,715 $ 6,277 Less: 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 Per Share of Common Stock Net Income (Loss) Attributable to Chevron Corporation – Basic $ 1.23 $ 3.48 $ 3.22 $ 3.48 $ 3.34 $ 5.81 $ 5.98 $ 3.23 – Diluted $ 1.22 $ 3.48 $ 3.20 $ 3.46 $ 3.33 $ 5.78 $ 5.95 $ 3.22 Dividends per share $ 1.51 $ 1.51 $ 1.51 $ 1.51 $ 1.42 $ 1.42 $ 1.42 $ 1.42 58 Financial Table of Contents Management’s Responsibility for Financial Statements To the Stockholders of Chevron Corporation Management of Chevron Corporation is responsible for preparing the accompanying consolidated financial statements and the related information appearing in this report. The statements were prepared in accordance with accounting principles generally accepted in the United States of America and fairly represent the transactions and financial position of the company. The financial statements include amounts that are based on management’s best estimates and judgments. As stated in its report included herein, the independent registered public accounting firm of PricewaterhouseCoopers LLP has audited the company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). The Board of Directors of Chevron has an Audit Committee composed of directors who are not officers or employees of the company. The Audit Committee meets regularly with members of management, the internal auditors and the independent registered public accounting firm to review accounting, internal control, auditing and financial reporting matters. Both the internal auditors and the independent registered public accounting firm have free and direct access to the Audit Committee without the presence of management. The company’s management has evaluated, with the participation of the Chief Executive Officer and Chief Financial Officer, the effectiveness of the company’s disclosure controls and procedures (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2023. Based on that evaluation, management concluded that the company’s disclosure controls are effective in ensuring that information required to be recorded, processed, summarized and reported are done within the time periods specified in the U.S. Securities and Exchange Commission’s rules and forms. Management’s Report on Internal Control Over Financial Reporting The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in the Exchange Act Rules 13a-15(f) and 15d-15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s internal control over financial reporting based on the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 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. 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. /s/ MICHAEL K. WIRTH /s/ PIERRE R. BREBER /s/ ALANA K. KNOWLES Michael K. Wirth Pierre R. Breber Alana K. Knowles Chairman of the Board Vice President Vice President and Chief Executive Officer and Chief Financial Officer and Controller February 26, 2024 59 Financial Table of Contents Report of Independent Registered Public Accounting Firm To the Board of Directors and Stockholders of Chevron Corporation Opinions on the Financial Statements and Internal Control over Financial Reporting We have audited the accompanying consolidated balance sheet of Chevron Corporation and its subsidiaries (the “Company”) as of December 31, 2023 and 2022, and the related consolidated statements of income, of comprehensive income, of equity and of cash flows for each of the three years in the period ended December 31, 2023, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO. Basis for Opinions The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. 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 60 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. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. The 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. The Company follows the successful efforts method of accounting for crude oil and natural gas exploration and production activities. Depreciation and depletion of all capitalized costs of proved crude oil and natural gas producing properties, except mineral interests, are expensed using the unit-of-production method, generally by individual field, as the proved developed reserves are produced. Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of-production method by individual field as the related proved reserves are produced. As disclosed by management, variables impacting the Company’s estimated volumes of proved crude oil and natural gas reserves include field performance, available technology, commodity prices, and development, production and carbon costs. Reserves are estimated by Company asset teams composed of earth scientists and engineers. As part of the internal control process related to reserves estimation, the Company maintains a Reserves Advisory Committee (RAC) (the Company’s earth scientists, engineers and RAC are collectively referred to as “management’s specialists”). The principal considerations for our determination that performing procedures relating to the impact of proved developed crude oil and natural gas reserves on upstream property, plant, and equipment, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved developed crude oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained related to the data, methods and assumptions used by management and its specialists in developing the estimates of proved developed crude oil and natural gas reserves. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved developed crude oil and natural gas reserves. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved developed crude oil and natural gas reserves. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of data used by the specialists and an evaluation of the specialists’ findings related to estimated future production volumes by comparing the estimate to relevant historical and current period information, as applicable. /s/ PricewaterhouseCoopers LLP San Francisco, California February 26, 2024 We have served as the Company’s auditor since 1935. 61 Consolidated Statement of Income Financial Table of Contents Millions of dollars, except per-share amounts Year ended December 31 2023 2022 2021 Revenues and Other Income Sales and other operating revenues $ 196,913 $ 235,717 $ 155,606 Income (loss) from equity affiliates 5,131 8,585 5,657 Other income (loss) ( 1,095 ) 1,950 1,202 Total Revenues and Other Income 200,949 246,252 162,465 Costs and Other Deductions Purchased crude oil and products 119,196 145,416 92,249 Operating expenses 24,887 24,714 20,726 Selling, general and administrative expenses 4,141 4,312 4,014 Exploration expenses 914 974 549 Depreciation, depletion and amortization 17,326 16,319 17,925 Taxes other than on income 4,220 4,032 3,963 Interest and debt expense 469 516 712 Other components of net periodic benefit costs 212 295 688 Total Costs and Other Deductions 171,365 196,578 140,826 Income (Loss) Before Income Tax Expense 29,584 49,674 21,639 Income Tax Expense (Benefit) 8,173 14,066 5,950 Net Income (Loss) 21,411 35,608 15,689 Less: Net income (loss) attributable to noncontrolling interests 42 143 64 Net Income (Loss) Attributable to Chevron Corporation $ 21,369 $ 35,465 $ 15,625 Per Share of Common Stock Net Income (Loss) Attributable to Chevron Corporation - Basic $ 11.41 $ 18.36 $ 8.15 - Diluted $ 11.36 $ 18.28 $ 8.14 See accompanying Notes to the Consolidated Financial Statements. 62 Consolidated Statement of Comprehensive Income Financial Table of Contents Millions of dollars Year ended December 31 2023 2022 2021 Net Income (Loss) $ 21,411 $ 35,608 $ 15,689 Currency translation adjustment Unrealized net change arising during period 11 ( 41 ) ( 55 ) Unrealized holding gain (loss) on securities Net gain (loss) arising during period 1 ( 1 ) ( 1 ) Derivatives Net derivatives gain (loss) on hedge transactions ( 11 ) 65 ( 6 ) Reclassification to net income 33 ( 80 ) 6 Income tax benefit (cost) on derivatives transactions ( 5 ) 3 — Total 17 ( 12 ) — Defined benefit plans Actuarial gain (loss) Amortization to net income of net actuarial loss and settlements 244 599 1,069 Actuarial gain (loss) arising during period ( 550 ) 1,050 1,244 Prior service credits (cost) Amortization to net income of net prior service costs and curtailments ( 13 ) ( 19 ) ( 14 ) Prior service (costs) credits arising during period ( 29 ) ( 96 ) — Defined benefit plans sponsored by equity affiliates - benefit (cost) 6 100 127 Income tax benefit (cost) on defined benefit plans 151 ( 489 ) ( 647 ) Total ( 191 ) 1,145 1,779 Other Comprehensive Gain (Loss), Net of Tax ( 162 ) 1,091 1,723 Comprehensive Income (Loss) 21,249 36,699 17,412 Comprehensive loss (income) attributable to noncontrolling interests ( 42 ) ( 143 ) ( 64 ) Comprehensive Income (Loss) Attributable to Chevron Corporation $ 21,207 $ 36,556 $ 17,348 See accompanying Notes to the Consolidated Financial Statements. 63 Consolidated Balance Sheet Financial Table of Contents Millions of dollars, except per-share amounts At December 31 2023 2022 Assets Cash and cash equivalents $ 8,178 $ 17,678 Marketable securities 45 223 Accounts and notes receivable (less allowance: 2023 - $ 301 ; 2022 - $ 457 ) 19,921 20,456 Inventories: Crude oil and products 6,059 5,866 Chemicals 406 515 Materials, supplies and other 2,147 1,866 Total inventories 8,612 8,247 Prepaid expenses and other current assets 4,372 3,739 Total Current Assets 41,128 50,343 Long-term receivables, net (less allowances: 2023 - $ 340 ; 2022 - $ 552 ) 942 1,069 Investments and advances 46,812 45,238 Properties, plant and equipment, at cost 346,081 327,785 Less: Accumulated depreciation, depletion and amortization 192,462 184,194 Properties, plant and equipment, net 153,619 143,591 Deferred charges and other assets 13,734 12,310 Goodwill 4,722 4,722 Assets held for sale 675 436 Total Assets $ 261,632 $ 257,709 Liabilities and Equity Short-term debt $ 529 $ 1,964 Accounts payable 20,423 18,955 Accrued liabilities 7,655 7,486 Federal and other taxes on income 1,863 4,381 Other taxes payable 1,788 1,422 Total Current Liabilities 32,258 34,208 Long-term debt 1 20,307 21,375 Deferred credits and other noncurrent obligations 24,226 20,396 Noncurrent deferred income taxes 18,830 17,131 Noncurrent employee benefit plans 4,082 4,357 Total Liabilities 2 $ 99,703 $ 97,467 Preferred stock (authorized 100,000,000 shares; $ 1.00 par value; none issued) — — Common stock (authorized 6,000,000,000 shares; $ 0.75 par value; 2,442,676,580 shares issued at December 31, 2023 and 2022) 1,832 1,832 Capital in excess of par value 21,365 18,660 Retained earnings 200,025 190,024 Accumulated other comprehensive losses ( 2,960 ) ( 2,798 ) Deferred compensation and benefit plan trust ( 240 ) ( 240 ) Treasury stock, at cost (2023 - 577,028,776 shares; 2022 - 527,460,237 shares) ( 59,065 ) ( 48,196 ) Total Chevron Corporation Stockholders’ Equity 160,957 159,282 Noncontrolling interests (includes redeemable noncontrolling interest of $ 166 and $ 142 at December 31, 2023 and 2022) 972 960 Total Equity 161,929 160,242 Total Liabilities and Equity $ 261,632 $ 257,709 1 Includes finance lease liabilities of $ 574 and $ 403 at December 31, 2023 and 2022, respectively. 2 Refer to Note 24 Other Contingencies and Commitments . See accompanying Notes to the Consolidated Financial Statements. 64 Consolidated Statement of Cash Flows Financial Table of Contents Millions of dollars Year ended December 31 2023 2022 2021 Operating Activities Net Income (Loss) $ 21,411 $ 35,608 $ 15,689 Adjustments Depreciation, depletion and amortization 17,326 16,319 17,925 Dry hole expense 436 486 118 Distributions more (less) than income from equity affiliates ( 885 ) ( 4,730 ) ( 1,998 ) Net before-tax gains on asset retirements and sales ( 138 ) ( 550 ) ( 1,021 ) Net foreign currency effects 578 ( 412 ) ( 7 ) Deferred income tax provision 298 2,124 700 Net decrease (increase) in operating working capital ( 3,185 ) 2,125 ( 1,361 ) Decrease (increase) in long-term receivables 150 153 21 Net decrease (increase) in other deferred charges ( 300 ) ( 212 ) ( 320 ) Cash contributions to employee pension plans ( 1,120 ) ( 1,322 ) ( 1,751 ) Other 1,038 13 1,192 Net Cash Provided by Operating Activities 35,609 49,602 29,187 Investing Activities Acquisition of businesses, net of cash received 55 ( 2,862 ) — Capital expenditures ( 15,829 ) ( 11,974 ) ( 8,056 ) Proceeds and deposits related to asset sales and returns of investment 669 2,635 1,791 Net sales (purchases) of marketable securities 175 117 ( 1 ) Net repayment (borrowing) of loans by equity affiliates ( 302 ) ( 24 ) 401 Net Cash Used for Investing Activities ( 15,232 ) ( 12,108 ) ( 5,865 ) Financing Activities Net borrowings (repayments) of short-term obligations 135 263 ( 5,572 ) Proceeds from issuances of long-term debt 150 — — Repayments of long-term debt and other financing obligations ( 4,340 ) ( 8,742 ) ( 7,364 ) Cash dividends - common stock ( 11,336 ) ( 10,968 ) ( 10,179 ) Net contributions from (distributions to) noncontrolling interests ( 40 ) ( 114 ) ( 36 ) Net sales (purchases) of treasury shares ( 14,678 ) ( 5,417 ) 38 Net Cash Provided by (Used for) Financing Activities ( 30,109 ) ( 24,978 ) ( 23,113 ) Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash ( 114 ) ( 190 ) ( 151 ) Net Change in Cash, Cash Equivalents and Restricted Cash ( 9,846 ) 12,326 58 Cash, Cash Equivalents and Restricted Cash at January 1 19,121 6,795 6,737 Cash, Cash Equivalents and Restricted Cash at December 31 $ 9,275 $ 19,121 $ 6,795 See accompanying Notes to the Consolidated Financial Statements. 65 Consolidated Statement of Equity Financial Table of Contents Amounts in millions of dollars Acc. Other Treasury Chevron Corp. Common Retained Comprehensive Stock Stockholders’ Noncontrolling Total Stock 1 Earnings Income (Loss) ( at cost ) Equity Interests Equity Balance at December 31, 2020 $ 18,421 $ 160,377 $ ( 5,612 ) $ ( 41,498 ) $ 131,688 $ 1,038 $ 132,726 Treasury stock transactions 315 — — — 315 — 315 NBLX acquisition 138 ( 148 ) — 377 367 ( 321 ) 46 Net income (loss) — 15,625 — — 15,625 64 15,689 Cash dividends ($ 5.31 per share) — ( 10,179 ) — — ( 10,179 ) ( 53 ) ( 10,232 ) Stock dividends — ( 3 ) — — ( 3 ) — ( 3 ) Other comprehensive income — — 1,723 — 1,723 — 1,723 Purchases of treasury shares — — — ( 1,383 ) ( 1,383 ) — ( 1,383 ) Issuances of treasury shares — — — 1,040 1,040 — 1,040 Other changes, net — ( 126 ) — — ( 126 ) 145 19 Balance at December 31, 2021 $ 18,874 $ 165,546 $ ( 3,889 ) $ ( 41,464 ) $ 139,067 $ 873 $ 139,940 Treasury stock transactions 63 — — — 63 — 63 Net income (loss) — 35,465 — — 35,465 143 35,608 Cash dividends ($ 5.68 per share) — ( 10,968 ) — — ( 10,968 ) ( 118 ) ( 11,086 ) Stock dividends — ( 3 ) — — ( 3 ) — ( 3 ) Other comprehensive income — — 1,091 — 1,091 — 1,091 Purchases of treasury shares — — — ( 11,255 ) ( 11,255 ) — ( 11,255 ) Issuances of treasury shares 1,315 — — 4,523 5,838 — 5,838 Other changes, net — ( 16 ) — — ( 16 ) 62 46 Balance at December 31, 2022 $ 20,252 $ 190,024 $ ( 2,798 ) $ ( 48,196 ) $ 159,282 $ 960 $ 160,242 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 Cash dividends ($ 6.04 per share) — ( 11,336 ) — — ( 11,336 ) ( 54 ) ( 11,390 ) Stock dividends — ( 9 ) — — ( 9 ) — ( 9 ) Other comprehensive income — — ( 162 ) — ( 162 ) — ( 162 ) Purchases of treasury shares 2 — — — ( 15,085 ) ( 15,085 ) — ( 15,085 ) Issuances of treasury shares 17 — — 246 263 — 263 Other changes, net ( 36 ) ( 23 ) — — ( 59 ) 24 ( 35 ) Balance at December 31, 2023 $ 22,957 $ 200,025 $ ( 2,960 ) $ ( 59,065 ) $ 160,957 $ 972 $ 161,929 Common Stock Share Activity Issued 3 Treasury Outstanding Balance at December 31, 2020 2,442,676,580 ( 517,490,263 ) 1,925,186,317 Purchases — ( 13,015,737 ) ( 13,015,737 ) Issuances — 17,635,477 17,635,477 Balance at December 31, 2021 2,442,676,580 ( 512,870,523 ) 1,929,806,057 Purchases — ( 69,912,961 ) ( 69,912,961 ) Issuances — 55,323,247 55,323,247 Balance at December 31, 2022 2,442,676,580 ( 527,460,237 ) 1,915,216,343 Purchases — ( 92,849,905 ) ( 92,849,905 ) Issuances — 43,281,366 43,281,366 Balance at December 31, 2023 2,442,676,580 ( 577,028,776 ) 1,865,647,804 1 Beginning and ending balances for all periods include capital in excess of par, common stock issued at par for $ 1,832 , and $( 240 ) associated with Chevron’s Benefit Plan Trust. Changes reflect capital in excess of par. 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. See accompanying Notes to the Consolidated Financial Statements. 66 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Note 1 Summary of Significant Accounting Policies General The company’s Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America. These require the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Although the company uses its best estimates and judgments, actual results could differ from these estimates as circumstances change and additional information becomes known. Prior years’ data have been reclassified in certain cases to conform to the 2023 presentation basis. Subsidiary and Affiliated Companies The Consolidated Financial Statements include the accounts of controlled subsidiary companies more than 50 percent-owned and any variable interest entities in which the company is the primary beneficiary. Undivided interests in oil and gas joint ventures and certain other assets are consolidated on a proportionate basis. Investments in and advances to affiliates in which the company has a substantial ownership interest of approximately 20 percent to 50 percent, or for which the company exercises significant influence but not control over policy decisions, are accounted for by the equity method. Investments in affiliates are assessed for possible impairment when events indicate that the fair value of the investment may be below the company’s carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in net income. In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee’s financial performance, and the company’s ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. The new cost basis of investments in these equity investees is not changed for subsequent recoveries in fair value. Differences between the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned to the extent practicable to specific assets and liabilities based on the company’s analysis of the various factors giving rise to the difference. When appropriate, the company’s share of the affiliate’s reported earnings is adjusted quarterly to reflect the difference between these allocated values and the affiliate’s historical book values. Noncontrolling Interests Ownership interests in the company’s subsidiaries held by parties other than the parent are presented separately from the parent’s equity on the Consolidated Balance Sheet. The amount of consolidated net income attributable to the parent and the noncontrolling interests are both presented on the face of the Consolidated Statement of Income and Consolidated Statement of Equity. Included within noncontrolling interest is redeemable noncontrolling interest. Fair Value Measurements The three levels of the fair value hierarchy of inputs the company uses to measure the fair value of an asset or a liability are as follows. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Level 3 inputs are inputs that are not observable in the market. Derivatives The majority of the company’s activity in derivative commodity instruments is intended to manage the financial risk posed by physical transactions. For some of this derivative activity, the company may elect to apply fair value or cash flow hedge accounting with changes in fair value recorded as components of accumulated other comprehensive income (loss). For other similar derivative instruments, generally because of the short-term nature of the contracts or their limited use, the company does not apply hedge accounting, and changes in the fair value of those contracts are reflected in current income. For the company’s commodity trading activity, gains and losses from derivative instruments are reported in current income. 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. Interest rate swaps related to a portion of the company’s fixed-rate debt, if any, may be accounted for as fair value hedges. Interest rate swaps related to floating-rate debt, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. Where Chevron is a party to master netting arrangements, fair value receivable and payable amounts recognized for derivative instruments executed with the same counterparty are generally offset on the balance sheet. Inventories Crude oil, products and chemicals inventories are generally stated at cost, using a last-in, first-out method. In the aggregate, these costs are below market. “Materials, supplies and other” inventories are primarily stated at cost or net realizable value. 67 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. All other exploratory wells and costs are expensed. Refer to Note 21 Accounting for Suspended Exploratory Wells for additional discussion of accounting for suspended exploratory well costs. Long-lived assets to be held and used, including proved crude oil and natural gas properties, are assessed for possible impairment by comparing their carrying values with their associated undiscounted, future net cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset (including changes to the commodity price forecast or carbon costs), significant change in the extent or manner of use of or a physical change in an asset, and a more likely than not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted, future net cash flows. For proved crude oil and natural gas properties, the company performs impairment reviews on a country, concession, PSC, development area or field basis, as appropriate. In downstream, impairment reviews are performed on the basis of a refinery, a plant, a marketing/lubricants area or distribution area, as appropriate. Impairment amounts are recorded as incremental “Depreciation, depletion and amortization” expense. Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value. Refer to Note 9 Fair Value Measurements relating to fair value measurements. The fair value of a liability for an ARO is recorded as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. Refer also to Note 25 Asset Retirement Obligations relating to AROs. Depreciation and depletion of all capitalized costs of proved crude oil and natural gas producing properties, except mineral interests, are expensed using the unit-of-production method, generally by individual field, as the proved developed reserves are produced. 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. Impairments of capitalized costs of unproved mineral interests are expensed. The capitalized costs of all other plant and equipment are depreciated or amortized over their estimated useful lives. In general, the declining-balance method is used to depreciate plant and equipment in the United States; the straight-line method is generally used to depreciate international plant and equipment and to amortize finance lease right-of-use assets. Gains or losses are not recognized for normal retirements of properties, plant and equipment subject to composite group amortization or depreciation. Gains or losses from abnormal retirements are recorded as expenses, and from sales as “Other income.” Expenditures for maintenance (including those for planned major maintenance projects), repairs and minor renewals to maintain facilities in operating condition are generally expensed as incurred. Major replacements and renewals are capitalized. Leases Leases are classified as operating or finance leases. Both operating and finance leases recognize lease liabilities and associated right-of-use assets. The company has elected the short-term lease exception and therefore only recognizes right-of-use assets and lease liabilities for leases with a term greater than one year. The company has elected the practical expedient to not separate non-lease components from lease components for most asset classes except for certain asset classes that have significant non-lease (i.e., service) components. Where leases are used in joint ventures, the company recognizes 100 percent of the right-of-use assets and lease liabilities when the company is the sole signatory for the lease (in most cases, where the company is the operator of a joint venture). Lease costs reflect only the costs associated with the operator’s working interest share. The lease term includes the committed lease term identified in the contract, taking into account renewal and termination options that management is 68 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts reasonably certain to exercise. The company uses its incremental borrowing rate as a proxy for the discount rate based on the term of the lease unless the implicit rate is available. Goodwill Goodwill resulting from a business combination is not subject to amortization. The company tests such goodwill at the reporting unit level for impairment annually at December 31, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount. Environmental Expenditures Environmental expenditures that relate to ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized. Liabilities related to future remediation costs are recorded when environmental assessments or cleanups or both are probable and the costs can be reasonably estimated. For crude oil, natural gas and mineral-producing properties, a liability for an ARO is made in accordance with accounting standards for asset retirement and environmental obligations. 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 . For U.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. The gross amount of environmental liabilities is based on the company’s best estimate of future costs using currently available technology and applying current regulations and the company’s own internal environmental policies. Future amounts are not discounted. Recoveries or reimbursements are recorded as assets when receipt is reasonably assured. Currency Translation The U.S. dollar is the functional currency for substantially all of the company’s consolidated operations and those of its equity affiliates. For those operations, all gains and losses from currency remeasurement are included in current period income. The cumulative translation effects for those few entities, both consolidated and affiliated, using functional currencies other than the U.S. dollar are included in “Currency translation adjustment” on the Consolidated Statement of Equity. 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. Payment is generally due within 30 days of delivery. The company accounts for delivery transportation as a fulfillment cost, not a separate performance obligation, and recognizes these costs as an operating expense in the period when revenue for the related commodity is recognized. Revenue is measured as the amount the company expects to receive in exchange for transferring commodities to the customer. The company’s commodity sales are typically based on prevailing market-based prices and may include discounts and allowances. Until market prices become known under terms of the company’s contracts, the transaction price included in revenue is based on the company’s estimate of the most likely outcome. Discounts and allowances are estimated using a combination of historical and recent data trends. When deliveries contain multiple products, an observable standalone selling price is generally used to measure revenue for each product. The company includes estimates in the transaction price only to the extent that a significant reversal of revenue is not probable in subsequent periods. Stock Options and Other Share-Based Compensation The company issues stock options and other share-based compensation to certain employees. For equity awards, such as stock options and certain restricted stock units, total compensation cost is based on the grant date fair value, and for liability awards, such as stock appreciation rights, total compensation cost is based on the settlement value. The company recognizes stock-based compensation expense for all awards over the service period required to earn the award, which is the shorter of the vesting period or the time period in which an employee becomes eligible to retain the award at retirement. The company’s Long-Term Incentive Plan (LTIP) awards include stock options and stock appreciation rights, which have graded vesting provisions by which one-third of each award vests on each of the first, second and third anniversaries of the date of grant. In addition, performance shares granted under the company’s LTIP will vest at the end of the three-year performance period. For awards granted under the company’s LTIP beginning in 2017, stock options and stock appreciation rights have graded vesting by which one-third of each award vests annually on each January 31 on or after the first anniversary of the grant date. Special restricted stock unit awards have cliff vesting by which the total award will vest on January 31 on or after the third anniversary of the grant date. Standard restricted stock unit awards have cliff vesting by which the total award will vest on January 31 on or after 69 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts the fifth anniversary of the grant date, subject to adjustment upon termination pursuant to the satisfaction of certain criteria. Commencing for grants issued in January 2023 and after, standard restricted stock units vest ratably on an annual basis over a three-year period. The company amortizes these awards on a straight-line basis. Note 2 Changes in Accumulated Other Comprehensive Losses The change in Accumulated Other Comprehensive Losses (AOCL) presented on the Consolidated Balance Sheet and the impact of significant amounts reclassified from AOCL on information presented in the Consolidated Statement of Income for the year ended December 31, 2023, are reflected in the table below. Currency Translation Adjustments Unrealized Holding Gains (Losses) on Securities Derivatives Defined Benefit Plans Total Balance at December 31, 2020 $ ( 107 ) $ ( 10 ) $ — $ ( 5,495 ) $ ( 5,612 ) Components of Other Comprehensive Income (Loss) 1 : Before Reclassifications ( 55 ) ( 1 ) ( 6 ) 949 887 Reclassifications 2,3 — — 6 830 836 Net Other Comprehensive Income (Loss) ( 55 ) ( 1 ) — 1,779 1,723 Balance at December 31, 2021 $ ( 162 ) $ ( 11 ) $ — $ ( 3,716 ) $ ( 3,889 ) Components of Other Comprehensive Income (Loss) 1 : Before Reclassifications ( 41 ) ( 1 ) 68 703 729 Reclassifications 2, 3 — — ( 80 ) 442 362 Net Other Comprehensive Income (Loss) ( 41 ) ( 1 ) ( 12 ) 1,145 1,091 Balance at December 31, 2022 $ ( 203 ) $ ( 12 ) $ ( 12 ) $ ( 2,571 ) $ ( 2,798 ) Components of Other Comprehensive Income (Loss) 1 : Before Reclassifications 11 1 ( 16 ) ( 397 ) ( 401 ) Reclassifications 2, 3 — — 33 206 239 Net Other Comprehensive Income (Loss) 11 1 17 ( 191 ) ( 162 ) Balance at December 31, 2023 $ ( 192 ) $ ( 11 ) $ 5 $ ( 2,762 ) $ ( 2,960 ) 1 All amounts are net of tax. 2 Refer to Note 23 Employee Benefit Plans , for reclassified components, including amortization of actuarial gains or losses, amortization of prior service costs and settlement losses, totaling $ 231 that are included in employee benefit costs for the year ended December 31, 2023. Related income taxes for the same period, totaling $ 25 , are reflected in Income Tax Expense on the Consolidated Statement of Income. All other reclassified amounts were insignificant. 3 Refer to Note 10 Financial and Derivative Instruments for cash flow hedging. 70 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Note 3 Information Relating to the Consolidated Statement of Cash Flows Year ended December 31 2023 2022 2021 Distributions more (less) than income from equity affiliates includes the following: Distributions from equity affiliates $ 4,246 $ 3,855 $ 3,659 (Income) loss from equity affiliates ( 5,131 ) ( 8,585 ) ( 5,657 ) Distributions more (less) than income from equity affiliates $ ( 885 ) $ ( 4,730 ) $ ( 1,998 ) Net decrease (increase) in operating working capital was composed of the following: Decrease (increase) in accounts and notes receivable $ 1,187 $ ( 2,317 ) $ ( 7,548 ) Decrease (increase) in inventories ( 320 ) ( 930 ) ( 530 ) Decrease (increase) in prepaid expenses and other current assets ( 1,202 ) ( 226 ) 19 Increase (decrease) in accounts payable and accrued liabilities ( 49 ) 2,750 5,475 Increase (decrease) in income and other taxes payable ( 2,801 ) 2,848 1,223 Net decrease (increase) in operating working capital $ ( 3,185 ) $ 2,125 $ ( 1,361 ) Net cash provided by operating activities includes the following cash payments: Interest on debt (net of capitalized interest) $ 465 $ 525 $ 699 Income taxes 10,416 9,148 4,355 Proceeds and deposits related to asset sales and returns of investment consisted of the following gross amounts: Proceeds and deposits related to asset sales $ 446 $ 1,435 $ 1,352 Returns of investment from equity affiliates 223 1,200 439 Proceeds and deposits related to asset sales and returns of investment $ 669 $ 2,635 $ 1,791 Net sales (purchases) of marketable securities consisted of the following gross amounts: Marketable securities purchased $ ( 289 ) $ ( 7 ) $ ( 4 ) Marketable securities sold 464 124 3 Net sales (purchases) of marketable securities $ 175 $ 117 $ ( 1 ) Net repayment (borrowing) of loans by equity affiliates: Borrowing of loans by equity affiliates $ ( 368 ) $ ( 108 ) $ — Repayment of loans by equity affiliates 66 84 401 Net repayment (borrowing) of loans by equity affiliates $ ( 302 ) $ ( 24 ) $ 401 Net borrowings (repayments) of short-term obligations consisted of the following gross and net amounts: 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 ) Net borrowings (repayments) of short-term obligations $ 135 $ 263 $ ( 5,572 ) Net sales (purchases) of treasury shares consists of the following gross and net amounts: Shares issued for share-based compensation plans $ 261 $ 5,838 $ 1,421 Shares purchased under share repurchase and deferred compensation plans ( 14,939 ) ( 11,255 ) ( 1,383 ) Net sales (purchases) of treasury shares $ ( 14,678 ) $ ( 5,417 ) $ 38 Net contributions from (distributions to) noncontrolling interests consisted of the following gross and net amounts: Distributions to noncontrolling interests $ ( 54 ) $ ( 118 ) $ ( 53 ) Contributions from noncontrolling interests 14 4 17 Net contributions from (distributions to) noncontrolling interests $ ( 40 ) $ ( 114 ) $ ( 36 ) The “Other” line in the Operating Activities section includes changes in postretirement benefits obligations and other long-term liabilities. The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash. “Depreciation, depletion and amortization” and “Deferred income tax provision” collectively include approximately $ 1,765 in non-cash reductions to “Properties, plant and equipment” and “Investments and advances” in 2023 relating to impairments, mainly of upstream assets in California. “Other income (loss)” and “Deferred income tax provision” collectively include a $ 1,950 charge related to non-cash increases to “Deferred credits and other noncurrent obligations” related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S. Gulf of Mexico. The cash outlays for these abandonment and decommissioning obligations are expected to take place over the next decade. 71 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Refer also to Note 25 Asset Retirement Obligations for a discussion of revisions to the company’s AROs that also did not involve cash receipts or payments for the three years ending December 31, 2023. The components of “Capital expenditures” are presented in the following table: Year ended December 31 2023 2022 2021 Additions to properties, plant and equipment * $ 14,788 $ 10,349 $ 7,515 Additions to investments 690 1,147 460 Current-year dry hole expenditures 326 309 83 Payments for other assets and liabilities, net 25 169 ( 2 ) Capital expenditures $ 15,829 $ 11,974 $ 8,056 * Excludes non-cash movements of $ 1,559 in 2023, $ 334 in 2022 and $ 316 in 2021. The table below quantifies the beginning and ending balances of restricted cash and restricted cash equivalents in the Consolidated Balance Sheet: Year ended December 31 2023 2022 2021 Cash and cash equivalents $ 8,178 $ 17,678 $ 5,640 Restricted cash included in “Prepaid expenses and other current assets” 275 630 333 Restricted cash included in “Deferred charges and other assets” 822 813 822 Total cash, cash equivalents and restricted cash $ 9,275 $ 19,121 $ 6,795 Note 4 New Accounting Standards Segment Reporting (Topic 280) Improvements to Reportable Segment Disclosures In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) 2023-07, which becomes effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. 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. Note 5 Lease Commitments The company enters into leasing arrangements as a lessee; any lessor arrangements are not significant. Operating lease arrangements mainly involve land, bareboat charters, terminals, drill ships, drilling rigs, time chartered vessels, office buildings and warehouses, and exploration and production equipment. Finance leases primarily include facilities, vessels and office buildings. Details of the right-of-use assets and lease liabilities for operating and finance leases, including the balance sheet presentation, are as follows: 72 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts At December 31, 2023 At December 31, 2022 Operating Leases Finance Leases Operating Leases Finance Leases Deferred charges and other assets $ 5,422 $ — $ 4,262 $ — Properties, plant and equipment, net — 583 — 392 Right-of-use assets* $ 5,422 $ 583 $ 4,262 $ 392 Accrued Liabilities $ 1,538 $ — $ 1,111 $ — Short-term Debt — 60 — 45 Current lease liabilities 1,538 60 1,111 45 Deferred credits and other noncurrent obligations 3,696 — 2,920 — Long-term Debt — 574 — 403 Noncurrent lease liabilities 3,696 574 2,920 403 Total lease liabilities $ 5,234 $ 634 $ 4,031 $ 448 Weighted-average remaining lease term (in years) 6.7 12.6 7.0 11.9 Weighted-average discount rate 3.3 % 4.5 % 1.9 % 4.1 % * Includes non-cash additions of $ 2,556 and $ 233 in 2023, and $ 1,807 and $ 3 in 2022 for right-of-use assets obtained in exchange for new and modified lease liabilities for operating and finance leases, respectively. Total lease costs consist of both amounts recognized in the Consolidated Statement of Income during the period and amounts capitalized as part of the cost of another asset. Total lease costs incurred for operating and finance leases were as follows: Year-ended December 31 2023 2022 2021 Operating lease costs* $ 2,984 $ 2,359 $ 2,199 Finance lease costs 52 57 66 Total lease costs $ 3,036 $ 2,416 $ 2,265 * Includes variable and short-term lease costs. Cash paid for amounts included in the measurement of lease liabilities was as follows: Year-ended December 31 2023 2022 2021 Operating cash flows from operating leases $ 2,271 $ 1,892 $ 1,670 Investing cash flows from operating leases 713 467 398 Operating cash flows from finance leases 15 18 21 Financing cash flows from finance leases 42 44 193 At December 31, 2023, the estimated future undiscounted cash flows for operating and finance leases were as follows: At December 31, 2023 Operating Leases Finance Leases Year 2024 $ 1,673 $ 84 2025 1,153 79 2026 734 76 2027 544 68 2028 396 66 Thereafter 1,364 443 Total $ 5,864 $ 816 Less: Amounts representing interest 630 182 Total lease liabilities $ 5,234 $ 634 Additionally, the company has $ 232 in future undiscounted cash flows for operating leases not yet commenced. These leases are primarily for drill ships, drilling rigs and storage tanks. For those leasing arrangements where the underlying asset is not yet constructed, the lessor is primarily involved in the design and construction of the asset. 73 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Note 6 Summarized Financial Data – Chevron U.S.A. Inc. Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron Corporation. CUSA and its subsidiaries manage and operate most of Chevron’s U.S. businesses. Assets include those related to the exploration and production of crude oil, natural gas liquids and natural gas and those associated with the refining, marketing, supply and distribution of products derived from petroleum, excluding most of the regulated pipeline operations of Chevron. CUSA also holds the company’s investment in the Chevron Phillips Chemical Company LLC joint venture, which is accounted for using the equity method. The summarized financial information for CUSA and its consolidated subsidiaries is as follows: Year ended December 31 2023 2022 2021 Sales and other operating revenues $ 152,347 $ 183,032 $ 120,380 Total costs and other deductions 144,482 166,955 114,641 Net income (loss) attributable to CUSA 4,598 13,315 6,904 At December 31 2023 2022 Current assets $ 19,489 $ 18,704 Other assets 54,460 50,153 Current liabilities 20,624 22,452 Other liabilities 22,227 19,274 Total CUSA net equity $ 31,098 $ 27,131 Memo: Total debt $ 9,740 $ 10,800 Note 7 Summarized Financial Data – Tengizchevroil LLP Chevron has a 50 percent equity ownership interest in Tengizchevroil LLP (TCO). Refer to Note 15 Investments and Advances for a discussion of TCO operations. Summarized financial information for 100 percent of TCO is presented in the table below: Year ended December 31 2023 2022 2021 Sales and other operating revenues $ 19,578 $ 23,795 $ 15,927 Costs and other deductions 10,193 11,596 8,186 Net income attributable to TCO 6,569 8,566 5,418 At December 31 2023 2022 Current assets $ 3,919 $ 6,522 Other assets 57,454 54,506 Current liabilities 2,372 3,567 Other liabilities 12,782 12,312 Total TCO net equity $ 46,219 $ 45,149 Note 8 Summarized Financial Data – Chevron Phillips Chemical Company LLC Chevron has a 50 percent equity ownership interest in Chevron Phillips Chemical Company LLC (CPChem). Refer to Note 15 Investments and Advances for a discussion of CPChem operations. Summarized financial information for 100 percent of CPChem is presented in the table below: Year ended December 31 2023 2022 2021 Sales and other operating revenues $ 11,560 $ 14,180 $ 14,104 Costs and other deductions 10,561 12,870 10,862 Net income attributable to CPChem 1,173 1,662 3,684 74 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts At December 31 2023 2022 Current assets $ 3,284 $ 3,472 Other assets 16,425 15,184 Current liabilities 1,757 2,146 Other liabilities 3,269 2,941 Total CPChem net equity $ 14,683 $ 13,569 Note 9 Fair Value Measurements The tables below show the fair value hierarchy for assets and liabilities measured at fair value on a recurring and nonrecurring basis at December 31, 2023 and 2022. Marketable Securities The company calculates fair value for its marketable securities based on quoted market prices for identical assets. 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 amount to the Consolidated Statement of Income. The company designates certain derivative instruments as cash flow hedges that, if applicable, are reflected in the table below. Derivatives classified as Level 1 include futures, swaps and options contracts valued using quoted prices from active markets such as the New York Mercantile Exchange. Derivatives classified as Level 2 include swaps, options and forward contracts, the fair values of which are obtained from third-party broker quotes, industry pricing services and exchanges. The company obtains multiple sources of pricing information for the Level 2 instruments. Since this pricing information is generated from observable market data, it has historically been very consistent. The company does not materially adjust this information. 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. Assets and Liabilities Measured at Fair Value on a Recurring Basis At December 31, 2023 At December 31, 2022 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Marketable securities $ 45 $ 45 $ — $ — $ 223 $ 223 $ — $ — Derivatives - not designated 152 24 128 — 184 111 73 — Derivatives - designated 7 7 — — — — — — Total assets at fair value $ 204 $ 76 $ 128 $ — $ 407 $ 334 $ 73 $ — Derivatives - not designated 262 160 102 — 43 33 10 — Derivatives - designated — — — — 15 15 — — Total liabilities at fair value $ 262 $ 160 $ 102 $ — $ 58 $ 48 $ 10 $ — Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis At December 31 At December 31 Before-Tax Loss Before-Tax Loss Total Level 1 Level 2 Level 3 Year 2023 Total Level 1 Level 2 Level 3 Year 2022 Properties, plant and equipment, net (held and used) $ 484 $ — $ — $ 484 $ 2,175 $ 54 $ — $ — $ 54 $ 518 Properties, plant and equipment, net (held for sale) — — — — 5 — — — — 432 Investments and advances 207 5 165 37 352 33 2 — 31 9 Total nonrecurring assets at fair value $ 691 $ 5 $ 165 $ 521 $ 2,532 $ 87 $ 2 $ — $ 85 $ 959 At year-end 2023, the company had assets measured at fair value Level 3 using unobservable inputs of $ 521 . The carrying value of these assets were written down to fair value based on estimates derived from discounted cash flow models. Cash 75 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts flows were determined using estimates of future production, an outlook of future price based on published prices and a discount rate believed to be consistent with those used by principal market participants. Assets and Liabilities Not Required to Be Measured at Fair Value The company holds cash equivalents in U.S. and non-U.S. portfolios. The instruments classified as cash equivalents are primarily bank time deposits with maturities of 90 days or less and money market funds. “Cash and cash equivalents” had carrying/fair values of $ 8,178 and $ 17,678 at December 31, 2023, and December 31, 2022, respectively. The fair values of cash and cash equivalents are classified as Level 1 and reflect the cash that would have been received if the instruments were settled at December 31, 2023. “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, 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. Long-term debt primarily includes corporate issued bonds. The fair value of corporate bonds is $ 13,321 and classified as Level 1. The fair value of other long-term debt classified as Level 2 is $ 388 . The carrying values of other short-term financial assets and liabilities on the Consolidated Balance Sheet approximate their fair values. Fair value remeasurements of other financial instruments at December 31, 2023 and 2022, were not material. Note 10 Financial and Derivative Instruments Derivative Commodity Instruments The company’s derivative commodity instruments principally include crude oil, natural gas, liquefied natural gas and refined product futures, swaps, options, and forward contracts. The company applies cash flow hedge accounting to certain commodity transactions, where appropriate, to manage the market price risk associated with forecasted sales of crude oil. The company’s derivatives are not material to the company’s financial position, results of operations or liquidity. The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodity derivative activities. The company uses derivative commodity instruments traded on the New York Mercantile Exchange and on electronic platforms of the Inter-Continental Exchange and Chicago Mercantile Exchange. In addition, the company enters into swap contracts and option contracts principally with major financial institutions and other oil and gas companies in the “over-the-counter” markets, which are governed by International Swaps and Derivatives Association agreements and other master netting arrangements. Depending on the nature of the derivative transactions, bilateral collateral arrangements may also be required. 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: Fair Value of Derivatives At December 31 Type of Contract Balance Sheet Classification 2023 2022 Commodity Accounts and notes receivable $ 151 $ 175 Commodity Long-term receivables, net 8 9 Total assets at fair value $ 159 $ 184 Commodity Accounts payable $ 216 $ 46 Commodity Deferred credits and other noncurrent obligations 46 12 Total liabilities at fair value $ 262 $ 58 Consolidated Statement of Income: The Effect of Derivatives Gain/(Loss) Type of Derivative Statement of Year ended December 31 Contract Income Classification 2023 2022 2021 Commodity Sales and other operating revenues $ ( 304 ) $ ( 651 ) $ ( 685 ) Commodity Purchased crude oil and products ( 154 ) ( 226 ) ( 64 ) Commodity Other income (loss) ( 47 ) 10 ( 46 ) $ ( 505 ) $ ( 867 ) $ ( 795 ) 76 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts The amount reclassified from AOCL to “Sales and other operating revenues” from designated hedges was a decrease of $ 33 in 2023, compared with an increase of $ 80 in the prior year. At December 31, 2023, before-tax deferred gains in AOCL related to outstanding crude oil price hedging contracts were $ 7 , all of which is expected to be reclassified into earnings during the next 12 months as the hedged crude oil sales are recognized in earnings. The 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. Consolidated Balance Sheet: The Effect of Netting Derivative Assets and Liabilities Gross Amounts Recognized Gross Amounts Offset Net Amounts Presented Gross Amounts Not Offset Net Amounts At December 31, 2023 Derivative Assets - not designated $ 2,394 $ 2,242 $ 152 $ 4 $ 148 Derivative Assets - designated $ 8 $ 1 $ 7 $ — $ 7 Derivative Liabilities - not designated $ 2,504 $ 2,242 $ 262 $ 15 $ 247 Derivative Liabilities - designated $ 1 $ 1 $ — $ — $ — At December 31, 2022 Derivative Assets - not designated $ 2,591 $ 2,407 $ 184 $ 5 $ 179 Derivative Assets - designated $ 8 $ 8 $ — $ — $ — Derivative Liabilities - not designated $ 2,450 $ 2,407 $ 43 $ — $ 43 Derivative Liabilities - designated $ 23 $ 8 $ 15 $ — $ 15 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. The company’s short-term investments are placed with a wide array of financial institutions with high credit ratings. Company investment policies limit the company’s exposure both to credit risk and to concentrations of credit risk. Similar policies on diversification and creditworthiness are applied to the company’s counterparties in derivative instruments. For a discussion of credit risk on trade receivables, see Note 28 Financial Instruments - Credit Losses . Note 11 Assets Held for Sale At December 31, 2023, the company classifie d $ 675 of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. These assets are associated with upstream operations that are anticipated to be sold in the next 12 months. The revenues and earnings contributions of these assets in 2023 were not material. Note 12 Equity Retained earnings at December 31, 2023 and 2022, included $ 34,359 and $ 33,570 , respectively, for the company’s share of undistributed earnings of equity affiliates. At December 31, 2023, about 101 million shares of Chevron’s common stock remained available for issuance from the 104 million shares that were reserved for issuance under the 2022 Chevron Long-Term Incentive Plan. In addition, 578,044 shares remain available for issuance from the 1,600,000 shares of the company’s common stock that were reserved for awards under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan. Note 13 Earnings Per Share Basic earnings per share (EPS) is based upon “Net Income (Loss) Attributable to Chevron Corporation” (“earnings”) and includes the effects of deferrals of salary and other compensation awards that are invested in Chevron stock units by certain officers and employees of the company. Diluted EPS includes the effects of these items as well as the dilutive effects of outstanding stock options awarded under the company’s stock option programs (refer to Note 22 Stock Options and Other Share-Based Compensation ). The table below sets forth the computation of basic and diluted EPS: 77 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Year ended December 31 2023 2022 2021 Basic EPS Calculation Earnings available to common stockholders - Basic * $ 21,369 $ 35,465 $ 15,625 Weighted-average number of common shares outstanding 1,873 1,931 1,916 Add: Deferred awards held as stock units — — — Total weighted-average number of common shares outstanding 1,873 1,931 1,916 Earnings per share of common stock - Basic $ 11.41 $ 18.36 $ 8.15 Diluted EPS Calculation Earnings available to common stockholders - Diluted * $ 21,369 $ 35,465 $ 15,625 Weighted-average number of common shares outstanding 1,873 1,931 1,916 Add: Deferred awards held as stock units — — — Add: Dilutive effect of employee stock-based awards 7 9 4 Total weighted-average number of common shares outstanding 1,880 1,940 1,920 Earnings per share of common stock - Diluted $ 11.36 $ 18.28 $ 8.14 * There was no effect of dividend equivalents paid on stock units or dilutive impact of employee stock-based awards on earnings. Note 14 Operating Segments and Geographic Data Although each subsidiary of Chevron is responsible for its own affairs, Chevron Corporation manages its investments in these subsidiaries and their affiliates. The investments are grouped into two business segments, Upstream and Downstream, representing the company’s “reportable segments” and “operating segments.” Upstream operations consist primarily of exploring for, developing, producing and transporting crude oil and natural gas; liquefaction, transportation and regasification associated with liquefied natural gas (LNG); transporting crude oil by major international oil export pipelines; processing, transporting, storage and marketing of natural gas; carbon capture and storage; and a gas-to-liquids plant. Downstream operations consist primarily of refining of crude oil into petroleum products; marketing of crude oil, refined products, and lubricants; manufacturing and marketing of renewable fuels; transporting of crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant additives. All Other activities of the company include worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology activities. The company’s segments are managed by “segment managers” who report to the “chief operating decision maker” (CODM). The segments represent components of the company that engage in activities (a) from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the segments and assesses their performance; and (c) for which discrete financial information is available. The company’s primary country of operation is the United States of America, its country of domicile. Other components of the company’s operations are reported as “International” (outside the United States). Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Non-billable costs remain at the corporate level in “All Other.” Earnings by major operating area are presented in the following table: 78 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Year ended December 31 2023 2022 2021 Upstream United States $ 4,148 $ 12,621 $ 7,319 International 13,290 17,663 8,499 Total Upstream 17,438 30,284 15,818 Downstream United States 3,904 5,394 2,389 International 2,233 2,761 525 Total Downstream 6,137 8,155 2,914 Total Segment Earnings 23,575 38,439 18,732 All Other Interest expense ( 432 ) ( 476 ) ( 662 ) Interest income 491 261 36 Other ( 2,265 ) ( 2,759 ) ( 2,481 ) Net Income (Loss) Attributable to Chevron Corporation $ 21,369 $ 35,465 $ 15,625 Segment Assets Segment assets do not include intercompany investments or receivables. Assets at year-end 2023 and 2022 are as follows: At December 31 2023 2022 Upstream United States $ 58,750 $ 44,246 International 131,685 134,489 Goodwill 4,370 4,370 Total Upstream 194,805 183,105 Downstream United States 33,066 31,676 International 21,070 21,193 Goodwill 352 352 Total Downstream 54,488 53,221 Total Segment Assets 249,293 236,326 All Other United States 10,292 17,861 International 2,047 3,522 Total All Other 12,339 21,383 Total Assets – United States 102,108 93,783 Total Assets – International 154,802 159,204 Goodwill 4,722 4,722 Total Assets $ 261,632 $ 257,709 Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2023, 2022 and 2021, are presented in the table on the next page. Products are transferred between operating segments at internal product values that approximate market prices. Revenues for the upstream segment are derived primarily from the production and sale of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the manufacture and sale of fuel and lubricant additives and the transportation and trading of refined products and crude oil. “All Other” activities include revenues from insurance operations, real estate activities and technology companies. 79 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Year ended December 31 * 2023 2022 2021 Upstream United States $ 40,115 $ 50,822 $ 29,219 International 43,805 56,156 40,921 Subtotal 83,920 106,978 70,140 Intersegment Elimination — United States ( 26,307 ) ( 29,870 ) ( 15,154 ) Intersegment Elimination — International ( 11,871 ) ( 13,815 ) ( 10,994 ) Total Upstream 45,742 63,293 43,992 Downstream United States 83,567 91,824 57,209 International 78,058 87,741 58,098 Subtotal 161,625 179,565 115,307 Intersegment Elimination — United States ( 8,793 ) ( 5,529 ) ( 2,296 ) Intersegment Elimination — International ( 1,794 ) ( 1,728 ) ( 1,521 ) Total Downstream 151,038 172,308 111,490 All Other United States 595 515 506 International 2 3 2 Subtotal 597 518 508 Intersegment Elimination — United States ( 462 ) ( 400 ) ( 382 ) Intersegment Elimination — International ( 2 ) ( 2 ) ( 2 ) Total All Other 133 116 124 Sales and Other Operating Revenues United States 124,277 143,161 86,934 International 121,865 143,900 99,021 Subtotal 246,142 287,061 185,955 Intersegment Elimination — United States ( 35,562 ) ( 35,799 ) ( 17,832 ) Intersegment Elimination — International ( 13,667 ) ( 15,545 ) ( 12,517 ) Total Sales and Other Operating Revenues $ 196,913 $ 235,717 $ 155,606 * Other than the United States, no other country accounted for 10 percent or more of the company’s Sales and Other Operating Revenues. Segment Income Taxes Segment income tax expense for the years 2023, 2022 and 2021 is as follows: Year ended December 31 2023 2022 2021 Upstream United States $ 1,141 $ 3,678 $ 1,934 International 5,733 9,055 4,192 Total Upstream 6,874 12,733 6,126 Downstream United States 1,109 1,515 547 International 519 280 203 Total Downstream 1,628 1,795 750 All Other ( 329 ) ( 462 ) ( 926 ) Total Income Tax Expense (Benefit) $ 8,173 $ 14,066 $ 5,950 Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 15 Investments and Advances . Information related to properties, plant and equipment by segment is contained in Note 18 Properties, Plant and Equipment . 80 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Note 15 Investments and Advances Equity in earnings, together with investments in and advances to companies accounted for using the equity method and other investments accounted for at or below cost, is shown in the following table. For certain equity affiliates, Chevron pays its share of some income taxes directly. For such affiliates, the equity in earnings does not include these taxes, which are reported on the Consolidated Statement of Income as “Income tax expense.” Investments and Advances Equity in Earnings At December 31 Year ended December 31 2023 2022 2023 2022 2021 Upstream Tengizchevroil $ 26,954 $ 26,534 $ 3,375 $ 4,386 $ 2,831 Caspian Pipeline Consortium 797 761 158 128 155 Angola LNG Limited 1,762 1,963 513 1,857 336 Other 2,106 1,938 ( 161 ) 255 187 Total Upstream 31,619 31,196 3,885 6,626 3,509 Downstream Chevron Phillips Chemical Company LLC 7,765 6,843 608 867 1,842 GS Caltex Corporation 4,309 4,288 437 874 85 Other 2,426 2,288 210 224 220 Total Downstream 14,500 13,419 1,255 1,965 2,147 All Other Other ( 6 ) ( 5 ) ( 9 ) ( 6 ) 1 Total equity method $ 46,113 $ 44,610 $ 5,131 $ 8,585 $ 5,657 Other non-equity method investments 699 628 Total investments and advances $ 46,812 $ 45,238 Total United States $ 10,985 $ 9,855 $ 340 $ 975 $ 1,889 Total International $ 35,827 $ 35,383 $ 4,791 $ 7,610 $ 3,768 Descriptions of major equity affiliates and non-equity investments, including significant differences between the company’s carrying value of its investments and its underlying equity in the net assets of the affiliates, are as follows: Tengizchevroil Chevron has a 50 percent equity ownership interest in Tengizchevroil (TCO), which operates the Tengiz and Korolev crude oil fields in Kazakhstan. At December 31, 2023, the company’s carrying value of its investment in TCO was about $ 80 higher than the amount of underlying equity in TCO’s net assets. This difference results from Chevron acquiring a portion of its interest in TCO at a value greater than the underlying book value for that portion of TCO’s net assets. Included in the investment is a loan to TCO to fund the development of the FGP/WPMP with a principal balance of $ 4,500 . 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. Angola LNG Limited Chevron has a 36.4 percent interest in Angola LNG Limited, which processes and liquefies natural gas produced in Angola for delivery to international markets. Chevron Phillips Chemical Company LLC Chevron owns 50 percent of Chevron Phillips Chemical Company LLC. 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. 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 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. “Accounts and notes receivable” on the Consolidated Balance Sheet includes $ 1,480 and $ 907 due from affiliated companies at December 31, 2023 and 2022, respectively. “Accounts payable” includes $ 591 and $ 709 due to affiliated companies at December 31, 2023 and 2022, respectively. 81 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts The following table provides summarized financial information on a 100 percent basis for all equity affiliates as well as Chevron’s total share, which includes Chevron’s net loans to affiliates of $ 4,494 , $ 4,278 and $ 4,704 at December 31, 2023, 2022 and 2021, respectively. Affiliates Chevron Share Year ended December 31 2023 2022 2021 2023 2022 2021 Total revenues $ 49,306 $ 100,184 $ 71,241 $ 23,217 $ 48,323 $ 34,359 Income before income tax expense* 15,304 23,811 15,175 7,209 10,876 6,984 Net income attributable to affiliates 11,618 19,077 12,598 5,485 8,595 5,670 At December 31 Current assets $ 22,772 $ 26,632 $ 21,871 $ 10,110 $ 11,671 $ 9,267 Noncurrent assets 105,965 101,557 100,235 48,753 46,428 44,360 Current liabilities 14,085 16,319 17,275 6,698 7,708 7,492 Noncurrent liabilities 23,797 22,943 24,219 6,342 5,980 5,982 Total affiliates’ net equity $ 90,855 $ 88,927 $ 80,612 $ 45,823 $ 44,411 $ 40,153 * Chevron’s net income attributable to affiliates is recorded in the company’s before-tax consolidated earnings in accordance with U.S. Generally Accepted Accounting Principles. The total income tax expense recorded by the company’s equity affiliates in 2023 was $ 3,686 , with Chevron’s share being $ 1,724 . Note 16 Litigation Ecuador In 2003, Chevron was sued in Ecuador for environmental harm allegedly caused by an oil consortium formerly operated by a Texaco subsidiary. The Ecuadorian trial court entered judgment against Chevron, and Ecuador’s highest Constitutional Court affirmed the judgment for approximately $ 9.5 billion. In 2017, Chevron obtained a final court ruling in the United States determining that the Ecuadorian judgment had been procured through fraud, bribery, and corruption, and prohibiting the Ecuadorian plaintiffs and their cohorts from seeking to enforce the Ecuadorian judgment in the United States or profiting from their illegal acts. The Ecuadorian plaintiffs sought to have the Ecuadorian judgment recognized and enforced in Canada, Brazil, and Argentina, but all of those actions were dismissed in Chevron’s favor. In 2009, Chevron filed an arbitration claim against Ecuador before an arbitral tribunal administered by the Permanent Court of Arbitration in The Hague, under the United States-Ecuador Bilateral Investment Treaty. In 2018, the tribunal ruled in Chevron’s favor, finding that the Ecuadorian judgment was procured through fraud, bribery, and corruption and was based on environmental claims that Ecuador had already settled and released. The tribunal ruled that the Ecuadorian judgment “violates international public policy” and “should not be recognized or enforced by the courts of other States,” and ordered Ecuador to remove the judgment’s status of enforceability and to compensate Chevron for its injuries in an amount to be established separately by the tribunal. Ecuador’s requests to have a Dutch court set aside the tribunal’s award were denied, and the Dutch Supreme Court affirmed such denial in a final ruling in favor of Chevron in November 2023. Management continues to believe that the Ecuadorian judgment is illegitimate and unenforceable and will vigorously defend against any further attempts to have it recognized or enforced. 82 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Climate Change Governmental and other entities in various jurisdictions across the United States have brought legal proceedings against fossil fuel producing companies, including Chevron entities, purporting to seek legal and equitable relief to address alleged impacts of climate change. 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: Bayamon v. Exxon Mobil Corp., et al. , No. 22-cv-1550 (D.P.R.); City of Annapolis v. BP P.L.C., et al. , No. C-02-CV-21-000250 (Md. Cir. Ct.); County of Anne Arundel v. BP P.L.C., et al. , No. C-02-CV-21-000565 (Md. Cir. Ct.); Mayor and City Council of Baltimore v. BP P.L.C., et al. , No. 24-C-18-004219 (Md. Cir. Ct.); People ex rel. Bonta v. Exxon Mobil Corp., et al. , No. CGC-23-609134 (Cal. Super. Ct.); City of Charleston v. Brabham Oil Co., et al. , No. 20-CP-10-3975 (S.C. Ct. of Common Pleas); District of Columbia v. Exxon Mobil Corp., et al. , No. 2020-CA-002892-B (D.C. Super. Ct.); Delaware ex rel. Jennings v. BP America Inc., et al. , No. N20C-09-097 (Del.Super. Ct.); City of Hoboken v. Exxon Mobil Corp., et al. , No. HUD-L-003179-20 (N.J. Super. Ct.); City and County of Honolulu, et al. v. Sunoco LP, et al. , No. 1CCV-20-0000380 (Haw. Cir. Ct.); City of Imperial Beach v. Chevron Corp., et al. , No. C17-01227 (Cal. Super. Ct.); King County v. BP P.L.C. , et al., No. 18-2-11859-0 (Wash. Super. Ct.) (voluntarily dismissed); Makah Indian Tribe v. Exxon Mobil Corp., et al. , No. 23-25216-1-SEA (Wash. Super. Ct.); County of Marin v. Chevron Corp., et al. , No. 17-cv-02586 (Cal. Super. Ct.); County of Maui v. Sunoco LP, et al. , No. 2CCV-20-0000283 (Haw. Cir. Ct.); County of Multnomah v. Exxon Mobil Corp., et al. , No. 23-cv-25164 (Or. Cir. Ct.); Municipality of San Juan, Puerto Rico v. Exxon Mobil Corp., et al. , No. 23-cv-01608 (D.P.R.); City of Oakland v. BP p.l.c., et al. , No. RG17875889 (Cal. Super. Ct.); Platkin, et al. v. Exxon Mobil Corp., et al. , No. MER-L-001797-22 (N.J. Super. Ct.); City of New York v. Chevron Corp., et al. , No. 18-cv-00182 (S.D.N.Y.) (dismissed on the merits); Pacific Coast Federation of Fishermen’s Associations v. Chevron Corp., et al. , No. CGC-18-571285 (Cal. Super. Ct.) (voluntarily dismissed); State of Rhode Island v. Chevron Corp., et al ., No. PC-2018-4716 (R.I. Super. Ct.); City of Richmond v. Chevron Corp., et al. , No. C18-00055 (Cal. Super. Ct.); City of San Francisco v. BP P.L.C., et al. , No. CGC-17-561370 (Cal. Super. Ct.); County of San Mateo v. Chevron Corp., et al. , No. 17-CIV-03222 (Cal. Super. Ct.); City of Santa Cruz v. Chevron Corp., et al. , No. 17-cv-03243 (Cal. Super. Ct.); County of Santa Cruz v. Chevron Corp., et al ., No. 17-cv-03242 (Cal. Super. Ct.); Shoalwater Bay Indian Tribe v. Exxon Mobil Corp., et al. , No. 23-2-25215-2-SEA (Wash. Super. Ct.); City of Chicago v. BP p.l.c., et al. , No. 2024-CH-01024 (Ill. Cir. Ct.) . 83 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Louisiana 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). Chevron entities are defendants in 39 of these cases. 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. 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. 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 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. Dist. Ct., Jefferson Par.); Jefferson Parish v. Chevron U.S.A. Holdings, Inc., et al. , No. 732-769 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Destin Operating Company, Inc., et al . , No. 732-770 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Canlan Oil Company, et al. , No. 732-771 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Anadarko E&P Onshore LLC, et al. , No. 732-772 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. ExxonMobil Corporation, et al. , No. 732-774 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Equitable Petroleum Corporation, et al., No. 732-775 (24th Jud. Dist. Ct., Jefferson Par.); Plaquemines Parish v. ConocoPhillips Co., et al. , No. 60-982 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. HHE Energy Co., et al. , No. 60-983 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Exchange Oil & Gas Corp. , et al. , No. 60-984 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. LLOG Exploration & Production Co. , et al. , No. 60-985 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Equitable Petroleum Corporation, et al. , No. 60-986 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. June Energy, et al. , No. 60-987 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Linder Oil Company, et al. , No. 60-988 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Riverwood Production Company, et al. , No. 60-989 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Helis Oil & Gas Company, et al ., No. 60-990 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Northcoast Oil Company, et al. , No. 60-992 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Goodrich Petroleum Company, L.L.C., et al. , No. 60-994 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Devon Energy Production Company, L.P., et al. , No. 60-995 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Rozel Operating Co., et al. , No. 60-996 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Palm Energy Offshore, L.L.C., et al. , No. 60-997 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Great Southern Oil & Gas Company, Inc., et al. , No. 60-998 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Hilcorp Energy Company, et al. , No. 60-999 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Apache Oil Corporation, et al. , No. 61-000 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Campbell Energy Corporation, et al. , No. 61-001 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. TotalPetrochemicals & Refining USA, Inc. , et al. , No. 61-002 (25th Jud. Dist. Ct., Plaquemines Par.); Cameron Parish v. Alpine Exploration Companies, Inc., et al. , No. 10-19580 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Anadarko E&P Onshore, LLC, et al. , No. 10-19578 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Apache Corporation (of Delaware), et al. , No. 10-19579 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v . Auster Oil & Gas, Inc ., et al., No. 10-19582 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v . Ballard Exploration Company, Inc., et al. , No. 10-19574 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Bay Coquille, Inc., et al. , No. 10-19581 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. BEPCO, LP, et al. , No. 10-19572 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. BP America Production Company, et al. , No. 10-19576 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Brammer Engineering, Inc., et al ., No. 10-19573 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v . Burlington Resources, et al. , No. 10-19575 (38th Jud. Dist. Ct., Cameron Par.); Stutes v. Gulfport Energy Corporation, et al. , No. 102,146 (15th Jud. Dist. Ct., Vermilion Par.); St. Bernard Parish v. Atlantic Richfield, et al. , No. 16-1228 (34th Jud. Dist. Ct. St., Bernard Par.); City of New Orleans v. Apache Louisiana Mins, LLC, et al. , No. 19-cv-08290, (E.D. La.). 84 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Note 17 Taxes Income Taxes Year ended December 31 2023 2022 2021 Income tax expense (benefit) U.S. federal Current $ 895 $ 1,723 $ 174 Deferred 666 2,240 1,004 State and local Current 211 482 222 Deferred 1 39 202 Total United States 1,773 4,484 1,602 International Current 6,745 9,738 4,854 Deferred ( 345 ) ( 156 ) ( 506 ) Total International 6,400 9,582 4,348 Total income tax expense (benefit) $ 8,173 $ 14,066 $ 5,950 The reconciliation between the U.S. statutory federal income tax rate and the company’s effective income tax rate is detailed in the following table: Year ended December 31 2023 2022 2021 Income (loss) before income taxes United States $ 8,565 $ 21,005 $ 9,674 International 21,019 28,669 11,965 Total income (loss) before income taxes 29,584 49,674 21,639 Theoretical tax (at U.S. statutory rate of 21%) 6,213 10,432 4,544 Equity affiliate accounting effect ( 1,072 ) ( 1,678 ) ( 890 ) Effect of income taxes from international operations 3,001 5,041 2,692 State and local taxes on income, net of U.S. federal income tax benefit 252 508 216 Prior year tax adjustments, claims and settlements 1 ( 32 ) ( 90 ) 362 Tax credits ( 20 ) ( 6 ) ( 173 ) Other U.S. 1, 2 ( 169 ) ( 141 ) ( 801 ) Total income tax expense (benefit) $ 8,173 $ 14,066 $ 5,950 Effective income tax rate 3 27.6 % 28.3 % 27.5 % 1 Includes one-time tax costs (benefits) associated with changes in uncertain tax positions. 2 Includes one-time tax costs (benefits) associated with changes in valuation allowances (2023 - $( 84 ); 2022 - $( 36 ); 2021 - $( 624 )). 3 The company’s effective tax rate is reflective of equity income reported on an after-tax basis as part of the “Total Income (Loss) Before Income Tax Expense,” in accordance with U.S. Generally Accepted Accounting Principles. Chevron’s share of its equity affiliates’ total income tax expense in 2023 was $ 1,724 . 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. 85 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts The company records its deferred taxes on a tax-jurisdiction basis. The reported deferred tax balances are composed of the following: At December 31 2023 2022 Deferred tax liabilities Properties, plant and equipment $ 20,303 $ 18,295 Investments and other 4,263 4,492 Total deferred tax liabilities 24,566 22,787 Deferred tax assets Foreign tax credits ( 13,560 ) ( 12,599 ) Asset retirement obligations/environmental reserves ( 4,543 ) ( 4,518 ) Employee benefits ( 1,785 ) ( 2,087 ) Deferred credits ( 268 ) ( 446 ) Tax loss carryforwards ( 3,492 ) ( 3,887 ) Other accrued liabilities ( 1,416 ) ( 746 ) Inventory ( 126 ) ( 219 ) Operating leases ( 1,479 ) ( 1,134 ) Miscellaneous ( 3,652 ) ( 4,057 ) Total deferred tax assets ( 30,321 ) ( 29,693 ) Deferred tax assets valuation allowance 20,416 19,532 Total deferred taxes, net $ 14,661 $ 12,626 Deferred tax liabilities increased by $ 1,779 from year-end 2022, driven by an increase to properties, plant and equipment. 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. foreign tax credit carryforwards, tax loss carryforwards and temporary differences. The valuation allowance reduces the deferred tax assets to amounts that are, in management’s assessment, more likely than not to be realized. At the end of 2023, the company had gross tax loss carryforwards of approximately $ 9,600 and tax credit carryforwards of approximately $ 260 , primarily related to various international tax jurisdictions. Whereas some of these tax loss carryforwards do not have an expiration date, others expire at various times from 2024 through 2042. U.S. foreign tax credit carryforwards of $ 13,560 will expire between 2024 and 2033. At December 31, 2023 and 2022, deferred taxes were classified on the Consolidated Balance Sheet as follows: At December 31 2023 2022 Deferred charges and other assets $ ( 4,169 ) $ ( 4,505 ) Noncurrent deferred income taxes 18,830 17,131 Total deferred income taxes, net $ 14,661 $ 12,626 Income taxes, including U.S. state and foreign withholding taxes, are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely, or where no taxable temporary differences exist that are attributable to unremitted earnings from an investment in a foreign entity. The indefinite reinvestment assertion continues to apply for the purpose of determining deferred tax liabilities for U.S. state and foreign withholding tax purposes. It is not practicable to estimate the amount of state and foreign withholding taxes that might be payable on the possible remittance of earnings that are intended to be reinvested indefinitely. The company does not anticipate incurring significant additional taxes on remittances of earnings that are not indefinitely reinvested. Uncertain Income Tax Positions The company recognizes a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that the position is more likely than not (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in the accounting standards for income taxes refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods. 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 86 Notes to the Consolidated Financial Statements Financial Table of Contents 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. 2023 2022 2021 Balance at January 1 $ 5,323 $ 5,288 $ 5,018 Foreign currency effects ( 27 ) ( 2 ) ( 1 ) Additions based on tax positions taken in current year 248 30 194 Additions for tax positions taken in prior years 265 234 218 Reductions based on tax positions taken in current year ( 104 ) — — Reductions for tax positions taken in prior years ( 251 ) ( 117 ) ( 36 ) Settlements with taxing authorities in current year ( 2 ) ( 110 ) ( 18 ) Reductions as a result of a lapse of the applicable statute of limitations — — ( 87 ) Balance at December 31 $ 5,452 $ 5,323 $ 5,288 Approximately 79 percent of the $ 5,452 of unrecognized tax benefits at December 31, 2023, would have an impact on the effective tax rate if subsequently recognized. Certain of these unrecognized tax benefits relate to tax carryforwards that may require a full valuation allowance at the time of any such recognition. 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. Given the number of years that still remain subject to examination and the number of matters being examined in the various tax jurisdictions, the company is unable to estimate the range of possible adjustments to the balance of unrecognized tax benefits. On the Consolidated Statement of Income, the company reports interest and penalties related to liabilities for uncertain tax positions as “Income Tax Expense (Benefit).” As of December 31, 2023, accrued expense of $ 229 for anticipated interest and penalties was included on the Consolidated Balance Sheet, compared with accrued benefit of $ 112 as of year-end 2022. Income tax expense (benefit) associated with interest and penalties was $ 124 , $ 152 and $ 19 in 2023, 2022 and 2021, respectively. Taxes Other Than on Income Year ended December 31 2023 2022 2021 United States Import duties and other levies $ ( 9 ) $ 10 $ 7 Property and other miscellaneous taxes 818 609 552 Payroll taxes 286 248 302 Taxes on production 801 989 628 Total United States 1,896 1,856 1,489 International Import duties and other levies 72 63 49 Property and other miscellaneous taxes 2,004 1,789 2,174 Payroll taxes 121 122 113 Taxes on production 127 202 138 Total International 2,324 2,176 2,474 Total taxes other than on income $ 4,220 $ 4,032 $ 3,963 87 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Note 18 Properties, Plant and Equipment 1 At December 31 Year ended December 31 Gross Investment at Cost Net Investment Additions at Cost 2 Depreciation Expense 3 2023 2022 2021 2023 2022 2021 2023 2022 2021 2023 2022 2021 Upstream United States $ 117,955 $ 96,590 $ 93,393 $ 50,390 $ 37,031 $ 36,027 $ 20,408 $ 6,461 $ 4,520 $ 7,666 $ 5,012 $ 5,675 International 183,996 188,556 202,757 84,561 88,549 94,770 4,130 2,599 2,349 8,109 9,830 10,824 Total Upstream 301,951 285,146 296,150 134,951 125,580 130,797 24,538 9,060 6,869 15,775 14,842 16,499 Downstream United States 31,192 29,802 26,888 13,521 12,827 10,766 1,623 2,742 543 931 913 833 International 8,401 8,281 8,134 3,122 3,226 3,300 237 246 234 301 311 296 Total Downstream 39,593 38,083 35,022 16,643 16,053 14,066 1,860 2,988 777 1,232 1,224 1,129 All Other United States 4,390 4,402 4,729 1,991 1,931 2,078 311 230 143 313 247 290 International 147 154 144 34 27 20 15 12 7 6 6 7 Total All Other 4,537 4,556 4,873 2,025 1,958 2,098 326 242 150 319 253 297 Total United States 153,537 130,794 125,010 65,902 51,789 48,871 22,342 9,433 5,206 8,910 6,172 6,798 Total International 192,544 196,991 211,035 87,717 91,802 98,090 4,382 2,857 2,590 8,416 10,147 11,127 Total $ 346,081 $ 327,785 $ 336,045 $ 153,619 $ 143,591 $ 146,961 $ 26,724 $ 12,290 $ 7,796 $ 17,326 $ 16,319 $ 17,925 1 Other than the United States and Australia, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2023. Australia had PP&E of $ 41,409 , $ 44,012 and $ 46,687 in 2023, 2022 and 2021, respectively. 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. Note 19 Short-Term Debt At December 31 2023 2022 Commercial paper $ — $ — Notes payable to banks and others with originating terms of one year or less 469 328 Current maturities of long-term debt * 1,667 2,699 Current maturities of long-term finance leases 60 45 Redeemable long-term obligations 2,876 2,942 Subtotal 5,072 6,014 Reclassified to long-term debt ( 4,543 ) ( 4,050 ) Total short-term debt $ 529 $ 1,964 * Inclusive of unamortized premiums of $ 17 at December 31, 2023 and $ 5 at December 31, 2022. Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date. The company may periodically enter into interest rate swaps on a portion of its short-term debt. At December 31, 2023, the company had no interest rate swaps on short-term debt. At December 31, 2023, the company had $ 8,050 in 364 -day committed credit facilities with various major banks that enable the refinancing of short-term obligations on a long-term basis. The credit facilities allow the company to convert any amounts outstanding into a term loan for a period of up to one year. This supports commercial paper borrowing and can also be used for general corporate purposes. The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facility would be unsecured indebtedness at interest rates based on the Secured Overnight Financing Rate (SOFR), or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under this facility at December 31, 2023. The company classified $ 4,543 and $ 4,050 of short-term debt as long-term at December 31, 2023 and 2022, respectively. Settlement of these obligations is not expected to require the use of working capital within one year, and the company has both the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis. 88 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Note 20 Long-Term Debt Total long-term debt including finance lease liabilities at December 31, 2023, was $ 20,307 . The company’s long-term debt outstanding at year-end 2023 and 2022 was as follows: At December 31 2023 2022 Weighted Average Interest Rate (%) 1 Range of Interest Rates (%) 2 Principal Principal Notes due 2024 3.291 2.895 - 3.900 $ 1,650 $ 1,650 Notes due 2025 1.724 0.687 - 3.326 4,000 4,000 Notes due 2026 2.954 2,250 2,250 Notes due 2027 2.379 1.018 - 8.000 2,000 2,000 Notes due 2028 3.850 600 600 Notes due 2029 3.250 500 500 Notes due 2030 2.236 1,500 1,500 Debentures due 2031 8.625 102 102 Debentures due 2032 8.416 8.000 - 8.625 183 183 Notes due 2040 2.978 293 293 Notes due 2041 6.000 397 397 Notes due 2043 5.250 330 330 Notes due 2044 5.050 222 222 Notes due 2047 4.950 187 187 Notes due 2049 4.200 237 237 Notes due 2050 2.763 2.343 - 3.078 1,750 1,750 Debentures due 2097 7.250 60 60 Bank loans due 2023 - — 91 Medium-term notes, maturing from 2023 to 2038 6.599 5.331 - 7.840 20 23 Notes due 2023 — 2,600 Total including debt due within one year 16,281 18,975 Debt due within one year ( 1,650 ) ( 2,694 ) Fair market value adjustment for debt acquired in the Noble acquisition 578 664 Reclassified from short-term debt 4,543 4,050 Unamortized discounts and debt issuance costs ( 19 ) ( 23 ) Finance lease liabilities 3 574 403 Total long-term debt $ 20,307 $ 21,375 1 Weighted-average interest rate at December 31, 2023. 2 Range of interest rates at December 31, 2023. 3 For details on finance lease liabilities, see Note 5 Lease Commitments . Long-term debt excluding finance lease liabilities with a principal balance of $ 16,281 matures as follows: 2024 – $ 1,650 ; 2025 – $ 4,000 ; 2026 – $ 2,250 ; 2027 – $ 2,000 ; 2028 – $ 600 ; and after 2028 – $ 5,781 . 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. Note 21 Accounting for Suspended Exploratory Wells The company continues to capitalize exploratory well costs after the completion of drilling when the well has found a sufficient quantity of reserves to justify completion as a producing well, and the business unit is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met or if the company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense. 89 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended December 31, 2023: 2023 2022 2021 Beginning balance at January 1 $ 1,627 $ 2,109 $ 2,512 Additions to capitalized exploratory well costs pending the determination of proved reserves 88 72 56 Reclassifications to wells, facilities and equipment based on the determination of proved reserves — ( 481 ) ( 425 ) Capitalized exploratory well costs charged to expense ( 67 ) ( 73 ) ( 34 ) Ending balance at December 31 $ 1,648 $ 1,627 $ 2,109 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: At December 31 2023 2022 2021 Exploratory well costs capitalized for a period of one year or less $ 78 $ 73 $ 65 Exploratory well costs capitalized for a period greater than one year 1,570 1,554 2,044 Balance at December 31 $ 1,648 $ 1,627 $ 2,109 Number of projects with exploratory well costs that have been capitalized for a period greater than one year * 13 12 15 * Certain projects have multiple wells or fields or both. 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 $ 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) $ 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. 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. The tables below contain the aging of these costs on a well and project basis: Aging based on drilling completion date of individual wells: Amount Number of wells 2000-2009 $ 263 14 2010-2014 1,121 49 2015-2022 186 8 Total $ 1,570 71 Aging based on drilling completion date of last suspended well in project: Amount Number of projects 2008-2012 $ 292 2 2013-2016 1,082 6 2017-2023 196 5 Total $ 1,570 13 Note 22 Stock Options and Other Share-Based Compensation 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 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. 90 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Cash received in payment for option exercises under all share-based payment arrangements for 2023, 2022 and 2021 was $ 263 , $ 5,835 and $ 1,274 , respectively. Actual tax benefits realized for the tax deductions from option exercises were $ 20 , $ 216 and $( 15 ) for 2023, 2022 and 2021, respectively. Cash paid to settle performance shares, restricted stock units and stock appreciation rights was $ 566 , $ 556 and $ 163 for 2023, 2022 and 2021, respectively. On May 25, 2022, stockholders approved the Chevron 2022 Long-Term Incentive Plan (2022 LTIP). Awards under the 2022 LTIP may take the form of, but are not limited to, stock options, restricted stock, restricted stock units, stock appreciation rights, performance shares and non-stock grants. From May 2022 through May 2032, no more than 104 million shares may be issued under the 2022 LTIP. For awards issued on or after May 25, 2022, no more than 48 million of those shares may be issued in the form of full value awards such as share-settled restricted stock, share-settled restricted stock units and other share-settled awards that do not require full payment in cash or property for shares underlying such awards by the award recipient. For the major types of awards issued before January 1, 2017, the contractual terms vary between three years for the performance shares and restricted stock units, and 10 years for the stock options and stock appreciation rights. For awards issued after January 1, 2017, contractual terms vary between three years for the performance shares and special restricted stock units, five years for standard restricted stock units and 10 years for the stock options and stock appreciation rights. Commencing for grants issued in January 2023 and after, standard restricted stock units vest ratably on an annual basis over a three-year period. Forfeitures of performance shares, restricted stock units, and stock appreciation rights are recognized as they occur. Forfeitures of stock options are estimated using historical forfeiture data dating back to 1990. 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: Year ended December 31 2023 2022 2021 Expected term in years 1 6.4 6.9 6.8 Volatility 2 32.5 % 31.3 % 31.1 % Risk-free interest rate based on zero coupon U.S. treasury note 3.43 % 1.79 % 0.71 % Dividend yield 3.5 % 5.0 % 6.0 % Weighted-average fair value per option granted $ 45.82 $ 23.56 $ 12.22 1 Expected term is based on historical exercise and post-vesting cancellation data. 2 Volatility rate is based on historical stock prices over an appropriate period, generally equal to the expected term. A summary of option activity during 2023 is presented below: Shares (Thousands) Weighted-Average Exercise Price Averaged Remaining Contractual Term (Years) Aggregate Intrinsic Value Outstanding at January 1, 2023 25,265 $ 114.61 Granted 2,122 $ 179.08 Exercised ( 2,538 ) $ 104.30 Forfeited ( 474 ) $ 246.61 Outstanding at December 31, 2023 24,375 $ 118.72 5.14 $ 934 Exercisable at December 31, 2023 18,438 $ 113.38 4.11 $ 791 The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2023, 2022 and 2021 was $ 167 , $ 2,369 and $ 152 , respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards. 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. That cost is expected to be recognized over a weighted-average period of 1.9 years. At January 1, 2023, the number of LTIP performance shares outstanding was equivalent to 4,753,266 shares. During 2023, 1,291,262 performance shares were granted, 1,521,636 shares vested with cash proceeds distributed to recipients and 103,582 shares were forfeited. At December 31, 2023, there were 4,419,310 performance shares outstanding that are payable in cash. The fair value of the liability recorded for these instruments was $ 360 and was measured largely using the Monte Carlo simulation method. 91 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, 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. The fair value of the liability recorded for the vested portion of these instruments was $ 32 . Note 23 Employee Benefit Plans The company has defined benefit pension plans for many employees. The company typically prefunds defined benefit plans as required by local regulations or in certain situations where prefunding provides economic advantages. In the United States, all qualified plans are subject to the Employee Retirement Income Security Act (ERISA) minimum funding standard. The company does not typically fund U.S. nonqualified pension plans that are not subject to funding requirements under laws and regulations because contributions to these pension plans may be less economic and investment returns may be less attractive than the company’s other investment alternatives. The company also sponsors other postretirement benefit (OPEB) plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees. The plans are unfunded, and the company and retirees share the costs. For the company’s main U.S. medical plan, the increase to the pre-Medicare company contribution for retiree medical coverage is limited to no more than 4 percent each year. Certain life insurance benefits are paid by the company. 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. The funded status of the company’s pension and OPEB plans for 2023 and 2022 follows: Pension Benefits 2023 2022 Other Benefits U.S. Int’l. U.S. Int’l. 2023 2022 Change in Benefit Obligation Benefit obligation at January 1 $ 9,713 $ 3,354 $ 12,966 $ 5,351 $ 1,938 $ 2,489 Service cost 342 58 432 83 33 43 Interest cost 448 193 318 137 97 60 Plan participants’ contributions — 3 — 3 63 62 Plan amendments — 28 40 38 — 18 Actuarial (gain) loss 603 17 ( 2,753 ) ( 1,559 ) 103 ( 509 ) Foreign currency exchange rate changes — 180 — ( 423 ) 5 ( 5 ) Benefits paid ( 714 ) ( 218 ) ( 1,290 ) ( 276 ) ( 222 ) ( 220 ) Divestitures/Acquisitions — ( 14 ) — — — — Curtailment — 2 — — — — Special termination costs — 2 — — — — Benefit obligation at December 31 10,392 3,605 9,713 3,354 2,017 1,938 Change in Plan Assets Fair value of plan assets at January 1 7,942 3,286 9,919 4,950 — — Actual return on plan assets 889 46 ( 1,851 ) ( 1,096 ) — — Foreign currency exchange rate changes — 181 — ( 453 ) — — Employer contributions 1,020 100 1,164 158 159 158 Plan participants’ contributions — 3 — 3 63 62 Benefits paid ( 714 ) ( 218 ) ( 1,290 ) ( 276 ) ( 222 ) ( 220 ) Fair value of plan assets at December 31 9,137 3,398 7,942 3,286 — — Funded status at December 31 $ ( 1,255 ) $ ( 207 ) $ ( 1,771 ) $ ( 68 ) $ ( 2,017 ) $ ( 1,938 ) 92 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: Pension Benefits 2023 2022 Other Benefits U.S. Int’l. U.S. Int’l. 2023 2022 Deferred charges and other assets $ 31 $ 703 $ 26 $ 759 $ — $ — Accrued liabilities ( 145 ) ( 73 ) ( 210 ) ( 62 ) ( 154 ) ( 152 ) Noncurrent employee benefit plans ( 1,141 ) ( 837 ) ( 1,587 ) ( 765 ) ( 1,863 ) ( 1,786 ) 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. 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. These amounts consisted of: Pension Benefits 2023 2022 Other Benefits U.S. Int’l. U.S. Int’l. 2023 2022 Net actuarial loss $ 3,161 $ 823 $ 3,147 $ 659 $ ( 266 ) $ ( 392 ) Prior service (credit) costs 37 126 40 107 ( 89 ) ( 115 ) Total recognized at December 31 $ 3,198 $ 949 $ 3,187 $ 766 $ ( 355 ) $ ( 507 ) The accumulated benefit obligations for all U.S. and international pension plans were $ 9,284 and $ 3,378 , respectively, at December 31, 2023, and $ 8,595 and $ 3,084 , respectively, at December 31, 2022. Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2023 and 2022, was: Pension Benefits 2023 2022 U.S. Int’l. U.S. Int’l. Projected benefit obligations $ 1,203 $ 913 $ 1,322 $ 828 Accumulated benefit obligations 1,108 773 1,135 671 Fair value of plan assets — 4 — 3 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: 93 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Pension Benefits 2023 2022 2021 Other Benefits U.S. Int’l. U.S. Int’l. U.S. Int’l. 2023 2022 2021 Net Periodic Benefit Cost Service cost $ 342 $ 58 $ 432 $ 83 $ 450 $ 123 $ 33 $ 43 $ 43 Interest cost 448 193 318 137 235 137 97 60 53 Expected return on plan assets ( 557 ) ( 204 ) ( 624 ) ( 176 ) ( 596 ) ( 171 ) — — — Amortization of prior service costs (credits) 4 8 2 6 2 8 ( 25 ) ( 27 ) ( 27 ) Recognized actuarial losses 199 8 218 15 309 46 ( 19 ) 13 16 Settlement losses 56 — 363 ( 6 ) 672 7 — — — 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 Changes Recognized in Comprehensive Income Net actuarial (gain) loss during period 270 172 ( 279 ) ( 257 ) ( 725 ) ( 408 ) 108 ( 514 ) ( 111 ) Amortization of actuarial loss ( 255 ) ( 8 ) ( 581 ) ( 5 ) ( 981 ) ( 73 ) 19 ( 13 ) ( 15 ) Prior service (credits) costs during period — 28 40 38 — — 1 18 — Amortization of prior service (costs) credits ( 4 ) ( 8 ) ( 2 ) ( 6 ) ( 2 ) ( 11 ) 25 27 27 Total changes recognized in other comprehensive income 11 184 ( 822 ) ( 230 ) ( 1,708 ) ( 492 ) 153 ( 482 ) ( 99 ) Recognized in Net Periodic Benefit Cost and Other Comprehensive Income $ 503 $ 249 $ ( 113 ) $ ( 176 ) $ ( 636 ) $ ( 343 ) $ 239 $ ( 393 ) $ ( 14 ) Assumptions The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31: Pension Benefits 2023 2022 2021 Other Benefits U.S. Int’l. U.S. Int’l. U.S. Int’l. 2023 2022 2021 Assumptions used to determine benefit obligations: Discount rate 5.0 % 5.5 % 5.2 % 5.8 % 2.8 % 2.8 % 5.1 % 5.3 % 2.9 % Rate of compensation increase 4.5 % 3.9 % 4.5 % 4.2 % 4.5 % 4.1 % N/A N/A N/A Assumptions used to determine net periodic benefit cost: Discount rate for service cost 5.2 % 5.8 % 3.6 % 2.8 % 3.0 % 2.4 % 5.4 % 3.1 % 3.0 % Discount rate for interest cost 5.0 % 5.8 % 2.8 % 2.8 % 1.9 % 2.4 % 5.2 % 2.4 % 2.1 % Expected return on plan assets 7.0 % 6.1 % 6.6 % 3.9 % 6.5 % 3.5 % N/A N/A N/A Rate of compensation increase 4.5 % 4.2 % 4.5 % 4.1 % 4.5 % 4.0 % N/A N/A N/A Expected Return on Plan Assets The company’s estimated long-term rates of return on pension assets are driven primarily by actual historical asset-class returns, an assessment of expected future performance, advice from external actuarial firms and the incorporation of specific asset-class risk factors. Asset allocations are periodically updated using pension plan asset/liability studies, and the company’s estimated long-term rates of return are consistent with these studies. 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 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. pension plan used in the determination of pension expense was based on the market values in the three months preceding the year-end measurement date. Management considers the three-month time period long enough to minimize the effects of distortions from day-to-day market volatility and still be contemporaneous to the end of the year. For other plans, market value of assets as of year-end is used in calculating the pension expense. Discount Rate The discount rate assumptions used to determine the U.S. and international pension and OPEB plan obligations and expense reflect the rate at which benefits could be effectively settled, and are equal to the equivalent single rate resulting from yield curve analysis. This analysis considered the projected benefit payments specific to the company’s plans and the yields on high-quality bonds. The projected cash flows were discounted to the valuation date using the yield curve for the main U.S. pension and OPEB plans. The effective discount rates derived from this analysis were 5.0 percent, 5.2 percent, and 2.8 percent for 2023, 2022, and 2021, respectively, for both the main U.S. pension and OPEB plans. 94 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. OPEB plan, the assumed health care cost-trend rates start with 8.4 percent in 2024 and gradually decline to 4.5 percent for 2033 and beyond. For this measurement at December 31, 2022, the assumed health care cost-trend rates started with 6.6 percent in 2023 and gradually declined to 4.5 percent for 2032 and beyond. Plan Assets and Investment Strategy The fair value measurements of the company’s pension plans for 2023 and 2022 are as follows: U.S. Int’l. Total Level 1 Level 2 Level 3 NAV Total Level 1 Level 2 Level 3 NAV At December 31, 2022 Equities U.S. 1 $ 1,358 $ 1,358 $ — $ — $ — $ 164 $ 164 $ — $ — $ — International 946 946 — — — 120 120 — — — Collective Trusts/Mutual Funds 2 1,695 4 — — 1,691 87 6 — — 81 Fixed Income Government 110 — 110 — — 185 127 58 — — Corporate 680 — 680 — — 343 15 328 — — Bank Loans 45 — 45 — — — — — — — Mortgage/Asset Backed 1 — 1 — — 4 — 4 — — Collective Trusts/Mutual Funds 2 1,616 — — — 1,616 1,750 — — — 1,750 Mixed Funds 3 — — — — — 87 14 73 — — Real Estate 4 1,184 — — — 1,184 198 — — 38 160 Alternative Investments — — — — — — — — — — Cash and Cash Equivalents 200 25 — — 175 80 69 2 — 9 Other 5 107 37 15 54 1 268 — 18 85 165 Total at December 31, 2022 $ 7,942 $ 2,370 $ 851 $ 54 $ 4,667 $ 3,286 $ 515 $ 483 $ 123 $ 2,165 At December 31, 2023 Equities U.S. 1 $ 1,691 $ 1,689 $ 1 $ 1 $ — $ 188 $ 188 $ — $ — $ — International 1,128 1,128 — — — 124 124 — — — Collective Trusts/Mutual Funds 2 1,269 4 — — 1,265 95 6 — — 89 Fixed Income Government 82 — 82 — — 172 101 71 — — Corporate 964 — 964 — — 431 4 427 — — Bank Loans 5 — 5 — — — — — — — Mortgage/Asset Backed 1 — 1 — — 5 — 5 — — Collective Trusts/Mutual Funds 2 2,293 — — — 2,293 1,819 — — — 1,819 Mixed Funds 3 — — — — — 85 8 77 — — Real Estate 4 1,087 — — — 1,087 147 — 24 — 123 Alternative Investments — — — — — 9 — 9 — — Cash and Cash Equivalents 548 12 — — 536 81 74 1 — 6 Other 5 69 ( 2 ) 14 56 1 242 — 11 81 150 Total at December 31, 2023 $ 9,137 $ 2,831 $ 1,067 $ 57 $ 5,182 $ 3,398 $ 505 $ 625 $ 81 $ 2,187 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. plans are entirely index funds; for International plans, they are mostly unit trust and index funds. 3 Mixed funds are composed of funds that invest in both equity and fixed-income instruments in order to diversify and lower risk. 4 The year-end valuations of the U.S. real estate assets are based on third-party appraisals that occur at least once a year for each property in the portfolio. 5 The “Other” asset class includes net payables for securities purchased but not yet settled (Level 1); dividends and interest- and tax-related receivables (Level 2); insurance contracts (Level 3); and investments in private-equity limited partnerships (NAV). 95 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below: Equity U.S. International Real Estate Other Total Total at December 31, 2021 $ — $ 1 $ 42 $ 161 $ 204 Actual Return on Plan Assets: Assets held at the reporting date — ( 1 ) — ( 18 ) ( 19 ) Assets sold during the period — — ( 4 ) — ( 4 ) Purchases, Sales and Settlements — — — ( 4 ) ( 4 ) Transfers in and/or out of Level 3 — — — — — Total at December 31, 2022 $ — $ — $ 38 $ 139 $ 177 Actual Return on Plan Assets: Assets held at the reporting date 1 — 5 — 6 Assets sold during the period — — — ( 2 ) ( 2 ) Purchases, Sales and Settlements — — — — — Transfers in and/or out of Level 3 — — ( 43 ) — ( 43 ) Total at December 31, 2023 $ 1 $ — $ — $ 137 $ 138 The primary investment objectives of the pension plans are to achieve the highest rate of total return within prudent levels of risk and liquidity, to diversify and mitigate potential downside risk associated with the investments, and to provide adequate liquidity for benefit payments and portfolio management. The company’s U.S. and U.K. pension plans comprise 95 percent of the total pension assets. Both the U.S. and U.K. plans have an Investment Committee that regularly meets during the year to review the asset holdings and their returns. To assess the plans’ investment performance, long-term asset allocation policy benchmarks have been established. For the primary U.S. pension plan, the company’s Investment Committee has established the following approved asset allocation ranges: Equities 35 – 65 percent, Fixed Income 25 – 45 percent, Real Estate 5 – 25 percent, Alternative Investments 0 – 5 percent and Cash 0 – 15 percent. For the U.K. pension plan, the U.K. Board of Trustees has established the following asset allocation guidelines: Equities 5 – 15 percent, Fixed Income 63 – 93 percent, Real Estate 5 – 15 percent, and Cash 0 – 7 percent. 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 liquidity constraints. To mitigate concentration and other risks, assets are invested across multiple asset classes with active investment managers and passive index funds. The company does not prefund its OPEB obligations. Cash Contributions and Benefit Payments In 2023, the company contributed $ 1,020 and $ 100 to its U.S. and international pension plans, respectively. In 2024, the company expects contributions to be approximately $ 750 to its U.S. plans and $ 100 to its international pension plans. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments, tax law changes and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations. The company anticipates paying OPEB benefits of approximately $ 150 in 2024; $ 159 was paid in 2023. The following benefit payments, which include estimated future service, are expected to be paid by the company in the next 10 years: Pension Benefits Other U.S. Int’l. Benefits 2024 $ 886 $ 216 $ 154 2025 912 210 151 2026 904 222 149 2027 901 228 147 2028 877 240 146 2029-2033 4,248 1,266 716 Employee Savings Investment Plan Eligible employees of Chevron and certain of its subsidiaries participate in the Chevron Employee Savings Investment Plan (ESIP). Compensation expense for the ESIP totaled $ 320 , $ 283 and $ 252 in 2023, 2022 and 2021, respectively. 96 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Benefit Plan Trusts Prior to its acquisition by Chevron, Texaco established a benefit plan trust for funding obligations under some of its benefit plans. At year-end 2023, the trust contained 14.2 million shares of Chevron treasury stock. The trust will sell the shares or use the dividends from the shares to pay benefits only to the extent that the company does not pay such benefits. The company intends to continue to pay its obligations under the benefit plans. The trustee will vote the shares held in the trust as instructed by the trust’s beneficiaries. 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. 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. Chevron also has the LTIP for officers and other regular salaried employees of the company and its subsidiaries who hold positions of significant responsibility. Awards under the LTIP consist of stock options and other share-based compensation that are described in Note 22 Stock Options and Other Share-Based Compensation . Note 24 Other Contingencies and Commitments Income Taxes The company calculates its income tax expense and liabilities quarterly. These liabilities generally are subject to audit and are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been calculated. Refer to Note 17 Taxes for a discussion of the periods for which tax returns have been audited for the company’s major tax jurisdictions and a discussion for all tax jurisdictions of the differences between the amount of tax benefits recognized in the financial statements and the amount taken or expected to be taken in a tax return. Settlement of open tax years, as well as other tax issues in countries where the company conducts its businesses, are not expected to have a material effect on the consolidated financial position or liquidity of the company and, in the opinion of management, adequate provisions have been made for all years under examination or subject to future examination. Guarantees The company has one guarantee to an equity affiliate totaling $ 135 . This guarantee is associated with certain payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 4-year remaining term of this guarantee, the maximum guarantee amount will be reduced as certain fees are paid by the affiliate. There are numerous cross-indemnity agreements with the affiliate and the other partners to permit recovery of amounts paid under the guarantee. Chevron has recorded no liability for this guarantee. Indemnifications The company often includes standard indemnification provisions in its arrangements with its partners, suppliers and vendors in the ordinary course of business, the terms of which range in duration and sometimes are not limited. The company may be obligated to indemnify such parties for losses or claims suffered or incurred in connection with its service or other claims made against such parties. Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain contingent liabilities with respect to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which may relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate amounts of required payments under throughput and take-or-pay agreements are: 2024 – $ 909 ; 2025 – $ 1,086 ; 2026 – $ 1,141 ; 2027 – $ 1,193 ; 2028 – $ 1,183 ; after 2028 – $ 7,553 . The aggregate amount of required payments for other unconditional purchase obligations are: 2024 – $ 589 ; 2025 – $ 451 ; 2026 – $ 484 ; 2027 – $ 604 ; 2028 – $ 273 ; after 2028 – $ 1,078 . A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were $ 1,420 in 2023, $ 1,866 in 2022 and $ 861 in 2021. Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances by the company or other parties. Such contingencies may exist for various operating, closed and divested sites, including, but not limited to, U.S. federal Superfund sites and analogous sites under state laws, refineries, chemical plants, marketing facilities, crude oil fields, and mining sites. 97 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Although the company has provided for known environmental obligations that are probable and reasonably estimable, it is likely that the company will continue to incur additional liabilities. The amount of additional future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. These future costs may be material to results of operations in the period in which they are recognized, but the company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Chevron’s environmental reserve as of December 31, 2023, was $ 936 . 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. Of the remaining year-end 2023 environmental reserves balance of $ 704 , $ 389 is related to the company’s U.S. downstream operations, $ 55 to its international downstream operations, and $ 260 to its upstream operations. Liabilities at all sites were primarily associated with the company’s plans and activities to remediate soil or groundwater contamination or both. The company manages environmental liabilities under specific sets of regulatory requirements, which in the United States include the Resource Conservation and Recovery Act and various state and local regulations. No single remediation site at year-end 2023 had a recorded liability that was material to the company’s results of operations, consolidated financial position or liquidity. Refer to Note 25 Asset Retirement Obligations for a discussion of the company’s asset retirement obligations. Other Contingencies Chevron receives claims from and submits claims to customers; trading partners; joint venture partners; U.S. federal, state and local regulatory bodies; governments; contractors; insurers; suppliers; and individuals. The amounts of these claims, individually and in the aggregate, may be significant and take lengthy periods to resolve, and may result in gains or losses in future periods. The company and its affiliates also continue to review and analyze their operations and may close, retire, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve competitiveness and profitability. These activities, individually or together, may result in significant gains or losses in future periods. In addition, some assets are sold along with their related liabilities and in certain instances, such transferred obligations have reverted and may in the future revert to the company and result in losses that could be significant. In fourth quarter 2023, the company recognized an after-tax loss of $ 1,950 related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S. Gulf of Mexico, as companies that purchased these assets have filed for protection under Chapter 11 of the U.S. Bankruptcy Code, and we believe it is now probable and estimable that a portion of these obligations will revert to the company. Note 25 Asset Retirement Obligations The company records the fair value of a liability for an asset retirement obligation (ARO) both as an asset and a liability when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. The legal obligation to perform the asset retirement activity is unconditional, even though uncertainty may exist about the timing and/or method of settlement that may be beyond the company’s control. This uncertainty about the timing and/or method of settlement is factored into the measurement of the liability when sufficient information exists to reasonably estimate fair value. Recognition of the ARO includes: (1) the present value of a liability and offsetting asset, (2) the subsequent accretion of that liability and depreciation of the asset, and (3) the periodic review of the ARO liability estimates and discount rates. AROs are primarily recorded for the company’s crude oil and natural gas producing assets. No significant AROs associated with any legal obligations to retire downstream long-lived assets have been recognized, as indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the associated ARO. The company performs periodic 98 Notes to the Consolidated Financial Statements Financial Table of Contents 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: 2023 2022 2021 Balance at January 1 $ 12,701 $ 12,808 $ 13,616 Liabilities assumed in the PDC acquisition 220 — — Liabilities incurred 183 9 31 Liabilities settled ( 1,565 ) ( 1,281 ) ( 1,887 ) Accretion expense 593 560 616 Revisions in estimated cash flows 1,701 605 432 Balance at December 31 $ 13,833 $ 12,701 $ 12,808 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 . Note 26 Revenue Revenue from contracts with customers is presented in “Sales and other operating revenues” along with some activity that is accounted for outside the scope of Accounting Standard Codification (ASC) 606, which is not material to this line, on the Consolidated Statement of Income. Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another (including buy/sell arrangements) are combined and recorded on a net basis and reported in “Purchased crude oil and products” on the Consolidated Statement of Income. 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” 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” 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. Amounts for these items are not material to the company’s financial position. Note 27 Other Financial Information Earnings in 2023 included after-tax gains of approximately $ 143 relating to the sale of certain properties. Of this amount, approximately $ 33 and $ 110 related to downstream and upstream, respectively. Earnings in 2022 included after-tax gains of approximately $ 390 relating to the sale of certain properties, of which approximately $ 90 and $ 300 related to downstream and upstream assets, respectively. Earnings in 2021 included after-tax gains of approximately $ 785 relating to the sale of certain properties, of which approximately $ 30 and $ 755 related to downstream and upstream assets, respectively. Earnings in 2023 included after-tax charges of approximately $ 1,950 for abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S. Gulf of Mexico and $ 1,765 for upstream impairments, mainly in California, and several tax items with a net benefit of $ 655 . Earnings in 2022 included after-tax charges of approximately $ 1,075 for impairments and other asset write-offs related to upstream, $ 600 for an early contract termination in upstream, and $ 271 for pension settlement costs. Earnings in 2021 included after-tax charges of approximately $ 519 for pension settlement c osts, $ 260 for early retirement of debt, $ 120 relating to upstream remediation and $ 110 relating to downstream legal reserves. 99 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Other financial information is as follows: Year ended December 31 2023 2022 2021 Total financing interest and debt costs $ 617 $ 630 $ 775 Less: Capitalized interest 148 114 63 Interest and debt expense $ 469 $ 516 $ 712 Research and development expenses $ 320 $ 268 $ 268 Excess of replacement cost over the carrying value of inventories (LIFO method) $ 6,455 $ 9,061 $ 5,588 LIFO profits (losses) on inventory drawdowns included in earnings $ 14 $ 122 $ 35 Foreign currency effects * $ ( 224 ) $ 669 $ 306 * Includes $( 11 ), $ 253 and $ 180 in 2023, 2022 and 2021, respectively, for the company’s share of equity affiliates’ foreign currency effects. The company has $ 4,722 in goodwill on the Consolidated Balance Sheet, of which $ 4,370 is in the upstream segment primarily related to the 2005 acquisition of Unocal and $ 352 is in the downstream segment. The company tested this goodwill for impairment during 2023, and no impairment was required. Note 28 Financial Instruments - Credit Losses 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. The company routinely assesses the financial strength of its customers. When the financial strength of a customer is not considered sufficient, alternative risk mitigation measures may be deployed, including requiring prepayments, letters of credit or other acceptable forms of collateral. Once credit is extended and a receivable balance exists, the company applies a quantitative calculation to current trade receivable balances that reflects credit risk predictive analysis, including probability of default and loss given default, which takes into consideration current and forward-looking market data as well as the company’s historical loss data. 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 $ 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. This management review includes review of reasonable and supportable repayment forecasts. Non-trade receivables also include employee and tax receivables that are deemed immaterial and low risk. Loans to equity affiliates and non-equity investees are also considered non-trade and associated allowances of $ 219 and $ 560 at December 31, 2023 and December 31, 2022, respectively, are included within “Investments and advances” on the Consolidated Balance Sheet. 100 Notes to the Consolidated Financial Statements Financial Table of Contents Millions of dollars, except per-share amounts Note 29 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 10,487 Other assets 118 Total assets acquired 11,235 Current liabilities 1,376 Long-term debt 1,473 Deferred income tax 1,397 Other liabilities 469 Total liabilities assumed 4,715 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. Note 30 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. See Item 1A. Risk Factors for a discussion of risks related to the Hess acquisition. 101 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 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 Table I - Costs Incurred in Exploration, Property Acquisitions and Development 1 Consolidated Companies Affiliated Companies Other Millions of dollars U.S. Americas Africa Asia Australia Europe Total TCO Other Year Ended December 31, 2023 Exploration Wells $ 280 $ 92 $ 36 $ 111 $ 11 $ — $ 530 $ — $ — Geological and geophysical 84 49 83 — — — 216 — — Other 50 104 57 15 32 4 262 — — Total exploration 414 245 176 126 43 4 1,008 — — Property acquisitions 2 Proved - Other 10,123 — — — — — 10,123 — — Unproved - Other 504 1 — 3 — — 508 — — Total property acquisitions 10,627 1 — 3 — — 10,631 — — Development 3 9,645 986 784 619 822 64 12,920 2,278 86 Total Costs Incurred 4 $ 20,686 $ 1,232 $ 960 $ 748 $ 865 $ 68 $ 24,559 $ 2,278 $ 86 Year Ended December 31, 2022 Exploration Wells $ 239 $ 84 $ 78 $ 34 $ 4 $ — $ 439 $ — $ — Geological and geophysical 98 28 110 — 1 — 237 — — Other 53 72 75 30 27 2 259 — — Total exploration 390 184 263 64 32 2 935 — — Property acquisitions 2 Proved - Other 18 — 63 13 — — 94 — — Unproved - Other 104 78 73 — — — 255 — — Total property acquisitions 122 78 136 13 — — 349 — — Development 3 6,221 863 21 649 719 35 8,508 2,429 34 Total Costs Incurred 4 $ 6,733 $ 1,125 $ 420 $ 726 $ 751 $ 37 $ 9,792 $ 2,429 $ 34 Year Ended December 31, 2021 Exploration Wells $ 184 $ 31 $ 5 $ 36 $ — $ — $ 256 $ — $ — Geological and geophysical 67 58 40 — 22 — 187 — — Other 80 80 39 14 25 1 239 — — Total exploration 331 169 84 50 47 1 682 — — Property acquisitions 2 Proved - Other 98 — 15 53 — — 166 — — Unproved - Other 13 16 — — — — 29 — — Total property acquisitions 111 16 15 53 — — 195 — — Development 3 4,360 640 383 545 526 44 6,498 2,442 27 Total Costs Incurred 4 $ 4,802 $ 825 $ 482 $ 648 $ 573 $ 45 $ 7,375 $ 2,442 $ 27 1 Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. Includes capitalized amounts related to asset retirement obligations. See Note 25 Asset Retirement Obligations . 2 Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired in nonmonetary transactions. 3 Includes $208, $186 and $298 of costs incurred on major capital projects prior to assignment of proved reserves for consolidated companies in 2023, 2022, and 2021, respectively. 4 Reconciliation of consolidated companies total cost incurred to Upstream Capex - $ billions: 2023 2022 2021 Total cost incurred by Consolidated Companies $ 24.6 $ 9.8 $ 7.4 PDC Energy, Inc. (PDC) acquisition (10.5) — — Expensed exploration costs (0.5) (0.5) (0.4) (Geological and geophysical and other exploration costs) Non-oil and gas activities 1.4 0.6 0.2 (Primarily LNG and transportation activities) ARO reduction/(build) (1.3) (0.3) (0.4) Upstream Capex $ 13.7 $ 9.6 $ 6.8 Reference page 48 Upstream Capex 102 Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents proved reserves, and changes in estimated discounted future net cash flows. The amounts for consolidated companies are organized by geographic areas including the United States, Other Americas, Africa, Asia, Australia/Oceania and Europe. 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. Table II - Capitalized Costs Related to Oil and Gas Producing Activities Consolidated Companies Affiliated Companies Other Millions of dollars U.S. Americas Africa Asia Australia Europe Total TCO Other At December 31, 2023 Unproved properties $ 2,541 $ 1,666 $ 265 $ 536 $ 1,882 $ — $ 6,890 $ 108 $ — Proved properties and related producing assets 100,680 23,867 47,635 30,387 23,842 2,228 228,639 23,139 1,609 Support equipment 2,121 191 1,555 688 19,118 — 23,673 673 — Deferred exploratory wells — 73 205 178 1,119 74 1,649 — — Other uncompleted projects 10,872 734 1,271 1,121 1,469 52 15,519 15,438 130 Gross Capitalized Costs 116,214 26,531 50,931 32,910 47,430 2,354 276,370 39,358 1,739 Unproved properties valuation 168 1,214 183 533 5 — 2,103 77 — Proved producing properties – Depreciation and depletion 65,055 14,009 39,921 18,941 12,082 834 150,842 10,279 866 Support equipment depreciation 1,295 155 1,202 529 5,478 — 8,659 478 — Accumulated provisions 66,518 15,378 41,306 20,003 17,565 834 161,604 10,834 866 Net Capitalized Costs $ 49,696 $ 11,153 $ 9,625 $ 12,907 $ 29,865 $ 1,520 $ 114,766 $ 28,524 $ 873 At December 31, 2022 Unproved properties $ 2,541 $ 2,176 $ 265 $ 970 $ 1,987 $ — $ 7,939 $ 108 $ — Proved properties and related producing assets 83,525 22,867 46,950 31,179 22,926 2,186 209,633 15,793 1,552 Support equipment 2,146 194 1,543 696 19,107 — 23,686 646 — Deferred exploratory wells 43 56 116 40 1,119 74 1,448 — — Other uncompleted projects 8,213 610 1,095 914 1,869 30 12,731 20,590 54 Gross Capitalized Costs 96,468 25,903 49,969 33,799 47,008 2,290 255,437 37,137 1,606 Unproved properties valuation 178 1,589 146 969 110 — 2,992 74 — Proved producing properties – Depreciation and depletion 58,253 12,974 38,543 19,051 10,689 720 140,230 9,441 654 Support equipment depreciation 1,302 155 1,166 500 4,644 — 7,767 424 — Accumulated provisions 59,733 14,718 39,855 20,520 15,443 720 150,989 9,939 654 Net Capitalized Costs $ 36,735 $ 11,185 $ 10,114 $ 13,279 $ 31,565 $ 1,570 $ 104,448 $ 27,198 $ 952 At December 31, 2021 Unproved properties $ 3,302 $ 2,382 $ 191 $ 982 $ 1,987 $ — $ 8,844 $ 108 $ — Proved properties and related producing assets 80,821 22,031 47,030 46,379 22,235 2,156 220,652 14,635 1,558 Support equipment 2,134 198 1,096 906 18,918 — 23,252 582 — Deferred exploratory wells 328 121 196 246 1,144 74 2,109 — — Other uncompleted projects 6,581 431 1,096 903 1,586 24 10,621 19,382 31 Gross Capitalized Costs 93,166 25,163 49,609 49,416 45,870 2,254 265,478 34,707 1,589 Unproved properties valuation 289 1,536 131 855 110 — 2,921 70 — Proved producing properties – Depreciation and depletion 55,064 11,745 37,657 33,300 8,920 602 147,288 8,461 514 Support equipment depreciation 1,681 155 778 623 3,724 — 6,961 362 — Accumulated provisions 57,034 13,436 38,566 34,778 12,754 602 157,170 8,893 514 Net Capitalized Costs $ 36,132 $ 11,727 $ 11,043 $ 14,638 $ 33,116 $ 1,652 $ 108,308 $ 25,814 $ 1,075 103 Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents Table III - Results of Operations for Oil and Gas Producing Activities 1 The company’s results of operations from oil and gas producing activities for the years 2023, 2022 and 2021 are shown in the following table. Net income (loss) from exploration and production activities as reported on page 79 reflects income taxes computed on an effective rate basis. Income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense are excluded from the results reported in Table III and from the upstream net income amounts on page 79. Consolidated Companies Affiliated Companies Other Millions of dollars U.S. Americas Africa Asia Australia Europe Total TCO Other Year Ended December 31, 2023 Revenues from net production Sales $ 6,658 $ 724 $ 515 $ 3,309 $ 6,780 $ 368 $ 18,354 $ 6,831 $ 891 Transfers 15,948 3,243 5,979 2,151 4,753 — 32,074 — — Total 22,606 3,967 6,494 5,460 11,533 368 50,428 6,831 891 Production expenses excluding taxes (5,459) (1,000) (1,619) (1,103) (556) (64) (9,801) (602) (44) Taxes other than on income (1,222) (69) (142) (27) (256) (4) (1,720) (675) — Proved producing properties: Depreciation and depletion (7,133) (1,042) (1,414) (1,114) (2,561) (115) (13,379) (895) (173) Accretion expense 2 (176) (25) (126) (120) (92) (8) (547) (7) (3) Exploration expenses (439) (274) (151) (33) (32) (5) (934) — — Unproved properties valuation (71) (68) (44) — — — (183) — — Other income (loss) 3 (2,673) (69) 45 89 (52) 4 (2,656) 32 (185) Results before income taxes 5,433 1,420 3,043 3,152 7,984 176 21,208 4,684 486 Income tax (expense) benefit (1,195) (389) (832) (1,576) (2,776) (196) (6,964) (1,408) 24 Results of Producing Operations $ 4,238 $ 1,031 $ 2,211 $ 1,576 $ 5,208 $ (20) $ 14,244 $ 3,276 $ 510 Year Ended December 31, 2022 Revenues from net production Sales $ 9,656 $ 1,172 $ 2,192 $ 3,963 $ 7,302 $ 564 $ 24,849 $ 8,304 $ 2,080 Transfers 18,494 3,801 6,829 2,477 7,535 — 39,136 — — Total 28,150 4,973 9,021 6,440 14,837 564 63,985 8,304 2,080 Production expenses excluding taxes (4,752) (1,071) (1,515) (1,316) (614) (60) (9,328) (485) (47) Taxes other than on income (1,286) (85) (170) (52) (352) (4) (1,949) (933) — Proved producing properties: Depreciation and depletion (4,612) (1,223) (1,943) (1,765) (2,520) (117) (12,180) (964) (164) Accretion expense 2 (167) (22) (147) (87) (77) (11) (511) (6) (3) Exploration expenses (402) (169) (243) (92) (52) (2) (960) — — Unproved properties valuation (38) (250) (15) (124) — — (427) — — Other income (loss) 3 92 21 300 180 51 105 749 195 (27) Results before income taxes 16,985 2,174 5,288 3,184 11,273 475 39,379 6,111 1,839 Income tax (expense) benefit (3,736) (670) (3,114) (1,742) (3,185) (193) (12,640) (1,835) 12 Results of Producing Operations $ 13,249 $ 1,504 $ 2,174 $ 1,442 $ 8,088 $ 282 $ 26,739 $ 4,276 $ 1,851 1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations. 2 Represents accretion of ARO liability. Refer to Note 25 Asset Retirement Obligations . 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. 104 Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents Table III - Results of Operations for Oil and Gas Producing Activities 1 , continued Consolidated Companies Affiliated Companies Other Millions of dollars U.S. Americas Africa Asia Australia Europe Total TCO Other Year Ended December 31, 2021 Revenues from net production Sales $ 6,708 $ 888 $ 1,283 $ 5,127 $ 3,725 $ 371 $ 18,102 $ 5,564 $ 868 Transfers 12,653 3,029 5,232 3,019 3,858 — 27,791 — — Total 19,361 3,917 6,515 8,146 7,583 371 45,893 5,564 868 Production expenses excluding taxes (4,325) (974) (1,414) (2,156) (548) (67) (9,484) (487) (20) Taxes other than on income (928) (73) (88) (15) (260) (4) (1,368) (359) — Proved producing properties: Depreciation and depletion (5,184) (1,470) (1,797) (3,324) (2,409) (105) (14,289) (947) (215) Accretion expense 2 (197) (22) (144) (113) (75) (13) (564) (7) (3) Exploration expenses (221) (132) (83) (20) (47) (35) (538) — — Unproved properties valuation (43) (95) (5) — — — (143) — — Other income (loss) 3 990 (33) (72) (124) 26 2 789 98 (332) Results before income taxes 9,453 1,118 2,912 2,394 4,270 149 20,296 3,862 298 Income tax (expense) benefit (2,108) (318) (1,239) (1,326) (1,314) (38) (6,343) (1,161) 29 Results of Producing Operations $ 7,345 $ 800 $ 1,673 $ 1,068 $ 2,956 $ 111 $ 13,953 $ 2,701 $ 327 1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations. 2 Represents accretion of ARO liability. Refer to Note 25 Asset Retirement Obligations . 3 Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses. Table IV - Results of Operations for Oil and Gas Producing Activities - Unit Prices and Costs 1 Consolidated Companies Affiliated Companies Other U.S. Americas Africa Asia Australia Europe Total TCO Other Year Ended December 31, 2023 Average sales prices Crude, per barrel $ 74.36 $ 72.85 $ 72.86 $ 70.05 $ 78.93 $ 83.00 $ 73.76 $ 66.44 $ — Natural gas liquids, per barrel 20.01 29.00 27.80 — 51.00 — 20.79 9.43 45.33 Natural gas, per thousand cubic feet 1.65 2.63 3.95 4.10 11.43 12.00 6.01 1.31 10.34 Average production costs, per barrel 2 11.19 16.13 16.35 7.82 3.41 12.80 10.23 4.47 2.94 Year Ended December 31, 2022 Average sales prices Crude, per barrel $ 91.88 $ 90.04 $ 100.82 $ 85.64 $ 98.00 $ 102.00 $ 92.92 $ 85.71 $ — Natural gas liquids, per barrel 33.76 34.33 35.43 — — — 34.31 20.83 65.33 Natural gas, per thousand cubic feet 5.53 5.15 9.00 4.02 15.34 27.00 8.85 0.95 29.44 Average production costs, per barrel 2 11.10 17.00 14.43 8.49 3.79 12.00 10.16 3.85 3.36 Year Ended December 31, 2021 Average sales prices Crude, per barrel $ 65.16 $ 62.84 $ 72.38 $ 63.71 $ 71.40 $ 69.20 $ 66.14 $ 58.31 $ — Natural gas liquids, per barrel 28.54 26.33 39.40 — 30.00 — 29.10 27.13 66.00 Natural gas, per thousand cubic feet 3.02 3.39 2.66 4.10 8.22 12.50 5.08 0.47 9.71 Average production costs, per barrel 2 10.45 13.91 12.40 10.52 3.65 13.40 9.90 4.09 1.25 1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations. 2 Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel. 105 Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents Table V Proved Reserve Quantity Information * Summary of Net Oil and Gas Reserves 2023 2022 2021 Liquids in Millions of Barrels Natural Gas in Billions of Cubic Feet Crude Oil Condensate SyntheticOil NGL Natural Gas Crude Oil Condensate SyntheticOil NGL Natural Gas Crude Oil Condensate SyntheticOil NGL Natural Gas Proved Developed Consolidated Companies U.S. 1,221 — 611 4,543 1,198 — 450 3,288 1,177 — 421 3,136 Other Americas 195 598 7 298 174 574 7 305 181 471 7 259 Africa 367 — 70 1,632 392 — 72 1,734 428 — 77 1,884 Asia 240 — — 6,974 235 — — 6,578 270 — — 7,007 Australia 85 — 2 6,951 99 — 3 7,898 102 — 3 8,057 Europe 25 — — 9 26 — — 9 24 — — 8 Total Consolidated 2,133 598 690 20,407 2,124 574 532 19,812 2,182 471 508 20,351 Affiliated Companies TCO 478 — 67 1,062 515 — 52 895 555 — 52 1,059 Other 3 — 13 323 3 — 13 349 3 — 13 310 Total Consolidated and Affiliated Companies 2,614 598 770 21,792 2,642 574 597 21,056 2,740 471 573 21,720 Proved Undeveloped Consolidated Companies U.S. 721 — 413 3,139 875 — 435 3,543 887 — 391 2,749 Other Americas 129 — 8 276 121 — 10 240 107 — 8 196 Africa 78 — 27 625 62 — 25 756 52 — 28 912 Asia 61 — — 1,419 58 — — 1,959 52 — — 466 Australia 22 — — 2,444 22 — — 2,444 32 — — 3,627 Europe 28 — — 8 32 — — 11 38 — — 13 Total Consolidated 1,039 — 448 7,911 1,170 — 470 8,953 1,168 — 427 7,963 Affiliated Companies TCO 526 — 11 233 611 — 21 368 695 — 32 642 Other — — — 445 — — — 487 1 — 6 583 Total Consolidated and Affiliated Companies 1,565 — 459 8,589 1,781 — 491 9,808 1,864 — 465 9,188 Total Proved Reserves 4,179 598 1,229 30,381 4,423 574 1,088 30,864 4,604 471 1,038 30,908 * Reserve quantities include natural gas projected to be consumed in operations of 2,655, 2,737 and 2,505 billions of cubic feet and equivalent 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. Reserves Governance The company has adopted a comprehensive reserves and resources classification system modeled after a system developed and approved by a number of organizations, including the Society of Petroleum Engineers, the World Petroleum Congress and the American Association of Petroleum Geologists. The company classifies discovered recoverable hydrocarbons into six categories based on their status at the time of reporting – three deemed commercial and three potentially recoverable. Within the commercial classification are proved reserves and two categories of unproved reserves: probable and possible. The potentially recoverable categories are also referred to as contingent resources. For reserves estimates to be classified as proved, they must meet all SEC and company standards. Proved oil and gas reserves are the estimated quantities that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in the future from known reservoirs under existing economic conditions, operating methods and government regulations. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate. Proved reserves are classified as either developed or undeveloped. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are the quantities expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available. 106 Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents Proved reserves are estimated by company asset teams composed of earth scientists and engineers. As part of the internal control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired by the Manager of Global Reserves, an organization that is separate from the business units that estimate reserves. The Manager of Global Reserves has more than 30 years of experience working in the oil and gas industry and holds both undergraduate and graduate degrees in geoscience. His experience includes various technical and management roles in providing reserve and resource estimates in support of major capital and exploration projects, and more than 10 years of overseeing oil and gas reserves processes. He has been named a Distinguished Lecturer by the American Association of Petroleum Geologists and is an active member of the American Association of Petroleum Geologists, the SEPM Society of Sedimentary Geologists and the Society of Petroleum Engineers. All RAC members are degreed professionals, each with more than 10 years of experience in various aspects of reserves estimation relating to reservoir engineering, petroleum engineering, earth science or finance. The members are knowledgeable in SEC guidelines for proved reserves classification and receive annual training on the preparation of reserves estimates. The RAC has the following primary responsibilities: establish the policies and processes used within the business units to estimate reserves; provide independent reviews and oversight of the business units’ recommended reserves estimates and changes; confirm that proved reserves are recognized in accordance with SEC guidelines; determine that reserve quantities are calculated using consistent and appropriate standards, procedures and technology; and maintain the Chevron Corporation Reserves Manual , which provides standardized procedures used corporatewide for classifying and reporting hydrocarbon reserves. During the year, the RAC is represented in meetings with each of the company’s business units to review and discuss reserve changes recommended by the various asset teams. Major changes are also reviewed with the company’s senior leadership team including the Chief Executive Officer and the Chief Financial Officer. The company’s annual reserves activity is also reviewed with the Board Audit Committee and the Board of Directors. If major changes to reserves were to occur between the annual reviews, those matters would also be discussed with the Board. 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 . Technologies Used in Establishing Proved Reserves Additions In 2023, additions to Chevron’s proved reserves were based on a wide range of geologic and engineering technologies. Information generated from wells, such as well logs, wire line sampling, production and pressure testing, fluid analysis, and core analysis, was integrated with seismic data, regional geologic studies, and information from analogous reservoirs to provide “reasonably certain” proved reserves estimates. Both proprietary and commercially available analytic tools, including reservoir simulation, geologic modeling and seismic processing, have been used in the interpretation of the subsurface data. These technologies have been utilized extensively by the company in the past, and the company believes that they provide a high degree of confidence in establishing reliable and consistent reserves estimates. Proved Undeveloped Reserves Noteworthy changes in proved undeveloped reserves are shown in the table below and discussed below. Proved Undeveloped Reserves (Millions of BOE) 2023 Quantity at January 1 3,907 Revisions (481) Improved recovery — Extension and discoveries 314 Purchases 312 Sales — Transfers to proved developed (596) Quantity at December 31 3,456 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 107 Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents to proved developed reserves in existing wells. These reductions were partially offset by an increase of 49 million BOE in Israel mainly due to the final investment decision on a new gas pipeline project. In 2023, extensions and discoveries of 258 million BOE in the United States were primarily due to planned development of new locations in shale and tight assets in the Midland and Delaware basins of 173 million BOE and the DJ basin of 49 million BOE, and deepwater assets in the Gulf of Mexico of 36 million BOE. In Other Americas, 57 million BOE of extensions and discoveries were mainly from shale and tight assets in Argentina. In 2023, purchases of 301 million BOE in the United States are primarily from the acquisition of PDC. 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. 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. During 2023, investments totaling approximately $9.1 billion in oil and gas producing activities and about $0.1 billion in non-oil and gas producing activities were expended to advance the development of proved undeveloped reserves. The United States accounted for about $5.0 billion primarily related to various development activities in the Midland and Delaware basins and the Gulf of Mexico. In Asia, expenditures during the year totaled approximately $2.5 billion, primarily related to development projects for TCO in Kazakhstan. An additional $0.3 billion were spent on development activities in Australia. In Africa, about $0.7 billion was expended on various offshore development and natural gas projects in Nigeria, Angola and Republic of Congo. 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. These factors may include the complex nature of the development project in adverse and remote locations, physical limitations of infrastructure or plant capacities that dictate project timing, compression projects that are pending reservoir pressure declines, and contractual limitations that dictate production levels. At year-end 2023, the company held approximately 1 billion BOE of proved undeveloped reserves that have remained undeveloped for five years or more. The majority of these reserves are in locations where the company has a proven track record of developing major projects. In Australia, approximately 235 million BOE remain undeveloped for five years or more related to the Gorgon and Wheatstone Projects. Further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with operating constraints, reservoir depletion and infrastructure optimization. In Africa, approximately 137 million BOE have remained undeveloped for five years or more, primarily due to facility constraints at various fields and infrastructure associated with the Escravos gas projects in Nigeria. Affiliates account for about 650 million BOE of proved undeveloped reserves with about 575 million BOE that have remained undeveloped for five years or more. Approximately 511 million BOE are related to TCO in Kazakhstan and about 64 million BOE are related to Angola LNG. At TCO and Angola LNG, further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with reservoir depletion and facility constraints. Annually, the company assesses whether any changes have occurred in facts or circumstances, such as changes to development plans, regulations, or government policies, that would warrant a revision to reserve estimates. In 2023, lower commodity prices negatively impacted the economic limits of oil and gas properties, resulting in a proved reserve decrease of approximately 135 million BOE, and positively impacted proved reserves due to entitlement effects, resulting in a proved reserves increase of approximately 89 million BOE. The year-end reserves quantities have been updated for these circumstances and significant changes have been discussed in the appropriate reserves sections. 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 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 108 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 (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 2021, the 206 million barrels increase in United States was primarily in the Gulf of Mexico and the Midland and Delaware basins. The higher commodity price environment led to the increase of 126 million barrels in the Gulf of Mexico primarily from Anchor and a 68 million barrels increase in the Midland and Delaware basins due to higher planned development activity. In TCO, entitlement effects and technical changes in field operating assumptions, reservoir model, and project schedule were primarily responsible for the 208 million barrels decrease in Kazakhstan. Entitlement effects primarily contributed to a decrease of 106 million barrels of synthetic oil at the Athabasca Oil Sands project in Canada. In the Other Americas, performance revisions and price effects, mainly in Canada and Argentina, were primarily responsible for the 41 million barrels increase. In 2022, entitlement effects primarily contributed to a decrease of 49 million barrels of synthetic oil at the Athabasca Oil Sands project in Canada. In TCO, entitlement effects and changes in operating assumptions were primarily responsible for the 35 million barrels decrease in Kazakhstan. In 2023, the 257 million barrels decrease in United States was primarily in the Midland and Delaware basins and California. 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. 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. 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. 109 Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents Net Proved Reserves of Crude Oil, Condensate and Synthetic Oil Consolidated Companies Affiliated Companies Total Consolidated Other Synthetic Synthetic and Affiliated Millions of barrels U.S. Americas 1 Africa Asia Australia Europe Oil 2,5 Total TCO Oil Other 3 Companies Reserves at January 1, 2021 1,750 260 554 403 141 61 597 3,766 1,550 — 3 5,319 Changes attributable to: Revisions 206 41 10 (8) 8 6 (106) 157 (208) — 2 (49) Improved recovery — 9 — — — — — 9 — — — 9 Extensions and discoveries 349 16 — — — — — 365 — — — 365 Purchases 26 — — 2 — — — 28 — — — 28 Sales (32) — — (1) — — — (33) — — — (33) Production (235) (38) (84) (74) (15) (5) (20) (471) (92) — (1) (564) Reserves at December 31, 2021 4, 5 2,064 288 480 322 134 62 471 3,821 1,250 — 4 5,075 Changes attributable to: Revisions (26) (9) 4 8 2 1 (49) (69) (35) — — (104) Improved recovery 2 15 4 5 — — — 26 — — — 26 Extensions and discoveries 264 32 6 — — — — 302 10 — — 312 Purchases 22 5 36 — — — 168 231 — — — 231 Sales (16) — (3) — — — — (19) — — — (19) Production (237) (36) (73) (42) (15) (5) (16) (424) (99) — (1) (524) Reserves at December 31, 2022 4, 5 2,073 295 454 293 121 58 574 3,868 1,126 — 3 4,997 Changes attributable to: Revisions (257) 9 37 48 1 (1) 42 (121) (20) — 1 (140) Improved recovery 9 — 2 — — — — 11 — — — 11 Extensions and discoveries 170 55 — — — — — 225 — — — 225 Purchases 207 — 24 — — — — 231 — — — 231 Sales (1) — — — — — — (1) — — — (1) Production (259) (35) (72) (40) (15) (4) (18) (443) (102) — (1) (546) Reserves at December 31, 2023 4, 5 1,942 324 445 301 107 53 598 3,770 1,004 — 3 4,777 1 Ending reserve balances in North America were 188, 185 and 183 and in South America were 136, 110 and 105 in 2023, 2022 and 2021, respectively. 2 Reserves associated with Canada. 3 Reserves associated with Africa. 4 Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to page E-8 for the definition of a PSC). PSC-related reserve quantities are 6 percent, 6 percent and 7 percent for consolidated companies for 2023, 2022 and 2021, respectively. 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 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 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. 110 Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents Net Proved Reserves of Natural Gas Liquids Consolidated Companies Affiliated Companies Total Consolidated Other and Affiliated Millions of barrels U.S. Americas 1 Africa Asia Australia Europe Total TCO Other 2 Companies Reserves at January 1, 2021 593 8 104 — 4 — 709 102 17 828 Changes attributable to: Revisions 107 5 8 — — — 120 (10) 4 114 Improved recovery — — — — — — — — — — Extensions and discoveries 190 4 — — — — 194 — — 194 Purchases 8 — — — — — 8 — — 8 Sales (8) — — — — — (8) — — (8) Production (78) (2) (6) — (1) — (87) (8) (3) (98) Reserves at December 31, 2021 3 812 15 106 — 3 — 936 84 18 1,038 Changes attributable to: Revisions 18 — (3) — — — 15 (5) (3) 7 Improved recovery — — — — — — — — — — Extensions and discoveries 163 2 1 — — — 166 — — 166 Purchases 14 2 — — — — 16 — — 16 Sales (35) — — — — — (35) — — (35) Production (87) (2) (7) — — — (96) (6) (2) (104) Reserves at December 31, 2022 3 885 17 97 — 3 — 1,002 73 13 1,088 Changes attributable to: Revisions (110) — (6) — — — (116) 12 2 (102) Improved recovery — — — — — — — — — — Extensions and discoveries 92 — — — — — 92 — — 92 Purchases 262 — 11 — — — 273 — — 273 Sales — — — — — — — — — — Production (105) (2) (5) — (1) — (113) (7) (2) (122) Reserves at December 31, 2023 3 1,024 15 97 — 2 — 1,138 78 13 1,229 1 Reserves associated with North America. 2 Reserves associated with Africa. 3 Year-end reserve quantities related to PSC are not material for 2023, 2022 and 2021, respectively. 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 2021, the approval of the Jansz Io Compression project was mainly responsible for the 1.2 trillion cubic feet (TCF) increase in Australia. Higher commodity prices, resulting in the increase of planned development activity in the Midland and Delaware basins, were mainly responsible for the 829 billion cubic feet (BCF) increase in the United States. In TCO, entitlement effects and technical changes in field operating assumptions, reservoir model, and project schedule were primarily responsible for the 179 BCF decrease. In 2022, the performance of the Leviathan and Tamar fields in Israel and the Bibiyana and Jalalabad fields in Bangladesh were mainly responsible for the 1.8 TCF increase in Asia. In Australia, the 377 BCF decrease was mainly due to updated reservoir characterization of the Wheatstone field. In TCO, entitlement effects and changes in operating assumptions were primarily responsible for the 285 BCF decrease. In 2023, portfolio optimization decrease of 276 BCF and a reservoir performance decrease of 186 BCF in the Midland and Delaware basins along with a reduction in planned development activities leading to a decrease of 485 BCF in the Haynesville shale formation of east Texas, were mainly responsible for the 1.2 TCF decrease in the United States. 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. 111 Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents In 2023, extensions and discoveries of 660 BCF in the United States were primarily in the Midland and Delaware basins. 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 Consolidated Companies Affiliated Companies Total Consolidated Other and Affiliated Billions of cubic feet (BCF) U.S. Americas 1 Africa Asia Australia Europe Total TCO Other 2 Companies Reserves at January 1, 2021 4,250 329 2,837 8,183 11,385 22 27,006 2,018 898 29,922 Changes attributable to: Revisions 829 129 147 119 1,181 1 2,406 (179) 82 2,309 Improved recovery — — — — — — — — — — Extensions and discoveries 1,408 63 — — 19 — 1,490 — — 1,490 Purchases 44 — — — — — 44 — — 44 Sales (29) — — — (13) — (42) — — (42) Production 3 (617) (66) (188) (829) (888) (2) (2,590) (138) (87) (2,815) Reserves at December 31, 2021 4, 5 5,885 455 2,796 7,473 11,684 21 28,314 1,701 893 30,908 Changes attributable to: Revisions 171 62 (118) 1,765 (377) 2 1,505 (285) 3 1,223 Improved recovery 1 — — — — — 1 — — 1 Extensions and discoveries 1,573 64 — — — — 1,637 — 17 1,654 Purchases 85 25 30 — — — 140 — — 140 Sales (243) — (11) — — — (254) — — (254) Production 3 (641) (61) (207) (701) (965) (3) (2,578) (153) (77) (2,808) Reserves at December 31, 2022 4, 5 6,831 545 2,490 8,537 10,342 20 28,765 1,263 836 30,864 Changes attributable to: Revisions (1,198) (1) (154) 481 31 1 (840) 166 18 (656) Improved recovery 2 — — — — — 2 — — 2 Extensions and discoveries 660 83 — — — — 743 — — 743 Purchases 2,161 — 97 — — — 2,258 — — 2,258 Sales (3) — — — — — (3) — — (3) Production 3 (771) (53) (176) (625) (978) (4) (2,607) (134) (86) (2,827) Reserves at December 31, 2023 4, 5 7,682 574 2,257 8,393 9,395 17 28,318 1,295 768 30,381 1 Ending reserve balances in North America and South America were 363, 407 and 347 and 211, 138 and 108 in 2023, 2022 and 2021, respectively. 2 Reserves associated with Africa. 3 Total “as sold” volumes are 2,609, 2,600 and 2,599 for 2023, 2022 and 2021, respectively. 4 Includes reserve quantities related to PSC. PSC-related reserve quantities are 7 percent, 8 percent and 8 percent for consolidated companies for 2023, 2022 and 2021, respectively. 5 Reserve quantities include natural gas projected to be consumed in operations of 2,655, 2,737 and 2,505 billions of cubic feet as of December 31, 2023, 2022 and 2021, respectively. 112 Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents Table VI - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves The standardized measure of discounted future net cash flows is calculated in accordance with SEC and FASB requirements. This includes using the average of first-day-of-the-month oil and gas prices for the 12-month period prior to the end of the reporting period, estimated future development and production costs assuming the continuation of existing economic conditions, estimated costs for asset retirement obligations (includes costs to retire existing wells and facilities in addition to those future wells and facilities necessary to produce proved undeveloped reserves), and estimated future income taxes based on appropriate statutory tax rates. Discounted future net cash flows are calculated using 10 percent mid-period discount factors. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. The valuation requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and do not represent management’s estimate of the company’s future cash flows or value of its oil and gas reserves. In the following table, the caption “Standardized Measure Net Cash Flows” refers to the standardized measure of discounted future net cash flows. Consolidated Companies Affiliated Companies Total Consolidated Other and Affiliated Millions of dollars U.S. Americas Africa Asia Australia Europe Total TCO Other Companies At December 31, 2023 Future cash inflows from production $ 181,152 $ 65,265 $ 42,786 $ 62,094 $ 99,003 $ 4,395 $ 454,695 $ 74,758 $ 7,324 $ 536,777 Future production costs (48,784) (22,549) (16,502) (13,000) (11,534) (1,194) (113,563) (21,467) (484) (135,514) Future development costs (16,938) (3,538) (4,474) (2,845) (5,804) (438) (34,037) (3,617) (67) (37,721) Future income taxes (21,089) (10,337) (12,446) (27,415) (24,499) (1,160) (96,946) (14,902) (2,371) (114,219) Undiscounted future net cash flows 94,341 28,841 9,364 18,834 57,166 1,603 210,149 34,772 4,402 249,323 10 percent midyear annual discount for timing of estimated cash flows (39,553) (16,623) (3,262) (9,343) (22,011) (600) (91,392) (11,283) (1,640) (104,315) Standardized Measure Net Cash Flows $ 54,788 $ 12,218 $ 6,102 $ 9,491 $ 35,155 $ 1,003 $ 118,757 $ 23,489 $ 2,762 $ 145,008 At December 31, 2022 Future cash inflows from production $ 257,478 $ 76,940 $ 55,865 $ 67,188 $ 147,839 $ 5,920 $ 611,230 $ 106,114 $ 22,630 $ 739,974 Future production costs (51,022) (22,744) (16,373) (12,261) (13,313) (1,069) (116,782) (28,046) (574) (145,402) Future development costs (20,907) (3,233) (2,657) (2,879) (5,030) (502) (35,208) (4,127) (8) (39,343) Future income taxes (40,096) (13,207) (26,160) (30,674) (38,861) (2,827) (151,825) (22,182) (7,707) (181,714) Undiscounted future net cash flows 145,453 37,756 10,675 21,374 90,635 1,522 307,415 51,759 14,341 373,515 10 percent midyear annual discount for timing of estimated cash flows (62,918) (22,165) (3,001) (10,769) (37,519) (571) (136,943) (18,810) (5,824) (161,577) Standardized Measure Net Cash Flows $ 82,535 $ 15,591 $ 7,674 $ 10,605 $ 53,116 $ 951 $ 170,472 $ 32,949 $ 8,517 $ 211,938 At December 31, 2021 Future cash inflows from production $ 174,976 $ 48,328 $ 41,698 $ 52,881 $ 87,676 $ 4,366 $ 409,925 $ 80,297 $ 8,446 $ 498,668 Future production costs (40,009) (16,204) (15,204) (13,871) (13,726) (1,400) (100,414) (23,354) (285) (124,053) Future development costs (16,709) (2,707) (2,245) (2,774) (5,283) (661) (30,379) (5,066) (18) (35,463) Future income taxes (24,182) (7,723) (17,228) (21,064) (20,600) (922) (91,719) (15,563) (2,850) (110,132) Undiscounted future net cash flows 94,076 21,694 7,021 15,172 48,067 1,383 187,413 36,314 5,293 229,020 10 percent midyear annual discount for timing of estimated cash flows (41,357) (11,370) (1,899) (7,277) (21,141) (485) (83,529) (14,372) (2,244) (100,145) Standardized Measure Net Cash Flows $ 52,719 $ 10,324 $ 5,122 $ 7,895 $ 26,926 $ 898 $ 103,884 $ 21,942 $ 3,049 $ 128,875 113 Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents Table VII - Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs. Changes in the timing of production are included with “Revisions of previous quantity estimates.” Total Consolidated and Millions of dollars Consolidated Companies Affiliated Companies Affiliated Companies Present Value at January 1, 2021 $ 48,443 $ 10,094 $ 58,537 Sales and transfers of oil and gas produced net of production costs (34,668) (5,760) (40,428) Development costs incurred 5,770 2,445 8,215 Purchases of reserves 772 — 772 Sales of reserves (889) — (889) Extensions, discoveries and improved recovery less related costs 12,091 — 12,091 Revisions of previous quantity estimates 2,269 (6,675) (4,406) Net changes in prices, development and production costs 89,031 30,076 119,107 Accretion of discount 6,657 1,503 8,160 Net change in income tax (25,592) (6,692) (32,284) Net Change for 2021 55,441 14,897 70,338 Present Value at December 31, 2021 $ 103,884 $ 24,991 $ 128,875 Sales and transfers of oil and gas produced net of production costs (53,356) (9,127) (62,483) Development costs incurred 7,962 2,430 10,392 Purchases of reserves 2,248 — 2,248 Sales of reserves (1,807) — (1,807) Extensions, discoveries and improved recovery less related costs 16,054 823 16,877 Revisions of previous quantity estimates 5,281 (1,481) 3,800 Net changes in prices, development and production costs 110,467 28,052 138,519 Accretion of discount 14,075 3,429 17,504 Net change in income tax (34,336) (7,651) (41,987) Net Change for 2022 66,588 16,475 83,063 Present Value at December 31, 2022 $ 170,472 $ 41,466 $ 211,938 Sales and transfers of oil and gas produced net of production costs (38,638) (6,350) (44,988) Development costs incurred 11,381 2,281 13,662 Purchases of reserves 9,628 — 9,628 Sales of reserves (51) — (51) Extensions, discoveries and improved recovery less related costs 7,262 — 7,262 Revisions of previous quantity estimates (14,389) (493) (14,882) Net changes in prices, development and production costs (80,284) (23,517) (103,801) Accretion of discount 23,306 5,722 29,028 Net change in income tax 30,070 7,142 37,212 Net Change for 2023 (51,715) (15,215) (66,930) Present Value at December 31, 2023 $ 118,757 $ 26,251 $ 145,008 114 Table of Contents PART IV Item 15. Exhibit and Financial Statement Schedules (a) The following documents are filed as part of this report: (1) Financial Statements: Page(s) Report of Independent Registered Public Accounting Firm — PricewaterhouseCoopers LLP 60 Consolidated Statement of Income for the three years ended December 31, 2023 62 Consolidated Statement of Comprehensive Income for the three years ended December 31, 2023 63 Consolidated Balance Sheet at December 31, 2023 and 2022 64 Consolidated Statement of Cash Flows for the three years ended December 31, 2023 65 Consolidated Statement of Equity for the three years ended December 31, 2023 66 Notes to the Consolidated Financial Statements 67 to 101 (2) Financial Statement Schedules: Included below is Schedule II - Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2023. (3) Exhibits: The Exhibit Index on the following pages lists the exhibits that are filed as part of this report. Schedule II — Valuation and Qualifying Accounts Year ended December 31 Millions of Dollars 2023 2022 2021 Employee Termination Benefits Balance at January 1 $ 11 $ 43 $ 470 Additions (reductions) charged to expense ( 2 ) 1 ( 30 ) Payments ( 3 ) ( 33 ) ( 397 ) Balance at December 31 $ 6 $ 11 $ 43 Expected Credit Losses Beginning allowance balance for expected credit losses $ 1,008 $ 745 $ 671 Current period provision ( 367 ) 263 74 Write-offs charged against the allowance, if any — — — Balance at December 31 $ 641 $ 1,008 $ 745 Deferred Income Tax Valuation Allowance * Balance at January 1 $ 19,532 $ 17,651 $ 17,762 Additions to deferred income tax expense 2,348 3,533 3,691 Reduction of deferred income tax expense ( 1,464 ) ( 1,652 ) ( 3,802 ) Balance at December 31 $ 20,416 $ 19,532 $ 17,651 * See also Note 17 Taxes . Item 16. Form 10-K Summary Not applicable. 115 Table of Contents EXHIBIT INDEX Exhibit No. Description 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, 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. 4.2 Indenture dated as of May 11, 2020, between Chevron Corporation and Deutsche Bank Trust Company Americas, as trustee, filed as Exhibit 4.1 to Chevron Corporation’s Current Report on Form 8-K filed May 12, 2020, and incorporated herein by reference. 4.3 Indenture dated as of August 12, 2020, among Chevron U.S.A. Inc., Chevron Corporation, as guarantor, and Deutsche Bank Trust Company Americas, as trustee, filed as Exhibit 4.1 to Chevron Corporation’s Current Report on Form 8-K filed August 13, 2020, and incorporated herein by reference. 4.4 Confidential Stockholder Voting Policy of Chevron Corporation, filed as Exhibit 4.2 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference. 4.5 Description of Securities Registered under Section 12 of the Exchange Act, filed as Exhibit 4.4 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2019, and incorporated herein by reference. 10.1+ Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.1 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference. 10.2+ Amendment Number One to the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, and incorporated herein by reference. 10.3+ Form of Retainer Stock Option Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.17 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2009, and incorporated herein by reference. 10.4+ 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 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. 10.9+ Form of Performance Share Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed February 3, 2020, and incorporated herein by reference. 10.10+ Form of Standard Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.3 to Chevron Corporation’s Current Report on Form 8-K filed February 3, 2020, and incorporated herein by reference. 116 Table of Contents Exhibit No. Description 10.11+ Form of Special Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.3 to Chevron Corporation’s Current Report on Form 8-K filed February 4, 2019, and incorporated herein by reference. 10.12+ Form of Non-Qualified Stock Option Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.2 to Chevron Corporation’s Current Report on Form 8-K filed February 3, 2020, and incorporated herein by reference. 10.13+ Form of Stock Appreciation Rights Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.13 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 201 9 , and incorporated herein by reference. 10.14+ Chevron Corporation Deferred Compensation Plan for Management Employees, filed as Exhibit 10.5 to Chevron Corporation’s Current Report on Form 8-K filed December 13, 2005, and incorporated herein by reference. 10.15+ Chevron Corporation Deferred Compensation Plan for Management Employees II, amended and restated effective October 2, 2023, filed as Exhibit 10. 1 to Chevron Corporation’s Quarterly Report on Form 10- Q for the quarter ended September 30, 2023 , and incorporated herein by reference. 10.16+ Chevron Corporation Retirement Restoration Plan, amended and restated effective October 2, 2023, filed as Exhibit 10. 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, 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. Inc. and Michael K. Wirth, filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, and incorporated herein by reference. 10.21+ 2022 Long-Term Incentive Plan of Chevron Corporation, amended and restated effective October 2, 2023, filed as Exhibit 10. 4 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2023, and incorporated herein by reference. 10.22+ Form of Performance Share Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference. 10.23+ Form of Standard Restricted Stock Unit Award Agreement (s hare settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.2 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference. 10.24+ Form of Standard Restricted Stock Unit Award Agreement (cash settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.3 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference. 10.25+ Form of Special Restricted Stock Unit Award Agreement (share settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.4 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference. 10.26+ Form of Special Restricted Stock Unit Award Agreement (cash settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.5 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference. 10.27+ Form of Non-Qualified Stock Options Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.6 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference. 10.28+ Form of Stock Appreciation Right Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.7 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference. 10.29+ 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. 117 Table of Contents Exhibit No. Description 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. 21.1* Subsidiaries of Chevron Corporation (page E-1). 22.1* Subsidiary Issuer of Guaranteed Securities. 23.1* Consent of PricewaterhouseCoopers LLP (page E-2). 24.1* Power of Attorney for certain directors of Chevron Corporation, authorizing the signing of the Annual Report on Form 10-K on their behalf. 31.1* Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Executive Officer (page E-3). 31.2* Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Financial Officer (page E-4). 32.1** Rule 13a-14(b)/15d-14(b) Certification by the company’s Chief Executive Officer (page E-5). 32.2** Rule 13a-14(b)/15d-14(b) Certification by the company’s Chief Financial Officer (page E-6). 97.1+* Chevron Corporation Dodd-Frank Clawback Policy. 99.1* Definitions of Selected Energy and Financial Terms (pages E-7 through E-10). 101* Interactive data files (formatted as Inline XBRL). 104* Cover Page Interactive Data File (contained in Exhibit 101). ___________________________________________ + Indicates a management contract or compensatory plan or arrangement. * Filed herewith. ** Furnished herewith. Pursuant to Item 601(b)(4) of Regulation S-K, certain instruments with respect to the company’s long-term debt are not filed with this Annual Report on Form 10-K. A copy of any such instrument will be furnished to the Securities and Exchange Commission upon request. 118 Signatures Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 26th day of February, 2024. Chevron Corporation By: /s/ MICHAEL K. WIRTH Michael K. Wirth, Chairman of the Board and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 26th day of February, 2024. Principal Executive Officer (and Director) /s/ MICHAEL K. WIRTH Michael K. Wirth, Chairman of the Board and Chief Executive Officer Principal Financial Officer /s/ PIERRE R. BREBER Pierre R. Breber, Vice President and Chief Financial Officer Principal Accounting Officer /s/ ALANA K. KNOWLES Alana K. Knowles, Vice President and Controller * By: /s/ MARY A. FRANCIS Mary A. Francis, Attorney-in-Fact Directors WANDA M. AUSTIN * Wanda M. Austin JOHN B. FRANK * John B. Frank ALICE P. GAST * Alice P. Gast ENRIQUE HERNANDEZ, JR. * Enrique Hernandez, Jr. MARILLYN A. HEWSON * Marillyn A. Hewson JON M. HUNTSMAN JR. * Jon M. Huntsman Jr. CHARLES W. MOORMAN * Charles W. Moorman DAMBISA F. MOYO * Dambisa F. Moyo DEBRA REED-KLAGES * Debra Reed-Klages D. JAMES UMPLEBY III * D. James Umpleby III CYNTHIA J. WARNER * Cynthia J. Warner 119