Registrant’s telephone number, including area code ()
Securities registered pursuant to Section 12(b) of the Act:
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| Title of each class | | Trading Symbol | | Name of each exchange on which registered |
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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
þ No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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| ☑ | | Accelerated filer | | ☐ |
| Non-accelerated filer | ☐ | | Smaller reporting company | | |
| | | Emerging growth company | | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
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The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter — $ billion (As of June 28, 2024)
Number of Shares of Common Stock outstanding as of February 7, 2025 —
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
TABLE OF CONTENTS
CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION
FOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995
This Annual Report on Form 10-K of Chevron Corporation contains forward-looking statements relating to Chevron’s operations, assets, and strategy that are based on management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words or phrases such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “advances,” “commits,” “drives,” “aims,” “forecasts,” “projects,” “believes,” “approaches,” “seeks,” “schedules,” “estimates,” “positions,” “pursues,” “progress,” “may,” “can,” “could,” “should,” “will,” “budgets,” “outlook,” “trends,” “guidance,” “focus,” “on track,” “goals,” “objectives,” “strategies,” “opportunities,” “poised,” “potential,” “ambitions,” “future,” “aspires” and similar expressions, and variations or negatives of these words, are intended to identify such forward-looking statements, but not all forward-looking statements include such words. These statements are not guarantees of future performance and are subject to numerous risks, uncertainties and other factors, many of which are beyond the company’s control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: changing crude oil and natural gas prices and demand for the company’s products, and production curtailments due to market conditions; crude oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries and other producing countries; technological advancements; changes to government policies in the countries in which the company operates; public health crises, such as pandemics and epidemics, and any related government policies and actions; disruptions in the company’s global supply chain, including supply chain constraints and escalation of the cost of goods and services; changing economic, regulatory and political environments in the various countries in which the company operates; general domestic and international economic, market and political conditions, including the military conflict between Russia and Ukraine, the conflict in the Middle East and the global response to these hostilities; changing refining, marketing and chemicals margins; the company’s ability to realize anticipated cost savings and efficiencies associated with enterprise structural cost reduction initiatives; actions of competitors or regulators; timing of exploration expenses; changes in projected future cash flows; timing of crude oil liftings; uncertainties about the estimated quantities of crude oil, natural gas liquids and natural gas reserves; the competitiveness of alternate-energy sources or product substitutes; pace and scale of the development of large carbon capture and offset markets; the results of operations and financial condition of the company’s suppliers, vendors, partners and equity affiliates; the inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction or start-up of planned projects; the potential disruption or interruption of the company’s operations due to war, accidents, political events, civil unrest, severe weather, cyber threats, terrorist acts, or other natural or human causes beyond the company’s control; the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant operational, investment or product changes undertaken or required by existing or future environmental statutes and regulations, including international agreements and national or regional legislation and regulatory measures related to greenhouse gas emissions and climate change; the potential liability resulting from pending or future litigation; the risk that regulatory approvals and clearances related to the Hess Corporation (Hess) transaction are not obtained or are not obtained in a timely manner or are obtained subject to conditions that are not anticipated by the company and Hess; potential delays in consummating the Hess transaction, including as a result of the ongoing arbitration proceedings regarding preemptive rights in the Stabroek Block joint operating agreement; risks that such ongoing arbitration is not satisfactorily resolved and the potential transaction fails to be consummated; uncertainties as to whether the potential transaction, if consummated, will achieve its anticipated economic benefits, including as a result of risks associated with third party contracts containing material consent, anti-assignment, transfer or other provisions that may be related to the potential transaction that are not waived or otherwise satisfactorily resolved; the company’s ability to integrate Hess’ operations in a successful manner and in the expected time period; the possibility that any of the anticipated benefits and projected synergies of the potential transaction will not be realized or will not be realized within the expected time period; the company’s future acquisitions or dispositions of assets or shares or the delay or failure of such transactions to close based on required closing conditions; the potential for gains and losses from asset dispositions or impairments; government mandated sales, divestitures, recapitalizations, taxes and tax audits, tariffs, sanctions, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; higher inflation and related impacts; material reductions in corporate liquidity and access to debt markets; changes to the company’s capital allocation strategies; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; the company’s ability to identify and mitigate the risks and hazards inherent in operating in the global energy industry; and the factors set forth under the heading “Risk Factors” on pages 20 through 27 in this report, and as updated in the future. Other unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.
PART I
Item 1. Business
General Development of Business
Summary Description of Chevron
Chevron Corporation1, a Delaware corporation, manages its investments in subsidiaries and affiliates and provides administrative, financial, management and technology support to U.S. and international subsidiaries that engage in integrated energy and chemicals operations. Upstream operations consist primarily of exploring for, developing, producing and transporting crude oil and natural gas; processing, liquefaction, transportation and regasification associated with liquefied natural gas; transporting crude oil by major international oil export pipelines; transporting, storage and marketing of natural gas; carbon capture and storage; and a gas-to-liquids plant. Downstream operations consist primarily of refining crude oil into petroleum products; marketing of crude oil, refined products and lubricants; manufacturing and marketing of renewable fuels; transporting 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.
A list of the company’s significant subsidiaries is presented in Exhibit 21.1. Overview of Petroleum Industry
Petroleum industry operations and profitability are influenced by many factors. Prices for crude oil, natural gas, liquefied natural gas (LNG), petroleum products and petrochemicals are generally determined by supply and demand. Production levels from the members of Organization of Petroleum Exporting Countries (OPEC), Russia and the United States are the major factors in determining worldwide supply. Demand for crude oil and its products and for natural gas is largely driven by the conditions of local, national and global economies, although weather patterns, the pace of energy transition and taxation relative to other energy sources also play a significant part. Laws and governmental policies, particularly in the areas of taxation, energy and the environment, affect where and how companies invest, conduct their operations, select feedstocks, and formulate their products and, in some cases, limit their profits directly.
Strong competition exists in all sectors of the petroleum and petrochemical industries in supplying the energy, fuel and chemical needs of industry and individual consumers. In the upstream business, Chevron competes with fully integrated, major global petroleum companies, as well as independent and national petroleum companies, for the acquisition of crude oil and natural gas leases and other properties and for the equipment and labor required to develop and operate those properties. In its downstream business, Chevron competes with fully integrated, major petroleum companies, as well as independent refining and marketing, transportation and chemicals entities and national petroleum companies in the refining, manufacturing, sale and marketing of fuels, lubricants, additives and petrochemicals.
Operating Environment
Refer to Business Environment and Outlook of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the company’s current business environment and outlook. Chevron’s Strategic Direction
Chevron’s strategy is to leverage our strengths to safely deliver lower carbon energy to a growing world. Our objective is to safely deliver higher returns, lower carbon and superior shareholder value in any business environment. We are leveraging our capabilities, assets and customer relationships as we aim to lead in lower carbon intensity oil, products and natural gas, as well as advance new products and solutions that reduce the carbon emissions of major industries. We aim to grow our oil and gas business, lower the carbon intensity of our operations and grow new businesses in renewable fuels, carbon capture and offsets, hydrogen, power generation for data centers, and emerging technologies.
Information about the company is available on the company’s website at www.chevron.com. Information contained on the company’s website is not part of this Annual Report on Form 10-K. The company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to these reports filed or furnished pursuant to
1 Incorporated in Delaware in 1926 as Standard Oil Company of California, the company adopted the name Chevron Corporation in 1984 and ChevronTexaco Corporation in 2001. In 2005, ChevronTexaco Corporation changed its name to Chevron Corporation. As used in this report, the term “Chevron” and such terms as “the company,” “the corporation,” “our,” “we,” “us” and "its" may refer to Chevron Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole, but unless stated otherwise they do not include “affiliates” of Chevron — i.e., those companies accounted for by the equity method (generally owned 50 percent or less) or non-equity method investments. All of these terms are used for convenience only and are not intended as a precise description of any of the separate companies, each of which manages its own affairs.
Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available free of charge on the company’s website soon after such reports are filed with or furnished to the U.S. Securities and Exchange Commission (SEC). The reports are also available on the SEC’s website at www.sec.gov.
Human Capital Management
The Chevron Way explains the company’s beliefs, vision, purpose and values. It guides how the company’s employees work and establishes a common understanding of culture and aspirations.
Chevron leadership is accountable for investing in the company’s people and culture with the objective of engaging employees to develop their full potential to help deliver energy solutions and enable human progress. This includes reviews of metrics addressing critical function hiring, leadership development, retention, diversity and inclusion, and employee engagement.
The following table summarizes the number of Chevron employees by sex, where data is available, and by region as of December 31, 2024.
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| At December 31, 2024 |
| Female | Male | Data not available* | Total Employees |
| Number of Employees | Percentage | Number of Employees | Percentage | Number of Employees | Percentage | Number of Employees | Percentage |
| Non-Service Station Employees | | | | | | | | |
| U.S. | 5,556 | | 26 | % | 15,751 | | 74 | % | 19 | | — | % | 21,326 | | 47 | % |
| Other Americas | 1,175 | | 30 | % | 2,689 | | 69 | % | 10 | | — | % | 3,874 | | 9 | % |
| Africa | 623 | | 16 | % | 3,189 | | 84 | % | 4 | | — | % | 3,816 | | 8 | % |
| Asia | 2,577 | | 36 | % | 4,476 | | 63 | % | 13 | | — | % | 7,066 | | 16 | % |
| Australia | 542 | | 26 | % | 1,550 | | 74 | % | 3 | | — | % | 2,095 | | 5 | % |
| Europe | 434 | | 28 | % | 1,107 | | 71 | % | 24 | | 2 | % | 1,565 | | 3 | % |
| Total Non-Service Station Employees | 10,907 | | 27 | % | 28,762 | | 72 | % | 73 | | — | % | 39,742 | | 88 | % |
| Service Station Employees | 2,545 | | 46 | % | 2,372 | | 43 | % | 639 | | 12 | % | 5,556 | | 12 | % |
| Total Employees | 13,452 | | 30 | % | 31,134 | | 69 | % | 712 | | 2 | % | 45,298 | | 100 | % |
* Includes employees where data was not collected or employee chose not to disclose.
Hiring, Development and Retention
The company’s approach to attracting, developing and retaining a global, diverse workforce of high-performing talent is anchored by an environment of personal growth and engagement. The company’s philosophy is to offer compelling career opportunities and a competitive total compensation and benefits package linked to individual and enterprise performance. The company recruits new employees in a variety of ways, including through partnerships with universities and diversity associations. In addition, the company recruits experienced hires to provide specialized skills.
Chevron’s learning and development programs are designed to help employees build technical, operating and leadership capabilities. The company’s leadership reviews metrics on employee training and development programs, which are refined on an ongoing basis to meet the needs of the business. The company invests in developing leadership at every level, including coaching programs for frontline supervisors, managers and individual contributors. Chevron invests in developing and upskilling employees, including things such as tailored generative AI training for leaders, practitioners and the broader workforce. In addition, the company offers the Digital Scholar Program, preparing employees with advanced technology skills through one-year Master of Science degrees in Engineering and Management.
In addition, leadership reviews the talent pipeline, identifies and develops succession candidates, and builds succession plans for key positions. The Board of Directors provides oversight of CEO and executive succession planning.
Management routinely reviews the retention of its professional population, executives, all levels of management, and the majority of its regular employee population. The voluntary attrition for this population in 2024 was 3.1 percent, in line with historical rates. The voluntary attrition rate generally excludes employee departures under restructuring programs. Chevron believes its low voluntary attrition rate is in part a result of the company’s commitment to employee development, competitive pay and benefits, and culture.
Diversity and Inclusion
Chevron believes human ingenuity is best able to solve difficult problems when people with different ideas, experiences and backgrounds work together in an inclusive environment.
The company has 11 employee networks (voluntary groups open to all employees with shared interests). The Chairman’s Inclusion Council provides employee network presidents with a direct line of communication to the Chairman and Chief Executive Officer, the Chief Human Resources Officer, the Chief Diversity and Inclusion Officer, and the executive leadership team to discuss how employee networks can help reinforce the company’s values and achieve its business objectives.
Diversity and inclusion at Chevron means zero tolerance for discrimination based on race, sex or other protected characteristics, and a deep respect for the cultures in which we operate. Chevron rejects the use of quotas and focuses on removing barriers to equal opportunity, fostering diversity, and ensuring that selection decisions are based on merit.
Employee Engagement
Employee engagement is an indicator of employee well-being and commitment to the company’s values, purpose and strategies. The company regularly conducts employee surveys to assess the health of the company’s culture. Our surveys indicate high levels of employee engagement compared to our industry.
Chevron prioritizes the health, safety and well-being of its employees. The company’s safety culture empowers every member of its workforce to exercise stop-work authority without repercussion to address any potential unsafe work conditions. The company has set clear expectations for leaders to deliver operational excellence by prioritizing the safety and health of its workforce, and the protection of communities, the environment and the company’s assets.
Additionally, the company offers long-standing employee support programs such as Ombuds, an independent resource designed to equip employees with options to address and resolve workplace issues; a company hotline, where employees can report concerns to the Corporate Compliance department; and an Employee Assistance Program, a confidential consulting service that can help employees resolve a broad range of personal, family and work-related concerns.
Description of Business and Properties
The upstream and downstream activities of the company and its equity affiliates are widely dispersed geographically, with operations and projects2 in North America, South America, Europe, Africa, Asia and Australia. These activities are managed by the Oil, Products and Gas organization. Tabulations of segment income statements for the three years ended December 31, 2024, and assets as of the end of 2024 and 2023 — for the United States and the company’s international geographic areas — are in Note 14 Operating Segments and Geographic Data to the Consolidated Financial Statements. Similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are in Note 15 Investments and Advances and Note 18 Property, Plant and Equipment. Refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the company’s Capital Expenditures.
Upstream
Reserves
Refer to Table V for a tabulation of the company’s proved reserves by geographic area for each year-end from 2022 through 2024. Reserves governance, technologies used in establishing proved reserves additions, and major changes to proved reserves by geographic area for the three-year period ended December 31, 2024, are summarized in the discussion for Table V. Discussion is also provided regarding the nature of, status of, and planned future activities associated with the development of proved undeveloped reserves. The company recognizes reserves for projects with various development periods, sometimes exceeding five years. The external factors that impact the duration of a project include scope and complexity, remoteness or adverse operating conditions, infrastructure constraints, and contractual limitations. The company’s proved reserves at year-end 2024 were approximately 9.8 billion barrels of oil-equivalent (BOE). The largest reductions from year-end 2023 were from record production and the sale of assets in Canada, and the largest additions were from extensions and discoveries in the Permian and DJ Basins. At December 31, 2024, 41 percent of the company’s net proved oil-equivalent reserves were located in the United States, 16 percent were located in Australia and 13 percent were located in Kazakhstan.
The net proved reserve balances at the end of each of the three years 2022 through 2024 are shown in the following table:
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| At December 31 | |
| 2024 | | 2023 | | 2022 | |
| Crude Oil, Condensate and Synthetic Oil — Millions of barrels | | | | | | |
| Consolidated Companies | 3,027 | | | 3,770 | | | 3,868 | | |
| Affiliated Companies | 889 | | | 1,007 | | | 1,129 | | |
| Total Crude Oil, Condensate and Synthetic Oil | 3,916 | | | 4,777 | | | 4,997 | | |
| Natural Gas Liquids — Millions of barrels | | | | | | |
| Consolidated Companies | 1,075 | | | 1,138 | | | 1,002 | | |
| Affiliated Companies | 84 | | | 91 | | | 86 | | |
| Total Natural Gas Liquids | 1,159 | | | 1,229 | | | 1,088 | | |
| Natural Gas — Billions of cubic feet | | | | | | |
| Consolidated Companies | 26,526 | | | 28,318 | | | 28,765 | | |
| Affiliated Companies | 1,849 | | | 2,063 | | | 2,099 | | |
| Total Natural Gas | 28,375 | | | 30,381 | | | 30,864 | | |
Oil-Equivalent — Millions of barrels* | | | | | | |
| Consolidated Companies | 8,523 | | | 9,628 | | | 9,664 | | |
| Affiliated Companies | 1,281 | | | 1,441 | | | 1,565 | | |
| Total Oil-Equivalent | 9,804 | | | 11,069 | | | 11,229 | | |
* Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil.
2 As used in this report, the term “project” may describe certain new upstream development activity, individual phases in a multiphase development, maintenance activities, existing assets, new investments in downstream and chemicals capacity, investments in emerging and lower carbon activities, and other activities. All of these terms are used for convenience only and are not intended as a precise description of the term “project” as it relates to any specific governmental law or regulation.
Average Sales Prices and Production Costs per Unit of Production
Refer to Table IV for the company’s average sales price per barrel of crude (including crude oil and condensate) and natural gas liquids (NGLs) and per thousand cubic feet of natural gas produced, and the average production cost per oil-equivalent barrel for 2024, 2023 and 2022. Gross and Net Productive Wells
The following table summarizes gross and net productive wells at year-end 2024 for the company and its affiliates:
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| At December 31, 2024 | |
| Productive Oil Wells1 | Productive Gas Wells1 | |
| Gross | | Net | Gross | | Net | |
| United States | 35,135 | | | 24,099 | | 2,110 | | | 1,758 | | |
| Other Americas | 1,277 | | | 752 | | — | | | — | | |
| Africa | 1,679 | | | 653 | | 48 | | | 18 | | |
| Asia | 1,699 | | | 807 | | 1,309 | | | 405 | | |
| Australia | 532 | | | 299 | | 118 | | | 33 | | |
| Europe | 27 | | | 5 | | — | | | — | | |
| Total Consolidated Companies | 40,349 | | | 26,615 | | 3,585 | | | 2,214 | | |
Affiliates2 | 1,510 | | | 595 | | — | | | — | | |
| Total Including Affiliates | 41,859 | | | 27,210 | | 3,585 | | | 2,214 | | |
| Multiple completion wells included above | 659 | | | 355 | | 147 | | | 115 | | |
1 Gross wells represent the total number of wells in which Chevron has an ownership interest. Net wells represent the sum of Chevron’s ownership interest in gross wells. |
2 Includes gross 1,381 and net 466 productive oil wells for interests accounted for by the non-equity method. | |
Production Outlook
The company estimates its average worldwide oil-equivalent production in 2025 to increase six to eight percent over 2024, assuming a Brent crude oil price of $70 per barrel and excluding the impact of asset sales. This estimate is subject to many factors and uncertainties, as described beginning on page 40. Refer to the Review of Ongoing Exploration and Production Activities in Key Areas for a discussion of the company’s major crude oil and natural gas development projects. Acreage
At December 31, 2024, the company owned or had under lease or similar agreements undeveloped and developed crude oil and natural gas properties throughout the world. The geographical distribution of the company’s acreage is shown in the following table:
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| Undeveloped2 | | Developed | | Developed and Undeveloped | |
Thousands of acres1 | Gross | | Net | | Gross | | Net | | Gross | | Net | |
| United States | 4,294 | | | 3,700 | | | 4,273 | | | 2,856 | | | 8,567 | | | 6,556 | | |
| Other Americas | 16,503 | | | 11,078 | | | 920 | | | 232 | | | 17,423 | | | 11,310 | | |
| Africa | 13,433 | | | 7,098 | | | 1,320 | | | 530 | | | 14,753 | | | 7,628 | | |
| Asia | 13,373 | | | 7,440 | | | 934 | | | 363 | | | 14,307 | | | 7,803 | | |
| Australia | 3,384 | | | 2,628 | | | 2,246 | | | 899 | | | 5,630 | | | 3,527 | | |
| Europe | 106 | | | 21 | | | 12 | | | 2 | | | 118 | | | 23 | | |
| Total Consolidated Companies | 51,093 | | | 31,965 | | | 9,705 | | | 4,882 | | | 60,798 | | | 36,847 | | |
Affiliates3 | 693 | | | 287 | | | 111 | | | 51 | | | 804 | | | 338 | | |
| Total Including Affiliates | 51,786 | | | 32,252 | | | 9,816 | | | 4,933 | | | 61,602 | | | 37,185 | | |
1 Gross acres represent the total number of acres in which Chevron has an ownership interest. Net acres represent the sum of Chevron’s ownership interest in gross acres. | |
2 The gross undeveloped acres that will expire in 2025, 2026 and 2027 if production is not established by certain required dates are 2,951, 1,149, and 733, respectively. | |
3 Includes gross 405 and net 143 undeveloped and gross 19 and net 5 developed acreage for interests accounted for by the non-equity method. | |
Net Production of Crude Oil, Natural Gas Liquids and Natural Gas
The following table summarizes the net production of crude oil, NGLs and natural gas for 2024 and 2023 by the company and its affiliates. Worldwide oil-equivalent production of 3.3 million barrels per day in 2024 was up approximately seven percent from 2023, mainly due to the full-year of legacy PDC Energy, Inc. (PDC) production and growth in the Permian Basin. Refer to the Results of Operations section for a detailed discussion of the factors explaining the changes in production for liquids (including crude oil, condensate, NGLs and synthetic oil) and natural gas, and refer to Table V for information on annual production by geographical region. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Components of Oil-Equivalent | | | | | | |
| Oil-Equivalent | | Crude Oil | | Natural Gas Liquids | | Natural Gas | | | | | | |
| Thousands of barrels per day (MBD) | (MBD)1 | | (MBD)2 | | (MBD) | | (MMCFD) | | | | | | |
| Millions of cubic feet per day (MMCFD) | 2024 | 2023 | | 2024 | 2023 | | 2024 | 2023 | | 2024 | 2023 | | | | | | |
| United States | 1,599 | | 1,349 | | | 782 | | 710 | | | 370 | | 287 | | | 2,684 | | 2,112 | | | | | | | |
| Other Americas | | | | | | | | | | | | | | | | | |
Argentina | 51 | | 43 | | | 43 | | 37 | | | — | | — | | | 47 | | 36 | | | | | | | |
| | | | | | | | | | |
Canada3,4 | 132 | | 132 | | | 104 | | 109 | | | 6 | | 5 | | | 131 | | 110 | | | | | | | |
| Total Other Americas | 183 | | 175 | | | 147 | | 146 | | | 6 | | 5 | | | 178 | | 146 | | | | | | | |
| Africa | | | | | | | | | | | | | | | | | |
Angola | 64 | | 67 | | | 52 | | 55 | | | 4 | | 4 | | | 48 | | 48 | | | | | | | |
| Equatorial Guinea | 46 | | 49 | | | 9 | | 11 | | | 5 | | 5 | | | 191 | | 198 | | | | | | | |
Nigeria | 129 | | 147 | | | 96 | | 104 | | | 3 | | 5 | | | 183 | | 227 | | | | | | | |
| Republic of Congo | 28 | | 30 | | | 26 | | 28 | | | — | | — | | | 10 | | 9 | | | | | | | |
| Total Africa | 267 | | 293 | | | 183 | | 198 | | | 12 | | 14 | | | 432 | | 482 | | | | | | | |
| Asia | | | | | | | | | | | | | | | | | |
Bangladesh | 99 | | 104 | | | 3 | | 3 | | | — | | — | | | 577 | | 610 | | | | | | | |
China | 29 | | 30 | | | 7 | | 9 | | | — | | — | | | 132 | | 126 | | | | | | | |
Indonesia5 | — | | 3 | | | — | | 1 | | | — | | — | | | — | | 11 | | | | | | | |
| Israel | 100 | | 95 | | | 1 | | 1 | | | — | | — | | | 592 | | 566 | | | | | | | |
Kazakhstan | 45 | | 45 | | | 26 | | 26 | | | — | | — | | | 113 | | 114 | | | | | | | |
Myanmar6 | 4 | | 15 | | | — | | — | | | — | | — | | | 22 | | 87 | | | | | | | |
| Partitioned Zone | 61 | | 61 | | | 60 | | 60 | | | — | | — | | | 5 | | 6 | | | | | | | |
| Thailand | 47 | | 42 | | | 14 | | 10 | | | — | | — | | | 200 | | 192 | | | | | | | |
| Total Asia | 385 | | 395 | | | 111 | | 110 | | | — | | — | | | 1,641 | | 1,712 | | | | | | | |
| Australia | | | | | | | | | | | | | | | | | |
| Australia | 479 | | 488 | | | 40 | | 40 | | | 2 | | 2 | | | 2,625 | | 2,678 | | | | | | | |
| Total Australia | 479 | | 488 | | | 40 | | 40 | | | 2 | | 2 | | | 2,625 | | 2,678 | | | | | | | |
| Europe | | | | | | | | | | | | | | | | | |
| United Kingdom | 12 | | 14 | | | 11 | | 12 | | | — | | — | | | 7 | | 11 | | | | | | | |
| Total Europe | 12 | | 14 | | | 11 | | 12 | | | — | | — | | | 7 | | 11 | | | | | | | |
| Total Consolidated Companies | 2,925 | | 2,714 | | | 1,274 | | 1,216 | | | 390 | | 308 | | | 7,567 | | 7,141 | | | | | | | |
Affiliates7 | 413 | | 406 | | | 286 | | 281 | | | 25 | | 25 | | | 611 | | 603 | | | | | | | |
Total Including Affiliates8 | 3,338 | | 3,120 | | | 1,560 | | 1,497 | | | 415 | | 333 | | | 8,178 | | 7,744 | | | | | | | |
| | | | | | | | | | | | | | | | | |
1 Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil. | | | | | | |
2 Includes crude oil, condensate and synthetic oil. | | | | | | |
3 Includes synthetic oil: | 46 | | 51 | | 46 | | 51 | | — | | — | | | — | | — | | | | | | | |
| | | | | | | | | | |
4 Canada Duvernay shale and AOSP assets were sold in December 2024. | | | | | | |
5 Indonesia Deepwater assets were sold in 2023. | | | | | | |
6 Chevron withdrew from Myanmar in April 2024. | | | | | | |
7 Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil in Kazakhstan and Angola LNG in Angola. | | | | | | |
8 Volumes include natural gas consumed in operations of 609 million and 596 million cubic feet per day in 2024 and 2023, respectively. Total “as sold” natural gas volumes were 7,569 million and 7,148 million cubic feet per day for 2024 and 2023, respectively. | | | | | | |
Delivery Commitments
The company sells crude oil, natural gas, and NGLs from its producing operations under a variety of contractual obligations. Most contracts generally commit the company to sell quantities based on production from specified properties, but some NGLs and natural gas sales contracts specify delivery of fixed and determinable quantities.
In the United States, the company is contractually committed to deliver approximately 25 million barrels of NGLs and 813 billion cubic feet of natural gas to third parties and affiliates from 2025 through 2027. The company believes it can satisfy these contracts through a combination of equity production from the company’s proved developed U.S. reserves and third-party purchases. These commitments are primarily based on contracts with indexed pricing terms.
Outside the United States, the company is contractually committed to deliver a total of 3.2 trillion cubic feet of natural gas to third parties and affiliates from 2025 through 2027 mainly from operations in Australia and Israel. The Australia sales contracts contain variable pricing formulas that generally reference the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery. The sales contracts for Israel contain formulas that generally reflect an initial base price subject to price indexation, Brent-linked or other, over the life of the contract. The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed reserves in these countries.
Development Activities
Refer to Table I for details associated with the company’s development expenditures and costs of proved property acquisitions for 2024, 2023 and 2022. The following table summarizes the company’s net interest in productive and dry development wells completed in each of the past three years, and the status of the company’s development wells drilling at December 31, 2024. A “development well” is a well drilled within the known area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Wells Drilling* | | Net Wells Completed | |
| at 12/31/24 | | 2024 | | 2023 | | 2022 | |
| Gross | Net | | Prod. | Dry | | Prod. | Dry | | Prod. | Dry | |
| United States | 451 | | 355 | | | 630 | | 3 | | | 697 | | 2 | | | 454 | | 2 | | |
| Other Americas | 9 | | 8 | | | 64 | | — | | | 39 | | — | | | 35 | | — | | |
| Africa | 4 | | 2 | | | 6 | | — | | | 7 | | — | | | 6 | | — | | |
| Asia | 24 | | 9 | | | 72 | | 1 | | | 58 | | 2 | | | 32 | | 1 | | |
| Australia | — | | — | | | 2 | | — | | | 3 | | — | | | 1 | | — | | |
| Europe | 1 | | — | | | — | | — | | | — | | — | | | 1 | | — | | |
| Total Consolidated Companies | 489 | | 374 | | | 774 | | 4 | | | 804 | | 4 | | | 529 | | 3 | | |
| Affiliates | 3 | | 1 | | | 3 | | — | | | 4 | | — | | | 6 | | — | | |
| Total Including Affiliates | 492 | | 375 | | | 777 | | 4 | | | 808 | | 4 | | | 535 | | 3 | | |
| * Gross wells represent the total number of wells in which Chevron has an ownership interest. Net wells represent the sum of Chevron’s ownership interest in gross wells. | |
Exploration Activities
Refer to Table I for detail on the company’s exploration expenditures and costs of unproved property acquisitions for 2024, 2023 and 2022. The following table summarizes the company’s net interests in productive and dry exploratory wells completed in each of the past three years, and the number of exploratory wells drilling at December 31, 2024. “Exploratory wells” are wells drilled to find and produce crude oil or natural gas in unknown areas and include delineation and appraisal wells, which are wells drilled to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir or to extend a known reservoir.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Wells Drilling* | | Net Wells Completed | |
| at 12/31/24 | | 2024 | | 2023 | | 2022 | |
| Gross | Net | | Prod. | Dry | | Prod. | Dry | | Prod. | Dry | |
| United States | 2 | | 1 | | | 5 | | 2 | | | — | | 2 | | | 3 | | 2 | | |
| Other Americas | — | | — | | | 1 | | — | | | — | | — | | | 1 | | 1 | | |
| Africa | 1 | | — | | | 1 | | 1 | | | — | | — | | | 1 | | — | | |
| Asia | — | | — | | | 3 | | 2 | | | 1 | | — | | | 2 | | — | | |
| Australia | — | | — | | | — | | — | | | — | | — | | | — | | — | | |
| Europe | — | | — | | | — | | — | | | — | | — | | | — | | — | | |
| Total Consolidated Companies | 3 | | 1 | | | 10 | | 5 | | | 1 | | 2 | | | 7 | | 3 | | |
| Affiliates | — | | — | | | — | | — | | | — | | — | | | — | | — | | |
| Total Including Affiliates | 3 | | 1 | | | 10 | | 5 | | | 1 | | 2 | | | 7 | | 3 | | |
| * Gross wells represent the total number of wells in which Chevron has an ownership interest. Net wells represent the sum of Chevron’s ownership interest in gross wells. | |
Review of Ongoing Activities in Key Areas
The discussion that follows references the status of proved reserves recognition for significant long lead time projects not on production as well as for projects recently placed on production. Reserves are not discussed for exploration activities or recent discoveries that have not advanced to a project stage, or for mature areas of production that do not have individual projects requiring significant levels of capital or exploratory investment. Projected start-up timing for nonoperated projects are per operator’s estimate.
United States
As one of the largest producers in the Permian Basin, Chevron continues to develop its advantaged portfolio of 1,780,000 net acres in the Delaware and Midland basins in west Texas and southeast New Mexico and is expected to achieve one million barrels of net oil-equivalent production per day in 2025. The asset is comprised of stacked formations enabling production from multiple geologic zones from single surface locations, staging the development for optimized capacity utilization of facilities and infrastructure. The company has implemented a factory development strategy utilizing multi-well pads to drill a series of horizontal wells that are subsequently completed using hydraulic fracture stimulation. This manufacturing-style process, combined with advantaged acreage holdings and technological advancements, have enabled productivity improvements across unique geological locations throughout the basin. Acreage transactions enabling longer laterals and the company’s diversified land assets via non-operated joint ventures and royalty positions have also contributed to higher returns. The company continued to progress water handling initiatives and ongoing emission reductions, including the partial or full electrification of drilling and hydraulic fracturing fleets, and the expansion of electricity sources with two new solar projects reaching final investment decision in 2024. Chevron’s 2024 net daily production in the Permian Basin averaged 405,000 barrels of crude oil, 251,000 barrels of NGLs and 1.6 billion cubic feet of natural gas.
Chevron also holds approximately 72,000 net acres in the Haynesville Shale in east Texas. The company continues to pursue strategic opportunities for these assets.
Chevron is the largest oil and natural gas producer in Colorado, where development is focused across approximately 580,000 net acres in the Denver-Julesburg (DJ) Basin. Chevron follows a factory development strategy utilizing multi-well pads to drill a series of horizontal wells that are subsequently completed using hydraulic fracture stimulation. It has also implemented facility design and electrification improvements to consolidate assets and remove facilities, reducing surface footprint and greenhouse gas emissions. In 2024, Chevron’s net daily production in Colorado averaged 132,000 barrels of crude oil, 107,000 barrels of NGLs and 930 million cubic feet of natural gas. Chevron also has operations in Colorado’s Piceance Basin, as well as an acreage position in Wyoming.
In 2024, Chevron’s California average net daily oil-equivalent production was 71,000 barrels. Chevron owns and operates between 87 and 100 percent interests in six fields including Kern River, Cymric/McKittrick, Midway Sunset, San Ardo, Coalinga and Lost Hills. The company announced its first solar-to-hydrogen production project in Kern County, which will create lower carbon hydrogen through electrolysis, utilizing solar power, land and non-potable produced water from Chevron’s existing assets.
During 2024, net daily production in the Gulf of America averaged 168,000 barrels of crude oil, 10,000 barrels of NGLs and 86 million cubic feet of natural gas. Chevron is engaged in various operated and nonoperated exploration, development and production activities in the deepwater Gulf of America. Chevron also holds nonoperated interests in several shelf fields.
Chevron has a 62.9 percent-owned and operated interest in the unit areas containing the Anchor Field, located in the Green Canyon area. Stage 1 of the Anchor development that consists of a seven-well subsea development and a semi-submersible floating production unit achieved first oil in August 2024 utilizing an industry-first 20,000 pounds per square inch
deepwater technology. Two producing wells were brought online and development drilling is progressing on subsequent wells. The field has an estimated remaining production life of 30 years.
Chevron has a 60 percent-owned and operated interest in the Ballymore Field located in the Mississippi Canyon area, which is being developed as a subsea tieback to the existing Chevron 75 percent-owned and operated Blind Faith facility. The development includes three production wells, with first oil expected in 2025. Proved reserves have been recognized for this project.
Chevron has a 60 percent-owned and operated interest in the Big Foot Field, located in the deepwater Walker Ridge area. First oil from further development is expected in 2025 and 2026. The field has an estimated remaining production life of 25 years.
Chevron has a 50 percent-owned and operated interest in the Jack Field, a 51 percent-owned and operated interest in the St. Malo Field and a 40.6 percent-owned and operated interest in the production host facility used for the joint development of both fields, all located in the Walker Ridge area. In 2024, the St. Malo Stage 4 waterflood project delivered first water injection and completed the installation of a second multi-phase subsea pump module within the St. Malo Field. An additional St. Malo well delivered first oil and further development drilling commenced in the Jack Field. The Jack/St. Malo Stage 5 project reached final investment decision (FID), with first oil expected in 2026. The Jack and St. Malo fields have an estimated remaining production life of 20 years.
The company has a 58 percent-owned and operated interest in the deepwater Tahiti Field, located in the Green Canyon area. In 2024, the company’s first deepwater Gulf of America producer-to-injector conversion well started water injection and an additional water injector well reached FID. The Tahiti Field surpassed 500 million barrels of oil-equivalent cumulative production in 2024 and has an estimated remaining production life of 20 years.
The company has a 15.6 percent nonoperated working interest in the deepwater Mad Dog Field, located in the Green Canyon area. In 2024, first water injection was achieved from the Mad Dog 2 project and additional producing wells were brought online. The field has an estimated remaining production life of more than 30 years.
Chevron has a 37.5 percent nonoperated working interest in the Perdido Regional Host, which accommodates production from the Great White, Silvertip and Tobago fields in the Alaminos Canyon area. In 2024, the Silvertip Expansion Project, in which Chevron has a 60 percent nonoperated working interest, reached FID, with first oil expected in 2026. Additional development drilling in the Great White Field is currently ongoing, with first oil expected in 2025. The Perdido asset has an estimated remaining production life of more than 15 years.
Chevron has a 25 percent nonoperated working interest in the Stampede Field, which is located in the Green Canyon area. In 2024, development drilling on a new well with tie back to the host facility commenced and first oil is expected in 2025. The Stampede Field has an estimated remaining production life of more than 20 years.
The company has a 40 percent nonoperated working interest in the Whale discovery located in the Alaminos Canyon area. Whale consists of a fifteen-well subsea development and floating production unit. In January 2025, first production was achieved with two producing wells brought online and development drilling in progress on subsequent wells. The field has an estimated remaining production life of more than 25 years.
During 2024, Chevron was formally awarded 26 exploration blocks as a result of Gulf of America lease sale 261.
Chevron has a 50 percent interest in Bayou Bend, a carbon dioxide transportation and sequestration affiliate that holds approximately 140,000 acres for carbon dioxide storage. In 2024, onshore and offshore stratigraphic wells were drilled to delineate carbon dioxide storage potential.
Chevron owns a majority interest in ACES Delta, LLC, a joint venture developing the Advanced Clean Energy Storage Project in Delta, Utah. The project, currently under construction, is designed to produce hydrogen made from renewable energy, store that hydrogen in two salt caverns, and deliver it as needed to hydrogen-capable gas turbines to generate power. The project is expected to be commercially operational in 2025.
Other Americas
Argentina Chevron has a 50 percent nonoperated interest in the Loma Campana and Narambuena concessions in the Vaca Muerta shale. At Loma Compana, 48 horizontal wells were drilled in 2024, with 46 wells in total put on production. This concession expires in 2048, and the Narambuena concession expires in 2027.
Chevron owns and operates a 100 percent interest in the El Trapial Field with conventional waterflood. The conventional field concession expires in 2032. Chevron also owns and operates a 100 percent interest in the east area of the El Trapial Field in the Vaca Muerta shale formation for unconventional development. In 2024, Chevron continued development on its unconventional resources with one drilling rig. The unconventional concession expires in 2057.
Chevron has a 14 percent interest in a pipeline system that provides an important export route for Argentina’s crude oil. During 2024, a majority of the company’s exported crude oil was transported through this pipeline system. Chevron is currently evaluating other strategic alternatives to increase its export capacity in the country.
Brazil Chevron holds 35 percent nonoperated interests in two blocks in the Campos Basin, following the relinquishment of two blocks in 2024. Chevron secured 15 additional exploration blocks in the South Santos and Pelotas basins in 2024.
Canada Upstream interests in Canada are concentrated in the offshore Atlantic region of Newfoundland and Labrador. The company also has interests in the Northeast British Columbia and the Beaufort Sea region of the Northwest Territories.
Chevron has a 26.9 percent nonoperated working interest in the Hibernia Field and a 24.1 percent nonoperated working interest in the unitized Hibernia Southern Extension areas offshore Atlantic Canada. The company has a 29.6 percent nonoperated working interest in the Hebron Field, also offshore Atlantic Canada.
In December 2024, the company sold its 20 percent nonoperated working interest in the Athabasca Oil Sands Project and associated Quest carbon capture and storage project in Alberta, as well as its operated assets in the Duvernay shale.
Colombia Chevron has a 40 percent-owned and operated interest in the offshore Colombia-3 Block.
Mexico All blocks in which Chevron has a participating interest are in the process of being relinquished to the government.
Suriname Chevron has a 40 percent-owned and operated working interest in Block 5 and an 80 percent-owned and operated interest in the shallow water Block 7. Chevron also holds a 33.3 percent nonoperated working interest in deepwater Block 42.
Uruguay In 2024, Chevron acquired a 60 percent-owned and operated interest in offshore exploration Block OFF-1 with plans to initiate a 3D seismic campaign in 2025.
Venezuela Chevron’s interests in Venezuela are located in western Venezuela, the Orinoco Belt and offshore Venezuela. As of December 31, 2024, no proved reserves are recognized for these interests. In 2024, the company conducted activities in Venezuela consistent with the authorization provided pursuant to licenses issued by the United States government.
Chevron has a 39.2 percent interest in Petroboscan, which operates the Boscan Field in western Venezuela, as well as a 25.2 percent interest in Petroindependiente, which operates the LL-652 Field in Lake Maracaibo with licenses that expire in 2041. Chevron has a 30 percent interest in Petropiar, which operates the heavy oil Huyapari Field under an agreement expiring in 2047, and a 35.8 percent interest in Petroindependencia, which includes the Carabobo 3 heavy oil project located in three blocks in the Orinoco Belt under a contract expiring in 2050.
Chevron also operates and holds a 60 percent interest in the Loran gas field offshore Venezuela. This is part of a cross- border field that includes the Manatee Field in Trinidad and Tobago. This license expires in 2039.
Africa
Angola The company operates and holds a 39.2 percent interest in Block 0, a concession adjacent to the Cabinda coastline that expires in 2050. The Block 0 Sanha Lean Gas Connection Project (SLGC) was completed in 2024 and added a new platform that ties the existing complex to new connecting pipelines for gathering and exporting gas from Blocks 0 and 14 to Angola LNG.
In 2024, construction continued at the South N’Dola project located in Area B of Block 0, with first oil expected in 2025.
Chevron also operates and holds a 31 percent interest in a production sharing contract (PSC) for deepwater Block 14 that expires in 2028.
In 2024, Chevron added frontier exploration acreage positions for Blocks 49 and 50 offshore Angola in the deepwater lower Congo Basin.
Chevron has a 36.4 percent shareholding in Angola LNG Limited, which operates an onshore natural gas liquefaction plant in Soyo, Angola. The plant has the capacity to process 1.1 billion cubic feet of natural gas per day. This is the world’s first LNG plant supplied with associated gas, where the natural gas is a byproduct of crude oil production. Feedstock for the plant originates from multiple fields and operators.
Chevron owns a 31 percent nonoperated working interest in the New Gas Consortium Project (NGC). NGC is an offshore gas concession in which the Quiluma and Maboqueiro (Q&M) fields will be the first to be developed, with first production expected in 2026. The Q&M development includes two wellhead platforms and an onshore gas treatment plant with connections to the Angola LNG plant. Proved reserves were recognized for this project in 2024.
Angola-Democratic Republic of Congo (DRC) Joint Development Area Chevron has a 31 percent interest in a production sharing agreement (PSA) with the Angola and DRC governments to explore Block 14/23 located in the Zone of Common Interest established between the Republic of Angola and DRC maritime area.
Angola-Republic of Congo (ROC) Joint Development Area Chevron operates and holds a 15.5 percent interest in the Lianzi Unitization Zone (Lianzi), which is located in an area shared equally by Angola and the ROC. This interest expires in 2031. In January 2025, the company sold its interest in the ROC portion of Lianzi, while retaining the Angolan portion.
Republic of Congo In January 2025, the company sold its 31.5 percent nonoperated interest in the offshore Haute Mer permit area.
Cameroon Chevron has a 100 percent interest in the YoYo Block in the Douala Basin. Preliminary development plans include a possible joint development between YoYo and the Yolanda fields located in Equatorial Guinea Block I.
Egypt Chevron has interests in Egypt blocks in both the Mediterranean and Red Sea. In the Mediterranean Sea, Chevron holds a 63 percent-owned and operated interest in North El Dabaa (Block 4), a 45 percent-owned and operated interest in the Nargis Block and a 27 percent non-operated working interest in North Cleopatra (Block 7). In 2024, Chevron relinquished its 63 percent-owned and operated interest in North Sidi Barrani (Block 2) and its 27 percent nonoperated interest in North Marina (Block 6).
In the Red Sea, the company holds a 45 percent-owned and operated interest in Block 1.
Equatorial Guinea Chevron has a 38 percent-owned and operated interest in the Aseng Field and the Yolanda Field in Block I and a 45 percent-owned and operated interest in the Alen Field in Block O. The Yolanda field is a discovered natural gas field that straddles the Equatorial Guinea and Cameroon maritime border, for which development options are being reviewed with both governments.
The company also holds a 32 percent nonoperated interest in the Alba natural gas and condensate field.
Chevron holds interests in two processing facilities located in Punta Europa. These include a 28 percent nonoperated interest in the Alba LPG Plant and a 45 percent nonoperated interest in the Atlantic Methanol Production Company.
In 2024, Chevron added two exploration acreage positions for Blocks EG-06 and EG-11, offshore Bioko Island.
Namibia Chevron has an 80 percent-owned and operated interest in Petroleum Exploration License (PEL) 90 (Block 2813B) in the Orange Basin, offshore Namibia. In early 2025, Chevron acquired an 80 percent-owned and operated interest in PEL82 (Blocks 2112B and 2212A) in the Walvis Basin.
Nigeria Chevron holds 40 percent interests in concessions across the onshore and shallow-offshore regions of the Niger Delta, most of which were converted in 2024 to the terms of the Petroleum Industry Act of 2021. The company also holds acreage positions in five operated and six nonoperated deepwater blocks, with working interests ranging from 20 to 100 percent.
Chevron operates and holds a 67.3 percent working interest in the Agbami Field, which straddles deepwater Petroleum Mining Lease (PML) 52 (previously known as Oil Mining License (OML) 127) and OML 128. PML 52 expires in 2044, and OML 128 expires in 2042. Additionally, Chevron holds a 30 percent nonoperated working interest in the Usan Field in OML 138 that expires in 2042.
In deepwater exploration, Chevron operates and holds a 55 percent working interest in the Nsiko discovery in OML 140 and a 100 percent working interest in the Aparo discovery in OML 132. Chevron also holds a 27 percent nonoperated working interest in OML 139 and OML 154, and the company continues to work with the operator to evaluate development options for the multiple deepwater discoveries in the Usan area, including the Owowo Field, which straddles OML 139 and OML 154. The development plan for the Owowo Field involves a subsea tie-back to the existing Usan floating, production, storage and offloading vessel. The field development plan for the Owowo Stage 1 development project was approved in August 2024. At the end of 2024, no proved reserves were recognized for this project.
Also, in the deepwater area, the third-party-operated Bonga South West Aparo Field in OML 118 straddles both OML 132 and OML 140. Chevron holds a 16.6 percent nonoperated working interest in the unitized area. The development plan involves subsea wells tied back to a floating production, storage and offloading vessel. At the end of 2024, no proved reserves were recognized for this project.
Chevron holds a 40 percent-owned and operated working interest in Oil Prospecting License (OPL) 215 that covers 256,000 net acres.
In 2024, Chevron discovered new oil in the Niger Delta at Petroleum Mining Lease 49 (previously within OML 90). This Meji NW-1 discovery is expected to increase Chevron’s oil production in the joint venture asset in which it holds a 40 percent working interest.
Chevron operates the Escravos Gas Plant, which has a total processing capacity of 680 million cubic feet per day of natural gas and liquefied petroleum gas and condensate export capacity of 58,000 barrels per day. The company operates the 33,000-barrel-per-day Escravos Gas to Liquids facility. In addition, the company holds a 36.9 percent interest in the West African Gas Pipeline Company Limited affiliate, which supplies Nigerian natural gas to customers in Benin, Togo and Ghana.
Asia
In Asia, the company is engaged in upstream activities in Bangladesh, China, Cyprus, Indonesia, Israel, Kazakhstan, the Partitioned Zone between Saudi Arabia and Kuwait, Russia and Thailand. Acreage for Asia can be found in the Acreage table. Net daily oil-equivalent production for these countries can be found in the Net Production of Crude Oil, Natural Gas Liquids and Natural Gas table. Bangladesh Chevron Bangladesh operates and holds 100 percent interest in Block 12 (Bibiyana field) and Blocks 13 and 14 (Jalalabad and Moulavi Bazar fields) under two PSCs. The rights to produce from Bibiyana and Jalalabad expire in 2034 and from Moulavi Bazar in 2038.
China Chevron has a 49 percent nonoperated working interest in the Chuandongbei project, including the Luojiazhai and Gunziping natural gas fields located onshore in the Sichuan Basin with the PSC expiring in 2038. The company also has a 32.7 percent nonoperated working interest in Block 16/19 in the Pearl River Mouth Basin, with the PSC expiring in 2028.
In the Bohai Bay, the company previously held a 24.5 percent nonoperated working interests in the Qinhuangdao (QHD) 32-6 PSC, which expired in November 2024.
Cyprus The company holds a 35 percent-owned and operated interest in the Aphrodite gas field in Block 12 under a PSC, with an exploitation license that expires in 2044. In February 2025, the government and the joint venture agreed to a development and production plan with revised PSC project milestones.
Indonesia In 2024, Chevron commenced an exploration project managed by its joint venture at the Way Ratai geothermal working area in Lampung.
Israel Chevron holds a 39.7 percent-owned and operated interest in the Leviathan Field, which operates under a concession that expires in 2044. A third gathering pipeline is under construction and is expected to increase gas production capacity from approximately 1.2 to 1.4 billion cubic feet per day from the Leviathan reservoir. This pipeline is scheduled for completion in early 2026.
Chevron is also undergoing front end engineering design (FEED) and procurement for long lead items to further expand the installed capacity at the Leviathan Field from 1.4 to up to 2.1 billion cubic feet per day. This expansion aims to increase production and improve the monetization of the asset, including opportunities via existing and planned regional infrastructure as well as potential avenues for entry into the global LNG market. The FEED work is critical to reach FID and is contingent upon meeting certain commercial and regulatory conditions.
The company also holds a 25 percent-owned and operated interest in the Tamar gas field, which operates under a concession that expires in 2038. Phase 1 of the Tamar Optimization Project includes installation of a new pipeline to increase delivery capacity to the processing platform, allowing for production at the platform to increase from approximately 1.0 billion to 1.2 billion cubic feet per day. This project is scheduled for completion in 2025.
Chevron reached FID on Phase 2 of the Tamar Optimization Project in February 2024, which is expected to further increase capacity up to approximately 1.6 billion cubic feet of gas per day and includes investment in additional midstream infrastructure. This project is scheduled for completion in 2026.
Kazakhstan Chevron has a 50 percent interest in the Tengizchevroil (TCO) affiliate and an 18 percent nonoperated working interest in the Karachaganak field.
TCO is developing the Tengiz and Korolev crude oil fields in western Kazakhstan under a concession agreement that expires in 2033. Most of TCO’s 2024 crude oil production was exported through the Caspian Pipeline Consortium (CPC) pipeline.
TCO completed the Wellhead Pressure Management Project (WPMP) in 2024 while also completing two major train turnarounds. In early 2025, TCO started oil production at the Future Growth Project (FGP). FGP is the third processing plant in operation at the Tengiz oil field, which is expected to increase crude oil production by 260,000 barrels per day at full capacity and ramp-up total output to one million barrels of oil-equivalent per day.
The Karachaganak field is located in northwest Kazakhstan, and operations are conducted under a PSA that expires in 2038. During 2024, a majority of the exported liquids were transported through the CPC pipeline. In 2024, the Karachaganak Expansion Project Stage 1A facility scope was completed with final associated injector well to be completed in first-half 2025 and Stage 1B continued development expecting to complete second-half 2026. Both projects increase gas re-injection capacity and extend stable field production. Proved reserves have been recognized for both projects.
Kazakhstan/Russia Chevron has a 15 percent interest in the CPC. Through 2024, CPC transported an average of 1.4 million barrels of crude oil per day, composed of 1.2 million barrels per day from Kazakhstan and 0.2 million barrels per day from Russia.
Kurdistan Region of Iraq After relinquishment of company interests in Sarta and Qara Dagh PSCs in 2023, Chevron continues to work with the government and joint venture partner on final exit agreements, expected to be completed in early 2025.
Myanmar Chevron withdrew from Myanmar, effective April 2024.
Partitioned Zone Chevron holds a concession to operate the Kingdom of Saudi Arabia’s 50 percent interest in the hydrocarbon resources in the onshore area of the Partitioned Zone between Saudi Arabia and Kuwait. The concession expires in 2046. In 2024, the NWWB-1 exploration well reached total depth and was placed on production. Current activities focus on optimizing base business, further exploration and development drilling and delivering new technology that enables production growth.
Thailand Chevron holds operated interests in the Pattani Basin, located in the Gulf of Thailand, with ownership ranging from 35 percent to 71.2 percent. Concessions for producing areas within this basin expire between 2028 and 2035. Chevron has a 35 percent-owned and operated interest in the Pailin field in Block 12/27. Chevron also has a 16 percent nonoperated working interest in the Arthit field located in the Malay Basin. Concessions for the producing areas within this basin expire between 2036 and 2040. Chevron also has an exploration and production license for Block G2/65, which covers 3.7 million net acres.
Chevron holds between 30 to 80 percent operated and nonoperated working interests in the Thailand-Cambodia Overlapping Claims Area that are inactive, pending resolution of border issues between Thailand and Cambodia.
Australia
Upstream activities in Australia are concentrated offshore Western Australia, where the company is the operator of two major LNG projects, Gorgon and Wheatstone, and has a nonoperated working interest in the North West Shelf (NWS) Venture and exploration acreage in the Carnarvon Basin.
Chevron holds a 47.3 percent-owned and operated interest in Gorgon on Barrow Island, which includes the development of the Gorgon and Jansz-Io fields, a three-train 15.6 million-metric-ton-per-year LNG facility, a carbon capture and underground storage facility and a domestic gas plant. Progress on the Jansz-Io Compression project continued during 2024 with first gas expected in 2028. Proved reserves have been recognized for this project. Gorgon’s estimated remaining economic life exceeds 40 years.
Chevron holds an 80.2 percent interest in the offshore licenses and a 64.1 percent-owned and operated interest in the LNG facilities associated with Wheatstone. Wheatstone includes the development of the Wheatstone and Iago fields, a two-train, 8.9 million-metric-ton-per-year LNG facility, and a domestic gas plant. The onshore facilities are located at Ashburton North on the coast of Western Australia. Wheatstone’s estimated remaining economic life exceeds 16 years.
Chevron has a 16.7 percent nonoperated working interest in the NWS Venture in Western Australia. In 2024, the company agreed to an asset swap of its 16.7 percent interest in the NWS Project, NWS Oil Project and its 20 percent interest in Angel Carbon Capture and Storage Project with Woodside’s 13 percent nonoperated interest in the Wheatstone Project and 65 percent operated interest in the Julimar-Brunello fields and related infrastructure, which is expected to close in 2026, subject to customary closing conditions and regulations.
The company continues to evaluate exploration and appraisal activity across the Carnarvon Basin, in which it holds more than 2.6 million net acres. In 2024, Chevron was awarded the WA-553-P exploration permit in the North Carnarvon Basin, which covers approximately 800,000 net acres. Chevron owns and operates the Clio, Acme and Acme West fields. The company is collaborating with other Carnarvon Basin participants to assess the possibility of developing Clio and Acme through shared utilization of existing infrastructure.
Chevron holds operated and nonoperated working interests ranging from 20 to 70 percent, in five greenhouse gas assessment permits to evaluate the potential of carbon dioxide storage. The blocks, including four in the Carnarvon Basin off the northwestern coast of Western Australia and one in the Bonaparte Basin offshore Northern Territory, total nearly 10.2 million gross acres. This acreage includes Block G-18-AP and Block G-20-AP, both awarded in 2024 and the Angel Carbon Capture and Storage Project, subject to the asset swap mentioned above.
United Kingdom
Chevron holds a 19.4 percent nonoperated working interest in the Clair Field, located west of the Shetland Islands. The Clair Field currently consists of two platform drilling centers: the original Clair Phase 1 and a later added Clair Ridge center. The company is assessing a third drilling center to develop further resources in the area. The Clair Field has an estimated remaining production life extending beyond 2050.
Sales of Natural Gas Liquids and Natural Gas
The company sells NGLs and natural gas from its producing operations under a variety of contractual arrangements. In addition, the company also makes third-party purchases and sales of NGLs and natural gas in connection with its supply and trading activities.
U.S. and international sales of NGLs averaged 511,000 and 268,000 barrels per day, respectively, in 2024.
During 2024, U.S. and international sales of natural gas averaged 5.2 billion and 5.7 billion cubic feet per day, respectively, which includes the company’s share of equity affiliates’ sales. Outside the United States, substantially all of the natural gas sales from the company’s producing interests are from operations in Angola, Australia, Bangladesh, Canada, Equatorial Guinea, Kazakhstan, Israel, Nigeria and Thailand.
Refer to Selected Operating Data in Management’s Discussion and Analysis of Financial Condition and Results of Operations, for further information on the company’s sales volumes of NGLs and natural gas. Refer also to Delivery Commitments for information related to the company’s delivery commitments for the sale of crude oil and natural gas.
Downstream
Refining Operations
At the end of 2024, the company had a refining network capable of processing 1.8 million barrels per day. Operable capacity at December 31, 2024, and daily refinery inputs for the company and affiliate refineries for 2022 through 2024, are summarized in the table below. Average crude unit distillation capacity utilization was 87.9 percent in 2024 and 89.8 percent in 2023.
At U.S. refineries, crude unit distillation capacity utilization, which includes all crude oil and other inputs, averaged 86.6 percent in 2024, compared with 90.8 percent in 2023. Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for approximately 60 percent of Chevron’s U.S. refinery inputs in both 2024 and 2023.
In the United States, the company continued work on projects aimed at improving refinery flexibility and reliability. In 2024, the company completed the upgrade of the Pasadena Refinery, which is expected to increase light crude oil throughput capacity to 125,000 barrels per day with a phased start-up through first-quarter 2025. This project should allow the company to process more equity crude from the Permian Basin, supply more products to customers in the U.S. Gulf Coast and realize synergies with the company’s Pascagoula Refinery.
Outside the United States, the company has interests in three large refineries in Singapore, South Korea and Thailand. Singapore Refining Company (SRC), a 50 percent-owned joint venture, has a total capacity of 290,000 barrels of crude per day and manufactures a wide range of petroleum products. The 50 percent-owned GS Caltex (GSC) Yeosu Refinery in South Korea remains one of the world’s largest refineries with a total crude capacity of 800,000 barrels per day. The company’s 60.6 percent-owned refinery in Thailand, Star Petroleum Refining Public Company Limited (SPRC), continues to supply high-quality petroleum products into regional markets.
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Petroleum Refineries: Locations, Capacities and Crude Unit Inputs | |
| Capacities and inputs in thousands of barrels per day | December 31, 2024 | Refinery Crude Unit Inputs* | |
| Locations | Number | Operable Capacity | 2024 | 2023 | 2022 | |
| Pascagoula | Mississippi | 1 | | 369 | | 337 | | 355 | | 359 | | |
| El Segundo | California | 1 | | 290 | | 224 | | 232 | | 251 | | |
| Richmond | California | 1 | | 257 | | 242 | | 236 | | 183 | | |
| Pasadena | Texas | 1 | | 85 | | 65 | | 84 | | 78 | | |
| Salt Lake City | Utah | 1 | | 58 | | 49 | | 55 | | 53 | | |
| Total Consolidated Companies — United States | 5 | | 1,059 | | 917 | | 962 | 924 | |
| Map Ta Phut | Thailand | 1 | | 175 | | 160 | | 153 | | 156 | | |
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Net proved reserves by product Billions of BOE*
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Proved Reserves Net proved reserves for consolidated companies and affiliated companies totaled 9.8 billion barrels of oil-equivalent at year-end 2024, a decrease from year-end 2023. The reserve replacement ratio in 2024 was negative 4 percent. The 5 and 10 year reserve replacement ratios were 72 percent and 88 percent, respectively. Refer to Table V for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2022 and each year-end from 2022 through 2024, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2024. Refer to the “Results of Operations” section on pages 43 for additional discussion of the company’s upstream business.
Downstream Earnings for the downstream segment are closely tied to margins on the refining, manufacturing and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil, fuel and lubricant additives, petrochemicals and renewable fuels. 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 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. The company is also one of the largest renewable fuels producers in the United States.
Refer to the “Results of Operations” section on page 44 for additional discussion of the company’s downstream operations.
All Other consists of worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities and technology companies.
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| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Noteworthy Developments
Key noteworthy developments and other events during 2024 and early 2025 included the following:
Angola Added frontier exploration acreage positions in the deepwater lower Congo Basin.
Angola Achieved first gas on the Sanha Lean Gas Connection project, securing incremental natural gas supply to the Angola Liquefied Natural Gas facility.
Australia Announced asset exchange of North West Shelf Assets for Wheatstone Assets and Julimar/Brunello fields.
Australia Received two offshore greenhouse gas assessment permits, covering an area of approximately 10,700 km2, to assess future carbon dioxide storage.
Brazil Secured 15 exploration blocks in the South Santos and Pelotas Basins.
Canada Sold the company’s interest in the Athabasca Oil Sands Project and Duvernay shale for $6.5 billion.
Equatorial Guinea Signed agreements to acquire two exploration blocks offshore Bioko Island.
Israel Reached final investment decision to add midstream infrastructure that is expected to increase production capacity at the Tamar gas field in Israel to 1.6 billion cubic feet per day.
Kazakhstan Completed the Wellhead Pressure Management Project and, in January 2025, started production at the Future Growth Project, which is expected to ramp up total output to around one million barrels of oil equivalent per day at the company’s 50 percent-owned affiliate, Tengizchevroil LLP in Kazakhstan.
Myanmar Withdrew from Chevron’s nonoperated working interests effective April 1, 2024.
Namibia Signed agreements to acquire 80 percent working interest in Petroleum Exploration License 82 in the Walvis Basin.
Nigeria Extended the Meji field offshore Nigeria with a near-field discovery and renewed the Agbami deep-water concession through 2044.
Republic of Congo Sold the company’s 31.5 percent nonoperated working interest in the offshore Haute Mer permit area and its 15.75 percent interest in the Republic of Congo portion of Lianzi in January 2025.
United States Reached final investment decision to build an oilseed processing plant in Louisiana through the company’s joint venture Bunge Chevron Ag Renewables LLC.
United States Drilled onshore and offshore stratigraphic wells to delineate carbon dioxide storage potential through the company’s joint venture Bayou Bend CCS LLC.
United States Launched a $500 million Future Energy Fund III focused on venture investments in technology-based solutions that have the potential to enable affordable, reliable and lower carbon energy.
United States Progressed the company’s pending merger with Hess Corporation by securing Hess stockholder approval and clearing Federal Trade Commission antitrust review.
United States Started production at the industry-first 20,000 pounds per square inch deepwater Anchor project, began water injection to boost production from the St. Malo and Tahiti fields, and in January 2025 started production from the Whale semi-submersible platform in the Gulf of America.
United States Upgraded the Pasadena Refinery, which is expected to increase product flexibility and expand the processing capacity of lighter crude oil to 125,000 barrels per day.
United States Completed projects and operational changes designed to abate over 700,000 tonnes of carbon dioxide-equivalent from the company’s operations.
United States Announced plans to jointly develop scalable power solutions using natural gas-fired turbines with flexibility to integrate carbon capture and storage to support growing energy demand from U.S. data centers.
Uruguay Entered an agreement to assume a 60 percent operated interest in Uruguay’s AREA OFF-1 offshore exploration block.
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| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Common Stock Dividends The 2024 annual dividend was $6.52 per share, making 2024 the 37th consecutive year that the company increased its annual per share dividend payout. In January 2025, the company’s Board of Directors increased its quarterly dividend by $0.08 per share, approximately five percent, to $1.71 per share payable in March 2025.
Common Stock Repurchase Program The company repurchased $15.2 billion of its common stock in 2024 under its stock repurchase program. For more information on the common stock repurchase program, see Liquidity and Capital Resources. 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 2023 and 2022 can be found in the “Results of Operations” section on pages 41 through 43 of the company’s 2023 Annual Report on Form 10-K filed with the SEC on February 26, 2024. | | |
Worldwide Upstream earnings Billions of Dollars
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Worldwide Downstream earnings Billions of dollars
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U.S. refined product sales Thousands of barrels per day
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| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Net Debt Ratio Total debt less cash and cash equivalents, time deposits and marketable securities as a percentage of total debt less cash and cash equivalents, time deposits and marketable securities, plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage, net of its cash balances.
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| At December 31 | |
| Millions of dollars | 2024 | | | | 2023 | | 2022 | |
| Short-term debt | $ | 4,406 | | | | | $ | 529 | | | $ | 1,964 | | |
| Long-term debt | 20,135 | | | | | 20,307 | | | 21,375 | | |
Total Debt | 24,541 | | | | | 20,836 | | | 23,339 | | |
| Less: Cash and cash equivalents | 6,781 | | | | | 8,178 | | | 17,678 | | |
| Less: Time deposits | 4 | | | | | — | | | — | | |
| Less: Marketable securities | — | | | | | 45 | | | 223 | | |
| Total adjusted debt | 17,756 | | | | | 12,613 | | | 5,438 | | |
Total Chevron Corporation Stockholders’ Equity | 152,318 | | | | | 160,957 | | | 159,282 | | |
| Total adjusted debt plus total Chevron Corporation Stockholders’ Equity | $ | 170,074 | | | | | $ | 173,570 | | | $ | 164,720 | | |
| Net Debt Ratio | 10.4 | | % | | | 7.3 | | % | 3.3 | | % |
Capital Employed The sum of Chevron Corporation Stockholders’ Equity, total debt and noncontrolling interests, which represents the net investment in the business.
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| At December 31 | |
| Millions of dollars | 2024 | | | | 2023 | | 2022 | |
| Chevron Corporation Stockholders’ Equity | $ | 152,318 | | | | | $ | 160,957 | | | $ | 159,282 | | |
| Plus: Short-term debt | 4,406 | | | | | 529 | | | 1,964 | | |
| Plus: Long-term debt | 20,135 | | | | | 20,307 | | | 21,375 | | |
| Plus: Noncontrolling interest | 839 | | | | | 972 | | | 960 | | |
| Capital Employed at December 31 | $ | 177,698 | | | | | $ | 182,765 | | | $ | 183,581 | | |
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.
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| Year ended December 31 | |
| Millions of dollars | 2024 | | | | 2023 | | 2022 | |
| Net income attributable to Chevron | $ | 17,661 | | | | | $ | 21,369 | | | $ | 35,465 | | |
| Plus: After-tax interest and debt expense | 539 | | | | | 432 | | | 476 | | |
| Plus: Noncontrolling interest | 88 | | | | | 42 | | | 143 | | |
| Net income after adjustments | 18,288 | | | | | 21,843 | | | 36,084 | | |
| Average capital employed | $ | 180,232 | | | | | $ | 183,173 | | | $ | 177,445 | | |
| Return on Average Capital Employed | 10.1 | | % | | | 11.9 | | % | 20.3 | | % |
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.
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| Year ended December 31 | |
| Millions of dollars | 2024 | | | | 2023 | | 2022 | |
| Net income attributable to Chevron | $ | 17,661 | | | | | $ | 21,369 | | | $ | 35,465 | | |
| Chevron Corporation Stockholders’ Equity at December 31 | 152,318 | | | | | 160,957 | | | 159,282 | | |
| Average Chevron Corporation Stockholders’ Equity | 156,638 | | | | | 160,120 | | | 149,175 | | |
| Return on Average Stockholders’ Equity | 11.3 | | % | | | 13.3 | | % | 23.8 | | % |
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.
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| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Derivative Commodity Instruments Chevron is exposed to market risks related to the price volatility of crude oil, refined products, 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 2024.
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 2024 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, 2024 and 2023 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, 2024.
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 2024, 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
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.
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| Millions of dollars | 2024 | | 2023 | | 2022 |
| Balance at January 1 | $ | 936 | | | $ | 868 | | | $ | 960 | |
| Net additions | 264 | | | 327 | | | 182 | |
| Expenditures | (255) | | | (259) | | | (274) | |
| Balance at December 31 | $ | 945 | | | $ | 936 | | | $ | 868 | |
The company records asset retirement obligations when there is a legal obligation associated with the retirement of long-lived assets and the liability can be reasonably estimated. These asset retirement obligations include costs related to environmental issues. The liability balance of approximately $12.7 billion for asset retirement obligations at year-end 2024 is related primarily to upstream properties.
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| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
For the company’s other ongoing operating assets, such as refineries and chemicals facilities, no provisions are made for exit or cleanup costs that may be required when such assets reach the end of their useful lives unless a decision to sell or otherwise decommission the facility has been made, as the indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the asset retirement obligation.
The company records decommissioning obligations for previously divested assets when it is probable that the decommissioning obligations would revert to the Company and costs can be reasonably estimated. At the end of 2024, the liability balance was $2.5 billion. Refer to Note 24 Other Contingencies and Commitments for additional discussion of decommissioning obligations for previously divested assets. Refer to the discussion below for additional information on environmental matters and their impact on Chevron, and on the company’s 2024 environmental expenditures. Refer to Note 24 Other Contingencies and Commitments for additional discussion of environmental remediation provisions. Refer also to Note 25 Asset Retirement Obligations for additional discussion of the company’s asset retirement obligations. 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 electric vehicle and renewable fuel penetration, energy efficiency standards, climate-related policy actions, and demand response to oil and natural gas prices. In addition, legislation and regulations intended to address hydraulic fracturing also continue to evolve in many jurisdictions where we operate. 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 35 through 37 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 2024 at approximately $2.5 billion for its consolidated companies. Included in these expenditures were approximately $0.6 billion of environmental capital expenditures and $1.9 billion of costs associated
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| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
with the prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites, and the decommissioning and restoration of sites.
For 2025, total worldwide environmental capital expenditures are estimated at $0.6 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, NGLs and natural gas reserves include field performance, available technology, commodity prices, and development, production and carbon costs.
The estimates of crude oil, NGLs and natural gas reserves are important to the timing of expense recognition for costs incurred and to the valuation of certain oil and gas producing assets. 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 2024, Chevron’s UOP DD&A for oil and gas properties was $13.0 billion, and proved developed reserves at the beginning of 2024 were 6.8 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 2024 would have increased by approximately $700 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, 2022, 2023 and 2024, 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, 2022, 2023 and 2024.
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| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
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 future undiscounted cash flows exceed the carrying value of the asset or asset group, no impairment charge is required. Such calculations are reviewed each period until the asset or asset group is disposed. 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 2024 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 Post-Employment Benefit Plans Note 23 Employee Benefit Plans includes information on the funded status of the company’s pension and other post-employment benefit (OPEB) plans reflected on the Consolidated Balance Sheet; the components of pension and OPEB expense reflected on the Consolidated Statement of Income; and the related underlying assumptions.
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| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
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 2024, the company used an expected long-term rate of return of 7.0 percent and a discount rate for service costs of 5.0 percent and a discount rate for interest cost of 4.8 percent for the primary U.S. pension plan. The actual return for 2024 was 3.6 percent. For the 10 years ended December 31, 2024, actual asset returns averaged 4.9 percent for this plan. Additionally, with the exception of four years within this 10-year period, actual asset returns for this plan equaled or exceeded 7.0 percent during each year.
Total pension expense for 2024 was $551 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 63 percent of companywide pension expense, would have reduced total pension plan expense for 2024 by approximately $84 million. A one percent increase in the discount rates for this same plan would have reduced pension expense for 2024 by approximately $106 million.
The aggregate funded status recognized at December 31, 2024, was a net liability of approximately $0.8 billion. An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan. At December 31, 2024, the company used a discount rate of 5.7 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 66 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $261 million, and would have increased the plan’s surplus from $573 million to $834 million.
For the company’s OPEB plans, expense for 2024 was $91 million, and the total liability, all unfunded at the end of 2024, was $1.9 billion. For the primary U.S. OPEB plan, the company used a discount rate for service cost of 5.1 percent and a discount rate for interest cost of 4.9 percent to measure expense in 2024, and a 5.6 percent discount rate to measure the benefit obligations at December 31, 2024. Discount rate changes, similar to those used in the pension sensitivity analysis, resulted in an immaterial impact on 2024 OPEB expense and OPEB liabilities at the end of 2024.
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 95 in Note 23 Employee Benefit Plans for more information on the $3.2 billion of before-tax actuarial losses recorded by the company as of December 31, 2024. In addition, information related to company contributions is included on page 98 in Note 23 Employee Benefit Plans under the heading “Cash Contributions and Benefit Payments.” Contingent Losses Management also makes judgments and estimates in recording liabilities for claims, litigation, tax matters, transferred liabilities from previously divested assets, and environmental remediation. Actual costs can frequently vary from estimates for a variety of reasons. For example, the costs for settlement of claims and litigation can vary from estimates based on differing interpretations of laws, opinions on culpability and assessments on the amount of damages. The costs for decommissioning obligations for previously divested assets can also vary from estimates. Recording of liabilities for such costs typically requires judgment to assess the likelihood of decommissioning obligations reverting to the company, the timing of decommissioning activity, regulatory requirements and the scope of decommissioning activities. Similarly, liabilities for environmental remediation are subject to change because of changes in laws, regulations and their interpretation, the determination of additional information on the extent and nature of site contamination, and improvements in technology.
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 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.”
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| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Refer also to the business segment discussions elsewhere in this section for the effect on earnings from losses associated with certain litigation, environmental remediation and tax matters for the three years ended December 31, 2024.
An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in recording these liabilities is not practicable because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss. 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 27. New Accounting Standards
Quarterly Results
Unaudited
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2024 | 2023 |
| 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 | $ | 48,334 | | | $ | 48,926 | | | $ | 49,574 | | | $ | 46,580 | | | $ | 48,933 | | | $ | 51,922 | | | $ | 47,216 | | | $ | 48,842 | |
Income from equity affiliates | 688 | | | 1,261 | | | 1,206 | | | 1,441 | | | 990 | | | 1,313 | | | 1,240 | | | 1,588 | |
| Other income (loss) | 3,204 | | | 482 | | | 401 | | | 695 | | | (2,743) | | | 845 | | | 440 | | | 363 | |
| Total Revenues and Other Income | 52,226 | | | 50,669 | | | 51,181 | | | 48,716 | | | 47,180 | | | 54,080 | | | 48,896 | | | 50,793 | |
| Costs and Other Deductions | | | | | | | | | | | | | | | |
Purchased crude oil and products | 30,148 | | | 30,450 | | | 30,867 | | | 27,741 | | | 28,477 | | | 32,328 | | | 28,984 | | | 29,407 | |
Operating expenses | 7,622 | | | 6,695 | | | 6,614 | | | 6,533 | | | 6,510 | | | 6,299 | | | 6,057 | | | 6,021 | |
Selling, general and administrative expenses | 1,585 | | | 1,191 | | | 1,048 | | | 1,010 | | | 969 | | | 1,163 | | | 1,128 | | | 881 | |
Exploration expenses | 449 | | | 154 | | | 263 | | | 129 | | | 254 | | 301 | | 169 | | 190 |
Depreciation, depletion and amortization | 4,973 | | | 4,214 | | | 4,004 | | | 4,091 | | | 6,254 | | | 4,025 | | | 3,521 | | | 3,526 | |
Taxes other than on income | 1,141 | | | 1,263 | | | 1,188 | | | 1,124 | | | 1,062 | | | 1,021 | | | 1,041 | | | 1,096 | |
Interest and debt expense | 199 | | | 164 | | | 113 | | | 118 | | | 120 | | | 114 | | | 120 | | | 115 | |
Other components of net periodic benefit costs | 50 | | | 49 | | | 48 | | | 48 | | | 44 | | | 91 | | | 39 | | | 38 | |
| Total Costs and Other Deductions | 46,167 | | | 44,180 | | | 44,145 | | | 40,794 | | | 43,690 | | | 45,342 | | | 41,059 | | | 41,274 | |
| Income (Loss) Before Income Tax Expense | 6,059 | | | 6,489 | | | 7,036 | | | 7,922 | | | 3,490 | | | 8,738 | | | 7,837 | | | 9,519 | |
| Income Tax Expense (Benefit) | 2,800 | | | 1,993 | | | 2,593 | | | 2,371 | | | 1,247 | | | 2,183 | | | 1,829 | | | 2,914 | |
| Net Income (Loss) | $ | 3,259 | | | $ | 4,496 | | | $ | 4,443 | | | $ | 5,551 | | | $ | 2,243 | | | $ | 6,555 | | | $ | 6,008 | | | $ | 6,605 | |
| Less: Net income (loss) attributable to noncontrolling interests | 20 | | | 9 | | | 9 | | | 50 | | | (16) | | | 29 | | | (2) | | | 31 | |
| Net Income (Loss) Attributable to Chevron Corporation | $ | 3,239 | | | $ | 4,487 | | | $ | 4,434 | | | $ | 5,501 | | | $ | 2,259 | | | $ | 6,526 | | | $ | 6,010 | | | $ | 6,574 | |
| Per Share of Common Stock | | | | | | | | | | | | | | | |
Net Income (Loss) Attributable to Chevron Corporation | | | | | | | | | | | | | | | |
– Basic | $ | 1.85 | | | $ | 2.49 | | | $ | 2.43 | | | $ | 2.99 | | | $ | 1.23 | | | $ | 3.48 | | | $ | 3.22 | | | $ | 3.48 | |
– Diluted | $ | 1.84 | | | $ | 2.48 | | | $ | 2.43 | | | $ | 2.97 | | | $ | 1.22 | | | $ | 3.48 | | | $ | 3.20 | | | $ | 3.46 | |
| Dividends per share | $ | 1.63 | | | $ | 1.63 | | | $ | 1.63 | | | $ | 1.63 | | | $ | 1.51 | | | $ | 1.51 | | | $ | 1.51 | | | $ | 1.51 | |
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| Management’s Responsibility for Financial Statements | |
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| 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, 2024. 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. | |
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| 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, 2024. The effectiveness of the company’s internal control over financial reporting as of December 31, 2024, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein. | |
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| /s/ MICHAEL K. WIRTH | | /s/ EIMEAR P. BONNER | | /s/ ALANA K. KNOWLES | |
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| Michael K. Wirth | | Eimear P. Bonner | | Alana K. Knowles | |
| Chairman of the Board | | Vice President | | Vice President | |
| and Chief Executive Officer | | and Chief Financial Officer | | and Controller | |
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| February 21, 2025 | | | | | |
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| 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, 2024 and 2023, 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, 2024, 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, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 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, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO. | |
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| 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. | |
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| Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. | |
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| Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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. | |
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| Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. | |
| The Impact of Proved Developed Crude Oil and Natural Gas Reserves on Upstream Property, Plant, and Equipment, Net As described in Notes 1 and 18 to the consolidated financial statements, the Company’s upstream property, plant and equipment, net balance was $129.1 billion as of December 31, 2024, and depreciation, depletion and amortization expense was $15.5 billion for the year ended December 31, 2024. 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, natural gas liquids (NGLs) and natural gas reserves include field performance, available technology, commodity prices, and development, production and carbon costs. Reserves are estimated by Company asset teams composed of earth scientists and engineers. 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/ | |
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| February 21, 2025 | |
| We have served as the Company’s auditor since 1935. | |
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| Consolidated Statement of Income | |
| Millions of dollars, except per-share amounts | |
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| | Year ended December 31 | |
| | 2024 | | | 2023 | | 2022 | |
| Revenues and Other Income | | | | | | | |
| Sales and other operating revenues | $ | | | | | $ | | | | $ | | | |
| Income (loss) from equity affiliates | | | | | | | | | | |
| Other income (loss) | | | | | () | | | | | |
| Total Revenues and Other Income | | | | | | | | | | |
| Costs and Other Deductions | | | | | | | |
| Purchased crude oil and products | | | | | | | | | | |
| Operating expenses | | | | | | | | | | |
| Selling, general and administrative expenses | | | | | | | | | | |
| Exploration expenses | | | | | | | | | | |
| Depreciation, depletion and amortization | | | | | | | | | | |
| Taxes other than on income | | | | | | | | | | |
| Interest and debt expense | | | | | | | | | | |
| Other components of net periodic benefit costs | | | | | | | | | | |
| Total Costs and Other Deductions | | | | | | | | | | |
| Income (Loss) Before Income Tax Expense | | | | | | | | | | |
| Income Tax Expense (Benefit) | | | | | | | | | | |
| Net Income (Loss) | | | | | | | | | | |
| Less: Net income (loss) attributable to noncontrolling interests | | | | | | | | | | |
| Net Income (Loss) Attributable to Chevron Corporation | $ | | | | | $ | | | | $ | | | |
| Per Share of Common Stock | | | | | | | |
| Net Income (Loss) Attributable to Chevron Corporation | | | | | | | |
| - Basic | $ | | | | | $ | | | | $ | | | |
| - Diluted | $ | | | | | $ | | | | $ | | | |
| See accompanying Notes to the Consolidated Financial Statements. | |
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| Consolidated Statement of Comprehensive Income | |
| Millions of dollars | |
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| | Year ended December 31 | |
| | 2024 | | | 2023 | | | 2022 | |
| Net Income (Loss) | $ | | | | | $ | | | | | $ | | | |
| Currency translation adjustment | | | | | | | | |
| Unrealized net change arising during period | () | | | | | | | | () | | |
| Unrealized holding gain (loss) on securities | | | | | | | | |
| Net gain (loss) arising during period | () | | | | | | | | () | | |
| Derivatives | | | | | | | | |
| Net derivatives gain (loss) on hedge transactions | () | | | | () | | | | | | |
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| Reclassification to net income | | | | | | | | | () | | |
| Income tax benefit (cost) on derivatives transactions | | | | | () | | | | | | |
| Total | () | | | | | | | | () | | |
| Defined benefit plans | | | | | | | | |
| Actuarial gain (loss) | | | | | | | | |
| Amortization to net income of net actuarial loss and settlements | | | | | | | | | | | |
| Actuarial gain (loss) arising during period | | | | | () | | | | | | |
| Prior service credits (cost) | | | | | | | | |
| Amortization to net income of net prior service costs and curtailments | () | | | | () | | | | () | | |
| Prior service (costs) credits arising during period | () | | | | () | | | | () | | |
| Defined benefit plans sponsored by equity affiliates - benefit (cost) | () | | | | | | | | | | |
| Income tax benefit (cost) on defined benefit plans | () | | | | | | | | () | | |
| Total | | | | | () | | | | | | |
| Other Comprehensive Gain (Loss), Net of Tax | | | | | () | | | | | | |
| Comprehensive Income (Loss) | | | | | | | | | | | |
| Comprehensive loss (income) attributable to noncontrolling interests | () | | | | () | | | | () | | |
| Comprehensive Income (Loss) Attributable to Chevron Corporation | $ | | | | | $ | | | | | $ | | | |
| See accompanying Notes to the Consolidated Financial Statements. | | | | |
| | | | | | | | | |
| | | | | | | | |
| Consolidated Balance Sheet | |
| Millions of dollars, except per-share amounts | |
| | | | | | | | | | | | | | | | | |
| | |
| | At December 31 | |
| | 2024 | | 2023 | |
| Assets | | | | |
| Cash and cash equivalents | $ | | | | $ | | | |
| Time deposits | | | | | | |
| Marketable securities | | | | | | |
| Accounts and notes receivable (less allowance: 2024 - $; 2023 - $) | | | | | | |
| Inventories: | | | | |
| Crude oil and products | | | | | | |
| Chemicals | | | | | | |
| Materials, supplies and other | | | | | | |
| Total inventories | | | | | | |
| Prepaid expenses and other current assets | | | | | | |
| Total Current Assets | | | | | | |
| Long-term receivables, net (less allowances: 2024 - $; 2023 - $) | | | | | | |
| Investments and advances | | | | | | |
| Properties, plant and equipment, at cost | | | | | | |
| Less: Accumulated depreciation, depletion and amortization | | | | | | |
| Properties, plant and equipment, net | | | | | | |
| Deferred charges and other assets | | | | | | |
| Goodwill | | | | | | |
| Assets held for sale | | | | | | |
| Total Assets | $ | | | | $ | | | |
| Liabilities and Equity | | | | |
| Short-term debt | $ | | | | $ | | | |
| Accounts payable | | | | | | |
| Accrued liabilities | | | | | | |
| Federal and other taxes on income | | | | | | |
| Other taxes payable | | | | | | |
| Total Current Liabilities | | | | | | |
| Long-term debt1 | | | | | | |
| | |
| Deferred credits and other noncurrent obligations | | | | | | |
| Noncurrent deferred income taxes | | | | | | |
| Noncurrent employee benefit plans | | | | | | |
| Total Liabilities2 | $ | | | | $ | | | |
| Preferred stock (authorized shares; $ par value; issued) | | | | | | |
| Common stock (authorized shares; $ par value; shares issued at December 31, 2024 and 2023) | | | | | | |
| Capital in excess of par value | | | | | | |
| Retained earnings | | | | | | |
| Accumulated other comprehensive losses | () | | | () | | |
| Deferred compensation and benefit plan trust | () | | | () | | |
| Treasury stock, at cost (2024 - shares; 2023 - shares) | () | | | () | | |
| Total Chevron Corporation Stockholders’ Equity | | | | | | |
| Noncontrolling interests (includes redeemable noncontrolling interest of $ and $ at December 31, 2024 and 2023) | | | | | | |
| Total Equity | | | | | | |
| Total Liabilities and Equity | $ | | | | $ | | | |
| and $ at December 31, 2024 and 2023, respectively. | | | | |
| | | | | |
| See accompanying Notes to the Consolidated Financial Statements. | | | | |
| | | | | |
| | |
|
|
| | | | | | | | |
| Consolidated Statement of Cash Flows | |
| Millions of dollars | |
| | | | | | | | | | | | | | | | | | | | | | | |
|
| | Year ended December 31 | |
| | 2024 | | 2023 | | 2022 | |
| Operating Activities | | | | | | |
| Net Income (Loss) | $ | | | | $ | | | | $ | | | |
| Adjustments | | | | | | |
| Depreciation, depletion and amortization | | | | | | | | | |
| Dry hole expense | | | | | | | | | |
| Distributions more (less) than income from equity affiliates | () | | | () | | | () | | |
| Net before-tax gains on asset retirements and sales | () | | | () | | | () | | |
| Net foreign currency effects | () | | | | | | () | | |
| Deferred income tax provision | | | | | | | | | |
| Net decrease (increase) in operating working capital | | | | () | | | | | |
| Decrease (increase) in long-term receivables | | | | | | | | | |
| Net decrease (increase) in other deferred charges | () | | | () | | | () | | |
| Cash contributions to employee pension plans | () | | | () | | | () | | |
| Other | () | | | | | | | | |
| Net Cash Provided by Operating Activities | | | | | | | | | |
| Investing Activities | | | | | | |
| Acquisition of businesses, net of cash received | | | | | | | () | | |
| Capital expenditures | () | | | () | | | () | | |
| Proceeds and deposits related to asset sales and returns of investment | | | | | | | | | |
| Net maturities of (investments in) time deposits | () | | | | | | | | |
| Net sales (purchases) of marketable securities | | | | | | | | | |
| Net repayment (borrowing) of loans by equity affiliates | () | | | () | | | () | | |
| Net Cash Used for Investing Activities | () | | | () | | | () | | |
| Financing Activities | | | | | | |
| Net borrowings (repayments) of short-term obligations | | | | | | | | | |
| Proceeds from issuances of long-term debt | | | | | | | | | |
| Repayments of long-term debt and other financing obligations | () | | | () | | | () | | |
| Cash dividends - common stock | () | | | () | | | () | | |
| Net contributions from (distributions to) noncontrolling interests | () | | | () | | | () | | |
| Net sales (purchases) of treasury shares | () | | | () | | | () | | |
| Net Cash Provided by (Used for) Financing Activities | () | | | () | | | () | | |
| Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash | () | | | () | | | () | | |
| Net Change in Cash, Cash Equivalents and Restricted Cash | () | | | () | | | | | |
| Cash, Cash Equivalents and Restricted Cash at January 1 | | | | | | | | | |
| Cash, Cash Equivalents and Restricted Cash at December 31 | $ | | | | $ | | | | $ | | | |
| See accompanying Notes to the Consolidated Financial Statements. | |
| | | | | | | |
| | |
|
|
|
| | |
| | | | | | | | |
| Consolidated Statement of Equity | |
| Millions of dollars, except per-share amounts | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Acc. Other | Treasury | Chevron Corp. | | | | |
| Common | Retained | Comprehensive | Stock | Stockholders’ | | Noncontrolling | | Total |
| Stock1 | Earnings | Income (Loss) | (at cost) | Equity | | Interests | | Equity |
| Balance at December 31, 2021 | $ | | | $ | | | $ | () | | $ | () | | $ | | | | $ | | | | $ | | |
| Treasury stock transactions | | | — | | — | | — | | | | | — | | | | |
| | |
| Net income (loss) | — | | | | — | | — | | | | | | | | | |
Cash dividends ($ per share) | — | | () | | — | | — | | () | | | () | | | () | |
| Stock dividends | — | | () | | — | | — | | () | | | — | | | () | |
| Other comprehensive income | — | | — | | | | — | | | | | — | | | | |
| Purchases of treasury shares | — | | — | | — | | () | | () | | | — | | | () | |
| Issuances of treasury shares | | | — | | — | | | | | | | — | | | | |
| Other changes, net | — | | () | | — | | — | | () | | | | | | | |
| Balance at December 31, 2022 | $ | | | $ | | | $ | () | | $ | () | | $ | | | | $ | | | | $ | | |
| Treasury stock transactions | | | — | | — | | — | | | | | — | | | | |
| PDC Energy, Inc. acquisition | | | — | | — | | | | | | | — | | | | |
| Net income (loss) | — | | | | — | | — | | | | | | | | | |
Cash dividends ($ per share) | — | | () | | — | | — | | () | | | () | | | () | |
| Stock dividends | — | | () | | — | | — | | () | | | — | | | () | |
| Other comprehensive income | — | | — | | () | | — | | () | | | — | | | () | |
| Purchases of treasury shares | — | | — | | — | | () | | () | | | — | | | () | |
| Issuances of treasury shares | | | — | | — | | | | | | | — | | | | |
| Other changes, net | () | | () | | — | | — | | () | | | | | | () | |
| Balance at December 31, 2023 | $ | | | $ | | | $ | () | | $ | () | | $ | | | | $ | | | | $ | | |
| Treasury stock transactions | | | — | | — | | — | | | | | — | | | | |
| | |
| Net income (loss) | — | | | | — | | — | | | | | | | | | |
Cash dividends ($ per share) | — | | () | | — | | — | | () | | | () | | | () | |
| Stock dividends | — | | () | | — | | — | | () | | | — | | | () | |
| Other comprehensive income | — | | — | | | | — | | | | | — | | | | |
Purchases of treasury shares2 | — | | — | | — | | () | | () | | | — | | | () | |
| Issuances of treasury shares | | | — | | — | | | | | | | — | | | | |
| Other changes, net | — | | () | | — | | — | | () | | | () | | | () | |
| Balance at December 31, 2024 | $ | | | $ | | | $ | () | | $ | () | | $ | | | | $ | | | | $ | | |
| | | | | | | | | |
| | | Common Stock Share Activity | | | | |
| | Issued3 | | Treasury | | | Outstanding | | |
| Balance at December 31, 2021 | | | | | () | | | | | | | |
| Purchases | | — | | | () | | | | () | | | |
| Issuances | | — | | | | | | | | | | |
| Balance at December 31, 2022 | | | | | () | | | | | | | |
| Purchases | | — | | | () | | | | () | | | |
| Issuances | | — | | | | | | | | | | |
| Balance at December 31, 2023 | | | | | () | | | | | | | |
| Purchases | | — | | | () | | | | () | | | |
| Issuances | | — | | | | | | | | | | |
| Balance at December 31, 2024 | | | | | () | | | | | | | |
| , and $() associated with Chevron’s Benefit Plan Trust. Changes reflect capital in excess of par. |
|
| shares associated with Chevron’s Benefit Plan Trust. |
| See accompanying Notes to the Consolidated Financial Statements. |
| | | | | | | | | |
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 1
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 2
) | | $ | () | | | $ | | | | $ | () | | | $ | () | |
Components of Other Comprehensive Income (Loss)1: | | | | | | | | | |
Before Reclassifications | () | | | () | | | | | | | | | | |
Reclassifications2, 3 | | | | | | | () | | | | | | | |
Net Other Comprehensive Income (Loss) | () | | | () | | | () | | | | | | | |
| Balance at December 31, 2022 | $ | () | | | $ | () | | | $ | () | | | $ | () | | | $ | () | |
Components of Other Comprehensive Income (Loss)1: | | | | | | | | | |
Before Reclassifications | | | | | | | () | | | () | | | () | |
Reclassifications2, 3 | | | | | | | | | | | | | | |
| Net Other Comprehensive Income (Loss) | | | | | | | | | | () | | | () | |
| | |
| Balance at December 31, 2023 | $ | () | | | $ | () | | | $ | | | | $ | () | | | $ | () | |
Components of Other Comprehensive Income (Loss)1: | | | | | | | | | |
Before Reclassifications | () | | | () | | | () | | | | | | | |
Reclassifications2, 3 | | | | | | | | | | | | | | |
| Net Other Comprehensive Income (Loss) | () | | | () | | | () | | | | | | | |
| | |
| Balance at December 31, 2024 | $ | () | | | $ | () | | | $ | () | | | $ | () | | | $ | () | |
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 $ that are included in employee benefit costs for the year ended December 31, 2024. Related income taxes for the same period, totaling $, are reflected in Income Tax Expense on the Consolidated Statement of Income. All other reclassified amounts were insignificant.
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 3
| | | $ | | | | $ | | | | (Income) loss from equity affiliates | () | | | | () | | | () | |
| Distributions more (less) than income from equity affiliates | $ | () | | | | $ | () | | | $ | () | |
Net decrease (increase) in operating working capital was composed of the following: | | | | | | |
| Decrease (increase) in accounts and notes receivable | $ | () | | | | $ | | | | $ | () | |
| Decrease (increase) in inventories | () | | | | () | | | () | |
| Decrease (increase) in prepaid expenses and other current assets | () | | | | () | | | () | |
| Increase (decrease) in accounts payable and accrued liabilities | | | | | () | | | | |
| Increase (decrease) in income and other taxes payable | | | | | () | | | | |
| Net decrease (increase) in operating working capital | $ | | | | | $ | () | | | $ | | |
Net cash provided by operating activities includes the following cash payments: | | | | | | |
| Interest on debt (net of capitalized interest) | $ | | | | | $ | | | | $ | | |
| Income taxes | | | | | | | | | |
| Proceeds and deposits related to asset sales and returns of investment consisted of the following gross amounts: | | | | | | |
| Proceeds and deposits related to asset sales | $ | | | | | $ | | | | $ | | |
| Returns of investment from equity affiliates | | | | | | | | | |
| Proceeds and deposits related to asset sales and returns of investment | $ | | | | | $ | | | | $ | | |
Net maturities (investments) of time deposits consisted of the following gross amounts: | | | | | | |
| Investments in time deposits | $ | () | | | | $ | | | | $ | | |
| Maturities of time deposits | | | | | | | | | |
| Net maturities of (investments in) time deposits | $ | () | | | | $ | | | | $ | | |
Net sales (purchases) of marketable securities consisted of the following gross amounts: | | | | | | |
| Marketable securities purchased | $ | | | | | $ | () | | | $ | () | |
| Marketable securities sold | | | | | | | | | |
| Net sales (purchases) of marketable securities | $ | | | | | $ | | | | $ | | |
Net repayment (borrowing) of loans by equity affiliates: | | | | | | |
| Borrowing of loans by equity affiliates | $ | () | | | | $ | () | | | $ | () | |
| Repayment of loans by equity affiliates | | | | | | | | | |
| Net repayment (borrowing) of loans by equity affiliates | $ | () | | | | $ | () | | | $ | () | |
| Net borrowings (repayments) of short-term obligations consisted of the following gross and net amounts: | | | | | | |
| Repayments of short-term obligations | $ | () | | | | $ | | | | $ | | |
| Proceeds from issuances of short-term debt obligations | | | | | | | | | |
| Net borrowings (repayments) of short-term obligations with three months or less maturity | | | | | | | | | |
| Net borrowings (repayments) of short-term obligations | $ | | | | | $ | | | | $ | | |
Net sales (purchases) of treasury shares consists of the following gross and net amounts: | | | | | | |
| Shares issued for share-based compensation plans | $ | | | | | $ | | | | $ | | |
| Shares purchased under share repurchase and deferred compensation plans | () | | | | () | | | () | |
| Share repurchase excise tax payments | () | | | | | | | | |
| Net sales (purchases) of treasury shares | $ | () | | | | $ | () | | | $ | () | |
| Net contributions from (distributions to) noncontrolling interests consisted of the following gross and net amounts: | | | | | | |
| Distributions to noncontrolling interests | $ | () | | | | $ | () | | | $ | () | |
| Contributions from noncontrolling interests | | | | | | | | | |
| Net contributions from (distributions to) noncontrolling interests | $ | () | | | | $ | () | | | $ | () | |
|
|
|
| | | | | $ | | | | $ | | |
Note 4
Note 5
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | $ | — | | | $ | | | | $ | — | | | Properties, plant and equipment, net | — | | | | | | — | | | | |
| Right-of-use assets* | $ | | | | $ | | | | $ | | | | $ | | |
| Accrued liabilities | $ | | | | $ | — | | | $ | | | | $ | — | |
| Short-term debt | — | | | | | | — | | | | |
| Current lease liabilities | | | | | | | | | | | |
| Deferred credits and other noncurrent obligations | | | | — | | | | | | — | |
| Long-term debt | — | | | | | | — | | | | |
| Noncurrent lease liabilities | | | | | | | | | | | |
Total lease liabilities | $ | | | | $ | | | | $ | | | | $ | | |
| | | | | | | |
| Weighted-average remaining lease term (in years) | | | | | | | |
| Weighted-average discount rate | | % | | | % | | | % | | | % |
and $ in 2024, and $ and $ in 2023 for right-of-use assets obtained in exchange for new and modified lease liabilities for operating and finance leases, respectively.
| | $ | | | | $ | | | | Finance lease costs | | | | | | |
Total lease costs | $ | | | | $ | | | | $ | | |
* 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 |
| 2024 | | 2023 | | 2022 |
| Operating cash flows from operating leases | $ | | | | $ | | | | $ | | |
| Investing cash flows from operating leases | | | | | | | | |
| Operating cash flows from finance leases | | | | | | | | |
| Financing cash flows from finance leases | | | | | | | | |
| | $ | | | | 2026 | | | | | |
| 2027 | | | | | |
| 2028 | | | | | |
| 2029 | | | | | |
| Thereafter | | | | | |
| Total | $ | | | | $ | | |
| Less: Amounts representing interest | | | | | |
Total lease liabilities | $ | | | | $ | | |
Additionally, the company has $ in future undiscounted cash flows for operating leases not yet commenced. These leases are primarily for drilling rigs, time chartered vessels, exploration and production equipment and storage tanks. For
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 6
| | | $ | | | | $ | | | Total costs and other deductions | | | | | | | | | |
Net income (loss) attributable to CUSA | | | | | | | | | |
| | | $ | | | | Other assets | | | | | | |
| Current liabilities | | | | | | |
| Other liabilities | | | | | | |
| Total CUSA net equity | $ | | | | | $ | | |
| Memo: Total debt | $ | | | | | $ | | |
Note 7
percent equity ownership interest in Tengizchevroil LLP (TCO). Refer to Note 15 Investments and Advances for a discussion of TCO operations. percent of TCO is presented in the table below: | | | $ | | | | $ | | | | Costs and other deductions | | | | | | | | | |
| Net income attributable to TCO | | | | | | | | | |
| | | $ | | | | Other assets | | | | | | |
| Current liabilities | | | | | | |
| Other liabilities | | | | | | |
| Total TCO net equity | $ | | | | | $ | | |
Note 8
- billion in structural cost reductions by the end of 2026. As a result, the company recorded severance accruals during fourth quarter 2024 for employee reduction programs related to an enterprise-wide restructuring, which is expected to be substantially completed by the end of 2026. A charge of $ was recorded in fourth quarter 2024, with $ reported as “” and $ reported as “Selling, general and administrative expenses” on the Consolidated Statement of Income. Approximately $ is associated with employee reductions in U.S. Upstream, $ in International Upstream, $ in U.S. Downstream, $ in International Downstream and $ in All Other. Approximately $ is classified as current and $ is classified as long-term on the Consolidated Balance Sheet at December 31, 2024.
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | Accruals/Adjustments | | |
| Payments | () | |
| Balance at December 31, 2024 | $ | | |
Note 9
| $ | | | $ | | | $ | | | $ | | | $ | | | $ | | | $ | | | | Derivatives - not designated | | | | | | | | | | | | | | | | |
| Derivatives - designated | | | | | | | | | | | | | | | | |
| Total assets at fair value | $ | | | $ | | | $ | | | $ | | | $ | | | $ | | | $ | | | $ | | |
| Derivatives - not designated | | | | | | | | | | | | | | | | |
| Derivatives - designated | | | | | | | | | | | | | | | | |
| | | | | | | | |
| Total liabilities at fair value | $ | | | $ | | | $ | | | $ | | | $ | | | $ | | | $ | | | $ | | | Note 14
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 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 segments represent components of the company that engage in activities from which revenues are earned and expenses are incurred. Each segment has discrete financial information available. The CODM regularly reviews the operating results of these segments to assess their performance and make decisions about resources to be allocated to the segments. The company's primary country of operation is the United States of America, its country of domicile, while other components of the company's operations are reported as “International” (outside the United States).
Segment Sales and Other Operating Revenues Products are transferred between operating segments at internal product values that approximate market prices. Revenues for the upstream segment are derived primarily from the production and sale of crude oil, natural gas and NGLs, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the manufacture and sale of fuel and lubricant additives, renewable fuels, and the transportation and trading of refined products and crude oil. “All Other” activities include revenues from insurance operations, real estate activities and technology companies.
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| $ | | | $ | | | $ | | | $ | | | $ | | | $ | | |
| Intersegment revenue elimination | () | | () | | () | | () | | () | | () | | () | |
| Sales and Other Operating Revenues | | | | | | | | | | | | | | |
| | | | | | | |
| Income (loss) from equity affiliates | () | | | | | | | | | | () | | | |
Other income (loss)1 | | | | | | | | | | | | | | |
| Total Revenues and Other Income | | | | | | | | | | | | | | |
| | | | | | | |
Intersegment product transfers2 | | | | | () | | () | | () | | | | — | |
| Less expenses: | | | | | | | |
| Purchased crude oil and products | | | | | | | | | | | | | | |
| Operating and SG&A expenses | | | | | | | | | | | | | | |
| Depreciation, depletion and amortization | | | | | | | | | | | | | | |
Other costs and deductions3 | | | | | | | | | | | | | | |
| Total Costs and Other Deductions | | | | | | | | | | | | | | |
| | | | | | | |
| Income Tax Expense (Benefit) | | | | | | | | | | | () | | | |
| Less: Net income (loss) attributable to non-controlling interests | | | | | | | | | | | | | | |
| Net Income (Loss) Attributable to Chevron Corporation | $ | | | $ | | | $ | | | $ | | | $ | | | $ | () | | $ | | |
Values have been adjusted for eliminations, unless otherwise specified. |
1 Includes interest income of $ in “All Other.” |
2 Valuation of product transfers between operating segments. |
3 Includes interest expense of $ in “All Other.” |
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| $ | | | $ | | | $ | | | $ | | | $ | | | $ | | | | Intersegment revenue elimination | () | | () | | () | | () | | () | | () | | () | |
| Sales and Other Operating Revenues | | | | | | | | | | | | | | |
| | | | | | | |
| Income (loss) from equity affiliates | () | | | | | | | | | | () | | | |
Other income (loss)1 | () | | | | | | | | () | | | | () | |
| Total Revenues and Other Income | | | | | | | | | | | | | | |
| | | | | | | |
Intersegment product transfers2 | | | | | () | | () | | () | | | | — | |
| Less expenses: | | | | | | | |
| Purchased crude oil and products | | | | | | | | | | | | | | |
| Operating and SG&A expenses | | | | | | | | | | | | | | |
| Depreciation, depletion and amortization | | | | | | | | | | | | | | |
Other costs and deductions3 | | | | | | | | | | | | | | |
| Total Costs and Other Deductions | | | | | | | | | | | | | | |
| | | | | | | |
| Income Tax Expense (Benefit) | | | | | | | | | | | () | | | |
| Less: Net income (loss) attributable to non-controlling interests | | | | | | | | | | | | | | |
| Net Income (Loss) Attributable to Chevron Corporation | $ | | | $ | | | $ | | | $ | | | $ | | | $ | () | | $ | | |
| Values have been adjusted for eliminations, unless otherwise specified. |
1 Includes interest income of $ in “All Other.” |
2 Valuation of product transfers between operating segments. |
3 Includes interest expense of $ in “All Other.” |
| | | | | | | | | | | | | | | | | | | | | | | |
| Upstream | Downstream | Segment Total | All Other | Total |
| Year Ended December 31, 2022 | U.S. | Int'l. | U.S. | Int'l. |
| Sales and other operating revenues before elimination | $ | | | $ | | | $ | | | $ | | | $ | | | $ | | | $ | | |
| Intersegment revenue elimination | () | | () | | () | | () | | () | | () | | () | |
| Sales and Other Operating Revenues | | | | | | | | | | | | | | |
| | | | | | | |
| Income (loss) from equity affiliates | () | | | | | | | | | | () | | | |
Other income (loss)1 | | | | | | | () | | | | | | | |
| Total Revenues and Other Income | | | | | | | | | | | | | | |
| | | | | | | |
Intersegment product transfers2 | | | | | () | | () | | () | | | | — | |
| Less expenses: | | | | | | | |
| Purchased crude oil and products | | | | | | | | | | | | | | |
| Operating and SG&A expenses | | | | | | | | | | | | | | |
| Depreciation, depletion and amortization | | | | | | | | | | | | | | |
Other costs and deductions3 | | | | | | | | | | | | | | |
| Total Costs and Other Deductions | | | | | | | | | | | | | | |
| | | | | | | |
| Income Tax Expense (Benefit) | | | | | | | | | | | () | | | |
| Less: Net income (loss) attributable to non-controlling interests | | | | | | | | | | | | | | |
| Net Income (Loss) Attributable to Chevron Corporation | $ | | | $ | | | $ | | | $ | | | $ | | | $ | () | | $ | | |
| Values have been adjusted for eliminations, unless otherwise specified. |
1 Includes interest income of $ in “All Other.” |
2 Valuation of product transfers between operating segments. |
3 Includes interest expense of $ in “All Other.” |
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | | $ | | | | International | | | | | | |
| Goodwill | | | | | | |
| Total Upstream | | | | | | |
| Downstream | | | | |
| United States | | | | | | |
| International | | | | | | |
| Goodwill | | | | | | |
| Total Downstream | | | | | | |
| Total Segment Assets | | | | | | |
| All Other | | | | |
| United States | | | | | | |
| International | | | | | | |
| Total All Other | | | | | | |
| Total Assets – United States | | | | | | |
| Total Assets – International | | | | | | |
| Goodwill | | | | | | |
| Total Assets | $ | | | | | $ | | |
Note 15
| | $ | | | | $ | | | | $ | | | | $ | | | | | |
| | |
| Caspian Pipeline Consortium | | | | | | | | | | | | | | |
| Angola LNG Limited | | | | | | | | | | | | | | |
| | |
| Other | | | | | | | () | | | () | | | | |
| Total Upstream | | | | | | | | | | | | | | |
| Downstream | | | | | | | | | |
| Chevron Phillips Chemical Company LLC | | | | | | | | | | | | | | |
| GS Caltex Corporation | | | | | | | | | | | | | | |
| Other | | | | | | | | | | | | | | |
| Total Downstream | | | | | | | | | | | | | | |
| All Other | | | | | | | | | |
| Other | | | | () | | | () | | | () | | | () | |
| Total equity method | $ | | | | $ | | | | $ | | | | $ | | | | $ | | |
| Other non-equity method investments | | | | | | | | | | | |
| Total investments and advances | $ | | | | $ | | | | | | | | |
| Total United States | $ | | | | $ | | | | $ | | | | $ | | | | $ | | |
| Total International | $ | | | | $ | | | | $ | | | | $ | | | | $ | | |
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Caspian Pipeline Consortium Chevron has a 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 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 percent of Chevron Phillips Chemical Company LLC. Included in the investment balance is a loan with a principal balance of $ to fund a portion of the Golden Triangle Polymers Project in Orange, Texas, in which Chevron Phillips Chemical Company LLC owns percent.
GS Caltex Corporation Chevron owns percent of GS Caltex Corporation, a joint venture with GS Energy in South Korea. The joint venture imports, produces and markets petroleum products, petrochemicals and lubricants.
Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $, $ and $ with affiliated companies for 2024, 2023 and 2022, respectively. “Purchased crude oil and products” includes $, $ and $ with affiliated companies for 2024, 2023 and 2022, respectively.
“Accounts and notes receivable” on the Consolidated Balance Sheet includes $ and $ due from affiliated companies at December 31, 2024 and 2023, respectively. “Accounts payable” includes $ and $ due to affiliated companies at December 31, 2024 and 2023, respectively.
percent basis for all equity affiliates as well as Chevron’s total share, which includes Chevron’s net loans to affiliates of $, $ and $ at December 31, 2024, 2023 and 2022, respectively. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Affiliates | | | Chevron Share |
| Year ended December 31 | 2024 | | 2023 | | 2022 | | | 2024 | | 2023 | | 2022 |
| Total revenues | $ | | | | $ | | | | $ | | | | | $ | | | | $ | | | | $ | | |
Income before income tax expense* | | | | | | | | | | | | | | | | | | |
| Net income attributable to affiliates | | | | | | | | | | | | | | | | | | |
| At December 31 | | | | | | | | | | | | |
| Current assets | $ | | | | $ | | | | $ | | | | | $ | | | | $ | | | | $ | | |
| Noncurrent assets | | | | | | | | | | | | | | | | | | |
| Current liabilities | | | | | | | | | | | | | | | | | | |
| Noncurrent liabilities | | | | | | | | | | | | | | | | | | |
| Total affiliates’ net equity | $ | | | | $ | | | | $ | | | | | $ | | | | $ | | | | $ | | |
* 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 2024 was $, with Chevron’s share being $.
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 16
separate lawsuits filed by various U.S. cities and counties, U.S. states, the District of Columbia, the Commonwealth of Puerto Rico, Native American tribes, and a trade group in both federal and state courts.3 The lawsuits have asserted various causes of action, including public nuisance, private nuisance, failure to warn, fraud, conspiracy to commit fraud, design defect, product defect, trespass, negligence, impairment of public trust, equitable relief for pollution, impairment and destruction of natural resources, unjust enrichment, violations of consumer and environmental protection statutes, violations of unfair competition statutes, violations of a federal antitrust statute, and violations of federal and state RICO statutes, based upon, among other things, the company’s production of oil and gas products and alleged misrepresentations or omissions relating to climate change risks associated with those products. Further such proceedings are likely to be brought by other parties. 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 U.S. Supreme Court has also denied petitions for certiorari to review a decision from the Hawaii Supreme Court allowing claims brought by the City and County of Honolulu to proceed past the pleadings. The unprecedented legal theories set forth in these proceedings include claims for damages (both compensatory and punitive), injunctive and other forms of equitable relief, including without limitation abatement, contribution to abatement funds, disgorgement of profits and equitable relief for pollution, impairment and destruction of natural resources, civil penalties and liability for fees and costs of suits. 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.3 The cases are: Municipality of Bayamon et al. 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.) (dismissed on the merits, Plaintiff’s appeal pending); Anne Arundel County v. BP P.L.C., et al., No. C-02-CV-21-000565 (Md. Cir. Ct.) (dismissed on the merits, Plaintiff’s appeal pending); Mayor and City Council of Baltimore v. BP P.L.C., et al., No. 24-C-18-004219 (Md. Cir. Ct.) (dismissed on the merits, Plaintiff’s appeal pending); People ex rel. Bonta v. Exxon Mobil Corp., et al., No. CGC-23-609134 (Cal. Super. Ct.); Bucks County v. BP P.L.C., et al., No. 2024-01836 (Pa. Ct. Com. Pl.); City of Charleston v. Brabham Oil Co., et al., No. 2020-CP-10-3975 (S.C. Ct. of Com. Pl.); 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., C.A. 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.) (dismissed on the merits, appeal may be filed); Estado Libre Asociado de Puerto Rico [Commonwealth of Puerto Rico] v. Exxon Mobil Corp., et al., No. SJ2024CV06512 (Tribunal de Primera Instancia, Estado Libre Asociado de P.R.) [P.R. Ct. of First Instance, Commonwealth of P.R.]; 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, Inc. v. Chevron Corp., et al., No. CGC-18-571285 (Cal. Super. Ct.) (voluntarily dismissed); State of Rhode Island v. Chevron Corp., et al., C.A. 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. 2024CH01024 (Ill. Cir. Ct.); Maine v. BP P.L.C. et al., No. PORSC-CV-24-442 (Me. Super. Ct.).
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
4 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. Apache Corporation (of Delaware), et al., No. 10-19579 (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.).
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 17
| | | $ | | | | $ | | | | Deferred | | | | | | | | | |
| State and local | | | | | | |
| Current | | | | | | | | | |
| Deferred | | | | | | | | | |
| Total United States | | | | | | | | | |
| International | | | | | | |
| Current | | | | | | | | | |
| Deferred | | | | | () | | | () | |
| Total International | | | | | | | | | |
| Total income tax expense (benefit) | $ | | | | | $ | | | | $ | | |
| | | $ | | | | $ | | | | International | | | | | | | | | |
| Total income (loss) before income taxes | | | | | | | | | |
| Theoretical tax (at U.S. statutory rate of 21%) | | | | | | | | | |
|
| Equity affiliate accounting effect | () | | | | () | | | () | |
| Effect of income taxes from international operations | | | | | | | | | |
State and local taxes on income, net of U.S. federal income tax benefit | | | | | | | | | |
Prior year tax adjustments, claims and settlements 1 | () | | | | () | | | () | |
| Tax credits | () | | | | () | | | () | |
Other U.S. 1, 2 | () | | | | () | | | () | |
| Total income tax expense (benefit) | $ | | | | | $ | | | | $ | | |
| | | | | | |
Effective income tax rate 3 | | % | | | | % | | | % |
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 (2024 - $(); 2023 - $(); 2022 - $()).
3 The company’s effective tax rate is reflective of equity income reported on an after-tax basis as part of the “Total Income (Loss) Before Income Tax Expense,” in accordance with U.S. Generally Accepted Accounting Principles. Chevron’s share of its equity affiliates’ total income tax expense in 2024 was $.
The 2024 increase in income tax expense of $ and the change in the company’s effective tax rate from percent in 2023 to percent in 2024 were primarily a result of the tax impacts from the asset sales in Canada.
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | | $ | | | | Investments and other | | | | | | |
| Total deferred tax liabilities | | | | | | |
| Deferred tax assets | | | | |
| Foreign tax credits | () | | | | () | |
| Asset retirement obligations/environmental reserves | () | | | | () | |
| Employee benefits | () | | | | () | |
| Deferred credits | () | | | | () | |
| Tax loss carryforwards | () | | | | () | |
| Other accrued liabilities | () | | | | () | |
| Inventory | () | | | | () | |
| Operating leases | () | | | | () | |
| Miscellaneous | () | | | | () | |
| Total deferred tax assets | () | | | | () | |
| Deferred tax assets valuation allowance | | | | | | |
| Total deferred income taxes, net | $ | | | | | $ | | |
Deferred tax liabilities increased by $ from year-end 2023, driven by deferred tax impacts resulting from the asset sales in Canada and foreign exchange impacts. Deferred tax assets increased by $ from year-end 2023. This increase was primarily related to increases in foreign tax credits and foreign exchange impacts, partially offset by decreases in tax loss carryforwards and other accrued liabilities.
The overall valuation allowance, which increased by $ from year-end 2023, 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 2024, the company had gross tax loss carryforwards of approximately $ and tax credit carryforwards of approximately $, 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 2025 through 2043. U.S. foreign tax credit carryforwards of $ will expire between 2025 and 2034.
) | | | $ | () | | | Noncurrent deferred income taxes | | | | | | |
| Total deferred income taxes, net | $ | | | | | $ | | |
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 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.
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | | $ | | | | $ | | | | Foreign currency effects | | | | | () | | | () | |
| Additions based on tax positions taken in current year | | | | | | | | | |
Additions for tax positions taken in prior years | | | | | | | | | |
| Reductions based on tax positions taken in current year | () | | | | () | | | | |
Reductions for tax positions taken in prior years | () | | | | () | | | () | |
| Settlements with taxing authorities in current year | | | | | () | | | () | |
|
| Balance at December 31 | $ | | | | | $ | | | | $ | | |
Approximately percent of the $ of unrecognized tax benefits at December 31, 2024, 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. Of the amount of unrecognized tax benefits the company has identified as of December 31, 2024, it is reasonably possible that developments on tax matters in certain tax jurisdictions may result in decreases of approximately percent within the next 12 months. Given the number of years that still remain subject to examination and the number of matters being examined in the various tax jurisdictions, the company is unable to estimate the range of possible adjustments to the balance of unrecognized tax benefits.
On the Consolidated Statement of Income, the company reports interest and penalties related to liabilities for uncertain tax positions as “Income Tax Expense (Benefit).” As of December 31, 2024, accrued expense of $ for anticipated interest and penalties was included on the Consolidated Balance Sheet, compared with accrued expense of $ as of year-end 2023. Income tax expense (benefit) associated with interest and penalties was $, $ and $ in 2024, 2023 and 2022, respectively.
| | | $ | () | | | $ | | | Property and other miscellaneous taxes | | | | | | | | | |
| Payroll taxes | | | | | | | | | |
| Taxes on production | | | | | | | | | |
| Total United States | | | | | | | | | |
| International | | | | | | |
| Import duties and other levies | | | | | | | | | |
Property and other miscellaneous taxes | | | | | | | | | |
| Payroll taxes | | | | | | | | | |
| Taxes on production | | | | | | | | | |
| Total International | | | | | | | | | |
| Total taxes other than on income | $ | | | | | $ | | | | $ | | |
|
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 18
| $ | | | $ | | | | $ | | | $ | | | $ | | | | $ | | | $ | | | $ | | | | $ | | | $ | | | $ | | | | International | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Upstream | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Downstream | | | | | | | | | | | | | | | |
| United States | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| International | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Downstream | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| All Other | | | | | | | | | | | | | | | |
| United States | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| International | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total All Other | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total United States | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total International | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | $ | | | $ | | | $ | | | | $ | | | $ | | | $ | | | | $ | | | $ | | | $ | | | | $ | | | $ | | | $ | | |
1Other than the United States and Australia, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2024. Australia had PP&E of $, $ and $ in 2024, 2023 and 2022, respectively. Gross Investment at Cost and Additions at Cost for 2023 each include $ associated with the PDC acquisition.
2Net of dry hole expense related to prior years’ expenditures of $, $ and $ in 2024, 2023 and 2022, respectively.
3Depreciation expense includes accretion expense of $, $ and $ in 2024, 2023 and 2022, respectively, and impairments and write-offs of $, $ and $ in 2024, 2023 and 2022, respectively.
Note 19
| | | $ | | | Notes payable to banks and others with originating terms of one year or less | | | | | | |
Current maturities of long-term debt* | | | | | | |
Current maturities of long-term finance leases | | | | | | |
| Redeemable long-term obligations | | | | | | |
| |
Subtotal | | | | | | |
| Reclassified to long-term debt | () | | | | () | |
| Total short-term debt | $ | | | | | $ | | |
* Inclusive of unamortized premiums of $ at December 31, 2024 and $ at December 31, 2023. |
| | 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, 2024, the company had no interest rate swaps on short-term debt.
At December 31, 2024, the company had $ in -day committed credit facilities with various major banks that enable the refinancing of short-term obligations. The credit facilities allow the company the option to convert outstanding short-term obligations into a term loan for a period of up to one year from the facilities termination date. This supports commercial paper borrowing and can also be used for general corporate purposes. The company’s practice has been to replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under these facilities would be unsecured indebtedness at interest rates based on the Secured Overnight Financing Rate (SOFR), or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. borrowings were outstanding under these facilities at December 31, 2024.
and $ of short-term debt as long-term at December 31, 2024 and 2023, respectively. Settlement of these obligations is not expected to require the use of working capital within one year, as the company had the intent and the ability, as evidenced by committed credit facilities, to continue refinancing them.
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 20
.
| Notes due 2026 | | | | | | | | | | |
| Notes due 2027 | | | - | | | | | | | |
| Notes due 2028 | | | | | | | | | | |
| Notes due 2029 | | | | | | | | | | |
| Notes due 2030 | | | | | | | | | | |
| Debentures due 2031 | | | | | | | | | | |
| Debentures due 2032 | | | - | | | | | | | |
| Notes due 2040 | | | | | | | | | | |
| Notes due 2041 | | | | | | | | | | |
| Notes due 2043 | | | | | | | | | | |
| Notes due 2044 | | | | | | | | | | |
| Notes due 2047 | | | | | | | | | | |
| Notes due 2049 | | | | | | | | | | |
| Notes due 2050 | | | - | | | | | | | |
| Debentures due 2097 | | | | | | | | | | |
| Bank loans due 2025 to 2027 | | | - | | | | | | | |
| |
| Medium-term notes, maturing from 2033 to 2038 | | | - | | | | | | | |
| Notes due 2024 | | | | | | | | | | |
| Total including debt due within one year | | | | | | | | | | |
| Debt due within one year | | | | | () | | | | () | |
| |
| |
| Fair market value adjustment for debt acquired in the Noble acquisition | | | | | | | |
| Reclassified from short-term debt | | | | | | | | | | |
| Unamortized discounts and debt issuance costs | | | | | () | | | | () | |
Finance lease liabilities3 | | | | | | | | | | |
| Total long-term debt | | | | | $ | | | | | $ | | |
1 Weighted-average interest rate at December 31, 2024. | | | | | | | | |
2 Range of interest rates at December 31, 2024. | | | | | | | | |
| | | | | | | |
Chevron has an automatic shelf registration statement that expires in November 2027. This registration statement is for an unspecified amount of nonconvertible debt securities issued or guaranteed by Chevron Corporation or CUSA.
Long-term debt excluding finance lease liabilities with a principal balance of $ matures as follows: 2025 – $; 2026 – $; 2027 – $; 2028 – $; 2029 – $; and after 2029 – $.
Note 21
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| $ | | | $ | | | Additions to capitalized exploratory well costs pending the determination of proved reserves | | | | | | |
Reclassifications to wells, facilities and equipment based on the determination of proved reserves | | | | | () | |
| Capitalized exploratory well costs charged to expense | | () | | () | |
| Ending balance at December 31 | $ | | | $ | | | $ | | |
| $ | | | $ | | | Exploratory well costs capitalized for a period greater than one year | | | | | | |
| Balance at December 31 | $ | | | $ | | | $ | | |
Number of projects with exploratory well costs that have been capitalized for a period greater than one year* | | | | | | |
*Certain projects have multiple wells or fields or both.
Of the $ of exploratory well costs capitalized for more than one year at December 31, 2024, $ is related to projects that had drilling activities underway or firmly planned for the near future. The $ balance is related to 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 $ referenced above had the following activities associated with assessing the reserves and the projects’ economic viability: (a) $ ( projects) – undergoing front-end engineering and design with final investment decision expected within ; (b) $ ( projects) – development alternatives under review. While progress was being made on all projects, the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations associated with the projects. Approximately half of these decisions are expected to occur in the next .
of suspended well costs capitalized for a period greater than one year as of December 31, 2024, represents exploratory wells in 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 | $ | | | | | | |
| 2010-2014 | | | | | | |
| 2015-2023 | | | | | | |
| Total | $ | | | | | | |
| | | | |
| Aging based on drilling completion date of last suspended well in project: | Amount | | | Number of projects |
| 2008-2012 | $ | | | | | | |
| 2013-2016 | | | | | | |
| 2017-2024 | | | | | | |
| Total | $ | | | | | | |
Note 22
($ after tax), $ ($ after tax) and $ ($ after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance shares and restricted stock units for 2024, 2023 and 2022 was $ ($ after tax), $() ($() after tax) and $ ($ after tax), respectively. No significant stock-based compensation cost was capitalized at December 31, 2024, or December 31, 2023.
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Cash paid to settle performance shares, restricted stock units and stock appreciation rights was $, $ and $ for 2024, 2023 and 2022, 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 million shares may be issued under the 2022 LTIP. For awards issued on or after May 25, 2022, no more than million of those shares may be issued in the form of full value awards such as share-settled restricted stock, share-settled restricted stock units, share-settled performance shares and other share-settled awards that do not require full payment in cash or property for shares underlying such awards by the award recipient. Contractual terms of equity awards vary between for the performance shares and special restricted stock units with cliff vesting at the end of the contractual period, for standard restricted stock units with cliff vesting at the end of the contractual period and years for the stock options and stock appreciation rights with graded vesting provisions by which one-third of each award vests around each of the first, second and third anniversaries of the date of grant. Commencing for grants issued in January 2023 and after, standard restricted stock units vest ratably on an annual basis over a 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
| | | | | | Volatility2 | | | % | | | | % | | | % |
Risk-free interest rate based on zero coupon U.S. treasury note | | | % | | | | % | | | % |
| Dividend yield | | | % | | | | % | | | % |
| Weighted-average fair value per option granted | $ | | | | | $ | | | | $ | | | |
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.
| | $ | | | | | | | | Granted | | | | $ | | | | | | |
| Exercised | () | | | $ | | | | | | |
| Forfeited | () | | | $ | | | | | | |
| Outstanding at December 31, 2024 | | | | $ | | | | | | $ | | |
| Exercisable at December 31, 2024 | | | | $ | | | | | | $ | | |
The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2024, 2023 and 2022 was $, $ and $, respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.
As of December 31, 2024, there was $ 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 years.
At January 1, 2024, the number of LTIP performance shares outstanding was equivalent to shares. During 2024, performance shares were granted, shares vested with cash proceeds distributed to recipients and shares were forfeited. At December 31, 2024, there were performance shares outstanding, of which are payable in cash and are payable in shares. The fair value of the liability recorded for these instruments payable in cash was $ and was measured largely using the Monte Carlo simulation method.
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 23
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.
| | $ | | | | | $ | | | | $ | | | | $ | | | | | $ | | | | Service cost | | | | | | | | | | | | | | | | | | | |
| Interest cost | | | | | | | | | | | | | | | | | | | |
| Plan participants’ contributions | | | | | | | | | | | | | | | | | | | |
| Plan amendments | | | | | | | | | | | | | | | | | | | |
| Actuarial (gain) loss | () | | | () | | | | | | | | | | () | | | | | |
| Foreign currency exchange rate changes | | | | () | | | | | | | | | | () | | | | | |
| Benefits paid | () | | | () | | | | () | | | () | | | () | | | | () | |
| Actual expenses/taxes | | | | () | | | | | | | | | | | | | | | |
| Divestitures/Acquisitions | | | | | | | | | | | () | | | | | | | | |
| Curtailment | | | | | | | | | | | | | | () | | | | | |
| Special termination costs | | | | | | | | | | | | | | | | | | | |
| Benefit obligation at December 31 | | | | | | | | | | | | | | | | | | | |
| Change in Plan Assets | | | | | | | | | | | | | |
| Fair value of plan assets at January 1 | | | | | | | | | | | | | | | | | | | |
| Actual return on plan assets | | | | () | | | | | | | | | | | | | | | |
| Foreign currency exchange rate changes | | | | () | | | | | | | | | | | | | | | |
| Employer contributions | | | | | | | | | | | | | | | | | | | |
| Plan participants’ contributions | | | | | | | | | | | | | | | | | | | |
| Benefits paid | () | | | () | | | | () | | | () | | | () | | | | () | |
| Actual expenses | | | | () | | | | | | | | | | | | | | | |
| | | | | | |
| Fair value of plan assets at December 31 | | | | | | | | | | | | | | | | | | | |
| Funded status at December 31 | $ | () | | | $ | () | | | | $ | () | | | $ | () | | | $ | () | | | | $ | () | |
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | $ | | | | | $ | | | | $ | | | | $ | | | | | $ | | | | Accrued liabilities | () | | | () | | | | () | | | () | | | () | | | | () | |
| Noncurrent employee benefit plans | () | | | () | | | | () | | | () | | | () | | | | () | |
| Net amount recognized at December 31 | $ | () | | | $ | () | | | | $ | () | | | $ | () | | | $ | () | | | | $ | () | |
For the year ended December 31, 2024, the decrease in benefit obligations was primarily due to actuarial gains caused by higher discount rates used to value the obligations. For the year ended December 31, 2023, the increase in benefit obligations was primarily due to actuarial losses caused by lower discount rates used to value the obligations.
and $ at the end of 2024 and 2023, respectively. These amounts consisted of: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | |
| 2024 | | | 2023 | | Other Benefits |
| U.S. | | Int’l. | | | U.S. | | Int’l. | | 2024 | | | 2023 |
| Net actuarial (gain) loss | $ | | | | $ | | | | | $ | | | | $ | | | | $ | () | | | | $ | () | |
| Prior service (credits) costs | | | | | | | | | | | | | | () | | | | () | |
| Total recognized at December 31 | $ | | | | $ | | | | | $ | | | | $ | | | | $ | () | | | | $ | () | |
The accumulated benefit obligations for all U.S. and international pension plans were $ and $, respectively, at December 31, 2024, and $ and $, respectively, at December 31, 2023.
| | $ | | | | | $ | | | | $ | | | | Accumulated benefit obligations | | | | | | | | | | | | |
| Fair value of plan assets | | | | | | | | | | | | |
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| $ | | | | | $ | | | $ | | | $ | | | $ | | | | $ | | | | | $ | | | | $ | | | | Interest cost | | | | | | | | | | | | | | | | | | | | | | | | |
| Expected return on plan assets | () | | () | | | | () | | () | | () | | () | | | | | | | | | | | |
| Amortization of prior service costs (credits) | | | | | | | | | | | | | | | | () | | | | () | | | () | |
| Recognized actuarial (gains) losses | | | | | | | | | | | | | | | | () | | | | () | | | | |
| Settlement losses (gains) | | | | | | | | | | | | | () | | | | | | | | | | | |
| Curtailment losses (gains) | | | | | | | | | | | | | () | | | () | | | | | | | | |
| Special termination benefits | | | | | | | | | | | | | | | | | | | | | | | | |
| Acquisition/Divestiture losses (gains) | | | | | | | | | () | | | | | | | | | | | | | | | |
| Total net periodic benefit cost | | | | | | | | | | | | | | | | | | | | | | | | |
| Changes Recognized in Comprehensive Income | | | | | | | | | | | | | | | |
| Net actuarial (gain) loss during period | () | | | | | | | | | | () | | () | | | () | | | | | | | () | |
| Amortization of actuarial (gain) loss | () | | () | | | | () | | () | | () | | () | | | | | | | | | | () | |
| Prior service (credits) costs during period | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of prior service (costs) credits | () | | () | | | | () | | () | | () | | () | | | | | | | | | | | |
Total changes recognized in other
comprehensive income | () | | | | | | | | | | () | | () | | | () | | | | | | | () | |
Recognized in Net Periodic Benefit Cost and Other Comprehensive Income | $ | | | $ | | | | | $ | | | $ | | | $ | () | | $ | () | | | $ | | | | | $ | | | | $ | () | |
% | | % | | | | % | | % | | | % | | % | | | % | | | | % | | | % | | Rate of compensation increase | | % | | % | | | | % | | % | | | % | | % | | N/A | | | N/A | | N/A |
Assumptions used to determine net periodic benefit cost: | | | | | | | | | | | | | | | | |
| Discount rate for service cost | | % | | % | | | | % | | % | | | % | | % | | | % | | | | % | | | % |
| Discount rate for interest cost | | % | | % | | | | % | | % | | | % | | % | | | % | | | | % | | | % |
| Expected return on plan assets | | % | | % | | | | % | | % | | | % | | % | | N/A | | | N/A | | N/A |
| Rate of compensation increase | | % | | % | | | | % | | % | | | % | | % | | N/A | | | N/A | | N/A |
percent for U.S. pension plan assets, which account for 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 preceding the year-end measurement date. Management considers the 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 percent, percent, and percent for 2024, 2023, and 2022, respectively, for the main U.S. pension plan and percent, percent, and percent for 2024, 2023, and 2022, respectively, for the main U.S. OPEB plans.
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Plan Assets and Investment Strategy
| | $ | | | | $ | | | | $ | | | | $ | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | International | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Collective Trusts/Mutual Funds2 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Income | | | | | | | | | | | | | | | | | | | | |
| Government | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Corporate | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Bank Loans | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Mortgage/Asset Backed | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Collective Trusts/Mutual Funds2 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Mixed Funds3 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Real Estate4 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Alternative Investments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash and Cash Equivalents | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other5 | | | | () | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total at December 31, 2023 | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | |
| At December 31, 2024 | | | | | | | | | | | | | | | | | | | | |
| Equities | | | | | | | | | | | | | | | | | | | | |
U.S.1 | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | |
| International | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Collective Trusts/Mutual Funds2 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Income | | | | | | | | | | | | | | | | | | | | |
| Government | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Corporate | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Bank Loans | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Mortgage/Asset Backed | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Collective Trusts/Mutual Funds2 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Mixed Funds3 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Real Estate4 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Alternative Investments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash and Cash Equivalents | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other5 | | | | () | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total at December 31, 2024 | $ | | | | $ | | | | $ | | | | $ | | | | $ | | | | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | |
1 There were investments in the company’s common stock at December 31, 2024 or December 31, 2023.
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).
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | $ | | | | | $ | | | | | $ | | | | | $ | | | | Actual Return on Plan Assets: | | | | | | | | | | | | |
| Assets held at the reporting date | | | | | | | | | | | | | | | | | |
| Assets sold during the period | | | | | | | | | | | | () | | | | () | |
| Purchases, Sales and Settlements | | | | | | | | | | | | | | | | | |
| Transfers in and/or out of Level 3 | | | | | | | | () | | | | | | | | () | |
| Total at December 31, 2023 | $ | | | | $ | | | | | $ | | | | | $ | | | | | $ | | |
| Actual Return on Plan Assets: | | | | | | | | | | | | |
| Assets held at the reporting date | () | | | | | | | | | | | | | | | | |
| Assets sold during the period | | | | | | | | | | | | | | | | | |
| Purchases, Sales and Settlements | | | | | | | | | | | | () | | | | () | |
| Transfers in and/or out of Level 3 | | | | | | | | | | | | () | | | | | |
| Total at December 31, 2024 | $ | | | | $ | | | | | $ | | | | | $ | | | | | $ | | |
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 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 – percent, Fixed Income – percent, Real Estate – percent, Alternative Investments – percent and Cash – percent. For the U.K. pension plan, the U.K. Board of Trustees has established the following asset allocation guidelines: Equities – percent, Fixed Income – percent, Real Estate – percent, and Cash – 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.
and $ to its U.S. and international pension plans, respectively. In 2025, the company expects contributions to be approximately $ to its U.S. plans and $ 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 $ in 2025; $ was paid in 2024.
| | $ | | | | $ | | | | 2026 | | | | | | | | |
| 2027 | | | | | | | | |
| 2028 | | | | | | | | |
| 2029 | | | | | | | | |
| 2030-2034 | | | | | | | | |
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 $, $ and $ in 2024, 2023 and 2022, respectively.
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
, $ and $ in 2024, 2023 and 2022, 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
guarantee to an equity affiliate totaling $. This guarantee is associated with certain payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 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.
; 2026 – $; 2027 – $; 2028 – $; 2029 – $; after 2029 – $. The aggregate amount of required payments for other unconditional purchase obligations are: 2025 – $; 2026 – $; 2027 – $; 2028 – $; 2029 – $; after 2029 – $. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were $ in 2024, $ in 2023 and $ in 2022.
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Of the remaining year-end 2024 environmental reserves balance of $, $ is related to the company’s U.S. downstream operations, $ to its international downstream operations, and $ 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 2024 had a recorded liability that was material to the company’s results of operations, consolidated financial position or liquidity.
, $ was spent in 2024, and the balance at the end of 2024 was $.
Note 25
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | | $ | | | | $ | | | |
| Liabilities assumed in the PDC acquisition | | | | | | | | | |
| Liabilities incurred | | | | | | | | | |
| Liabilities settled | () | | | | () | | | () | |
| Reduction due to asset sales | () | | | | () | | | () | |
| Accretion expense | | | | | | | | | |
| Revisions in estimated cash flows | | | | | | | | | |
| Balance at December 31 | $ | | | | | $ | | | | $ | | |
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 $ balance at the end of 2024 was $.
Note 26
and $ at December 31, 2024 and 2023, 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
relating to the sale of certain properties. Of this amount, approximately $ and $ related to upstream and downstream, respectively. Earnings in 2023 included after-tax gains of approximately $ relating to the sale of certain properties, of which approximately $ and $ related to upstream and downstream assets, respectively. Earnings in 2022 included after-tax gains of approximately $ relating to the sale of certain properties, of which approximately $ and $ related to upstream and downstream assets, respectively. Earnings in 2024 included after-tax charges of approximately $ for severance ($ in All Other, $ in U.S. Downstream, $ in U.S. Upstream, $ in International Upstream, $ in International Downstream) and $ for impairments ($ in International Downstream, $ in International Upstream, $ in U.S. Downstream). Earnings in 2023 included after-tax charges of approximately $ for decommissioning obligations from previously divested oil and gas production assets in the U.S. Upstream Gulf of America, $ for U.S. Upstream impairments, mainly in California, and several tax items with a net benefit of $ in International Upstream. Earnings in 2022 included after-tax charges of approximately $ for impairments and other asset write-offs related to International Upstream, $ for an early contract termination in U.S. Upstream, and $ for pension settlement costs in All Other.
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | | $ | | | | $ | | | | Less: Capitalized interest | | | | | | | | | |
| Interest and debt expense | $ | | | | | $ | | | | $ | | |
| Research and development expenses | $ | | | | | $ | | | | $ | | |
Excess of replacement cost over the carrying value of inventories (LIFO method) | $ | | | | | $ | | | | $ | | |
| LIFO profits (losses) on inventory drawdowns included in earnings | $ | () | | | | $ | | | | $ | | |
Foreign currency effects* | $ | | | | | $ | () | | | $ | | |
* Includes $, $() and $ in 2024, 2023 and 2022, respectively, for the company’s share of equity affiliates’ foreign currency effects.
in goodwill on the Consolidated Balance Sheet, of which $ is in the upstream segment primarily related to the 2005 is in the downstream segment related to the 2022 acquisition of Renewable Energy Group, Inc. The company tested this goodwill for impairment during 2024, and impairment was required.
Note 28
and $ at December 31, 2024, and December 31, 2023, 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 $ at December 31, 2024, 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 $ at December 31, 2024, 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 and $ at December 31, 2024, and December 31, 2023, respectively, are included within “Investments and advances” on the Consolidated Balance Sheet.
| | | | | | | | |
Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 29
, with approximately million shares of Chevron common stock issued as consideration in the transaction. The shares represented approximately percent of the shares of Chevron common stock outstanding immediately after the transaction closed on August 7, 2023.The acquisition was accounted for as a business combination under ASC 805, which requires assets acquired and liabilities assumed to be measured at their acquisition date fair value. Oil and gas properties were valued using a discounted cash flow approach that incorporated internally generated price assumptions and production profiles together with appropriate operating cost and development cost assumptions. Debt assumed in the acquisition was valued based on observable market prices for PDC’s debt. As a result of measuring the assets acquired and the liabilities assumed at fair value, there was no goodwill or bargain purchase recognized.
| Properties, plant and equipment | | | | |
| Other assets | | | | |
| Total assets acquired | | | | |
| Current liabilities | | | | |
| Long-term debt | | | | |
| Deferred income tax | | | | |
| Other liabilities | | | | |
| Total liabilities assumed | | | | |
| Purchase Price | | | $ | | |
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
, pursuant to which Hess stockholders will receive shares of Chevron common stock for each Hess share. The transaction was unanimously approved by the Boards of Directors of both companies.On May 28, 2024, a majority of Hess stockholders voted to approve the merger. Following the Federal Trade Commission’s (FTC) review of the transaction, on September 30, 2024, the FTC announced that a majority of the Commission voted to accept a consent agreement among the FTC, Chevron and Hess, resolving the concerns the FTC identified during its review of the transaction. Chevron and Hess have taken and will continue to take appropriate steps to maintain our ability to close the merger under the Hart-Scott-Rodino Act of 1976, as amended. The filing of an arbitration relating to the right of first refusal contained in the Stabroek Block operating agreement among Hess Guyana Exploration Limited, a wholly owned subsidiary of Hess, and affiliates of Exxon Mobil Corporation, and China National Offshore Oil Corporation has delayed completion of the transaction. An arbitration decision against Hess Guyana and in favor of Exxon Guyana and CNOOC Guyana would cause the transaction not to be completed. The arbitration merits hearing has been scheduled for May 2025, with a decision expected in approximately the following three months.
Chevron and Hess are working to complete the merger as soon as practicable. However, neither Chevron nor Hess can predict the actual date on which the transaction will be completed, if at all, because it is subject to conditions beyond each company’s control. See Item 1A. Risk Factors for a discussion of risks related to the Hess acquisition.
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
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 Development1
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated Companies | | Affiliated Companies |
| | Other | | | | | | | | |
| Millions of dollars | U.S. | Americas | Africa | Asia | Australia | Europe | Total | | TCO | Other |
| Year Ended December 31, 2024 | | | | | | | | | | |
| Exploration | | | | | | | | | | |
| Wells | $ | 193 | | $ | 2 | | $ | 155 | | $ | 94 | | $ | 4 | | $ | — | | $ | 448 | | | $ | — | | $ | — | |
| Geological and geophysical | 173 | | 81 | | 47 | | 23 | | 3 | | — | | 327 | | | — | | — | |
| Other | 62 | | 62 | | 70 | | 15 | | 30 | | — | | 239 | | | — | | — | |
| Total exploration | 428 | | 145 | | 272 | | 132 | | 37 | | — | | 1,014 | | | — | | — | |
Property acquisitions2 | | | | | | | | | | |
| Proved - Other | 11 | | — | | 95 | | — | | — | | — | | 106 | | | — | | — | |
| Unproved - Other | 69 | | 38 | | 22 | | — | | — | | — | | 129 | | | — | | — | |
| Total property acquisitions | 80 | | 38 | | 117 | | — | | — | | — | | 235 | | | — | | — | |
Development3 | 9,334 | | 1,261 | | 895 | | 774 | | 1,015 | | 54 | | 13,333 | | | 1,480 | | 7 | |
Total Costs Incurred4 | $ | 9,842 | | $ | 1,444 | | $ | 1,284 | | $ | 906 | | $ | 1,052 | | $ | 54 | | $ | 14,582 | | | $ | 1,480 | | $ | 7 | |
| 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 acquisitions2 | | | | | | | | | | |
| Proved - Other | 10,123 | | — | | — | | — | | — | | — | | 10,123 | | | — | | — | |
| Unproved - Other | 504 | | 1 | | — | | 3 | | — | | — | | 508 | | | — | | — | |
| Total property acquisitions | 10,627 | | 1 | | — | | 3 | | — | | — | | 10,631 | | | — | | — | |
Development3 | 9,645 | | 986 | | 784 | | 619 | | 822 | | 64 | | 12,920 | | | 2,278 | | 86 | |
Total Costs Incurred4 | $ | 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 acquisitions2 | | | | | | | | | | |
| Proved - Other | 18 | | — | | 63 | | 13 | | — | | — | | 94 | | | — | | — | |
| Unproved - Other | 104 | | 78 | | 73 | | — | | — | | — | | 255 | | | — | | — | |
| Total property acquisitions | 122 | | 78 | | 136 | | 13 | | — | | — | | 349 | | | — | | — | |
Development3 | 6,221 | | 863 | | 21 | | 649 | | 719 | | 35 | | 8,508 | | | 2,429 | | 34 | |
Total Costs Incurred4 | $ | 6,733 | | $ | 1,125 | | $ | 420 | | $ | 726 | | $ | 751 | | $ | 37 | | $ | 9,792 | | | $ | 2,429 | | $ | 34 | |
| | | | | | | | | | | | | | | | | | | | |
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 $59, $208 and $186 of costs incurred on major capital projects prior to assignment of proved reserves for consolidated companies in 2024, 2023, and 2022, respectively. |
4 Reconciliation of consolidated companies total cost incurred to Upstream Capex - $ billions: |
| 2024 | | 2023 | | 2022 | |
| Total cost incurred by Consolidated Companies | $ | 14.6 | | | $ | 24.6 | | | $ | 9.8 | | |
| PDC Energy, Inc. (PDC) acquisition | — | | | (10.5) | | | — | | |
| Expensed exploration costs | (0.6) | | | (0.5) | | | (0.5) | | (Geological and geophysical and other exploration costs) |
| Non-oil and gas activities | 0.6 | | | 1.4 | | | 0.6 | | (Primarily LNG and transportation activities) |
| ARO reduction/(build) | (0.3) | | | (1.3) | | | (0.3) | | |
| Upstream Capex | $ | 14.3 | | | $ | 13.7 | | | $ | 9.6 | | Reference page 50 Upstream Capex |
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
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, 2024 | | | | | | | | | | |
| Unproved properties | $ | 2,473 | | $ | 1,545 | | $ | 287 | | $ | 536 | | $ | 1,882 | | $ | — | | $ | 6,723 | | | $ | 108 | | $ | — | |
Proved properties and
related producing assets | 109,147 | | 15,739 | | 48,391 | | 29,265 | | 24,310 | | 2,283 | | 229,135 | | | 35,374 | | 1,612 | |
| Support equipment | 2,075 | | 213 | | 1,565 | | 698 | | 19,134 | | — | | 23,685 | | | 733 | | — | |
| Deferred exploratory wells | 17 | | 69 | | 204 | | 179 | | 1,119 | | 74 | | 1,662 | | | — | | — | |
| Other uncompleted projects | 8,918 | | 650 | | 1,756 | | 1,040 | | 1,814 | | 69 | | 14,247 | | | 4,634 | | — | |
| Gross Capitalized Costs | 122,630 | | 18,216 | | 52,203 | | 31,718 | | 48,259 | | 2,426 | | 275,452 | | | 40,849 | | 1,612 | |
| Unproved properties valuation | 119 | | 1,119 | | 213 | | 533 | | 5 | | — | | 1,989 | | | 80 | | — | |
Proved producing properties – Depreciation and depletion | 69,545 | | 10,314 | | 41,485 | | 18,251 | | 14,038 | | 956 | | 154,589 | | | 11,441 | | 1,014 | |
| Support equipment depreciation | 1,265 | | 152 | | 1,231 | | 556 | | 6,375 | | — | | 9,579 | | | 535 | | — | |
| Accumulated provisions | 70,929 | | 11,585 | | 42,929 | | 19,340 | | 20,418 | | 956 | | 166,157 | | | 12,056 | | 1,014 | |
| Net Capitalized Costs | $ | 51,701 | | $ | 6,631 | | $ | 9,274 | | $ | 12,378 | | $ | 27,841 | | $ | 1,470 | | $ | 109,295 | | | $ | 28,793 | | $ | 598 | |
| 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 | |
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
Table III - Results of Operations for Oil and Gas Producing Activities1
The company’s results of operations from oil and gas producing activities for the years 2024, 2023 and 2022 are shown in the following table. Net income (loss) from exploration and production activities as reported on page 81 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 81.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated Companies | | Affiliated Companies |
| | Other | | | | | | | | |
| Millions of dollars | U.S. | Americas | Africa | Asia | Australia | Europe | Total | | TCO | Other |
| Year Ended December 31, 2024 | | | | | | | | | | |
| Revenues from net production | | | | | | | | | | |
| Sales | $ | 6,657 | | $ | 799 | | $ | 622 | | $ | 3,376 | | $ | 5,856 | | $ | 319 | | $ | 17,629 | | | $ | 7,240 | | $ | 700 | |
| Transfers | 18,043 | | 3,110 | | 5,227 | | 2,101 | | 4,237 | | — | | 32,718 | | | — | | — | |
| Total | 24,700 | | 3,909 | | 5,849 | | 5,477 | | 10,093 | | 319 | | 50,347 | | | 7,240 | | 700 | |
| Production expenses excluding taxes | (5,472) | | (928) | | (1,662) | | (939) | | (540) | | (74) | | (9,615) | | | (696) | | (46) | |
| Taxes other than on income | (1,445) | | (67) | | (165) | | (24) | | (209) | | (3) | | (1,913) | | | (1,117) | | — | |
| Proved producing properties: | | | | | | | | | | |
| Depreciation and depletion | (7,231) | | (981) | | (1,616) | | (1,236) | | (2,547) | | (103) | | (13,714) | | | (1,222) | | (154) | |
Accretion expense2 | (205) | | (26) | | (127) | | (63) | | (104) | | (8) | | (533) | | | (5) | | (3) | |
| Exploration expenses | (352) | | (141) | | (308) | | (233) | | (33) | | (1) | | (1,068) | | | — | | — | |
| Unproved properties valuation | (68) | | (31) | | (30) | | (1) | | — | | — | | (130) | | | — | | — | |
Other income (loss)3 | 247 | | 1,556 | | 534 | | 139 | | (8) | | (4) | | 2,464 | | | (80) | | (150) | |
| Results before income taxes | 10,174 | | 3,291 | | 2,475 | | 3,120 | | 6,652 | | 126 | | 25,838 | | | 4,120 | | 347 | |
| Income tax (expense) benefit | (2,238) | | (954) | | (1,240) | | (1,684) | | (2,010) | | (95) | | (8,221) | | | (1,238) | | 12 | |
| Results of Producing Operations | $ | 7,936 | | $ | 2,337 | | $ | 1,235 | | $ | 1,436 | | $ | 4,642 | | $ | 31 | | $ | 17,617 | | | $ | 2,882 | | $ | 359 | |
| 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 expense2 | (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 | |
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.
3 Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses. 2023 also includes a loss related to decommissioning obligations from certain previously divested oil and gas production assets in the Gulf of America.
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
Table III - Results of Operations for Oil and Gas Producing Activities1, continued
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated Companies | | Affiliated Companies |
| | Other | | | | | | | | |
| Millions of dollars | U.S. | Americas | Africa | Asia | Australia | Europe | Total | | TCO | Other |
| 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 expense2 | (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.
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 Costs1
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated Companies | | Affiliated Companies |
| | Other | | | | | | | | |
| U.S. | Americas | Africa | Asia | Australia | Europe | Total | | TCO | Other |
| Year Ended December 31, 2024 | | | | | | | | | | |
| Average sales prices | | | | | | | | | | |
| Crude, per barrel | $ | 73.47 | | $ | 70.06 | | $ | 75.69 | | $ | 71.22 | | $ | 74.20 | | $ | 77.47 | | $ | 73.27 | | | $ | 67.02 | | $ | — | |
| Natural gas liquids, per barrel | 19.88 | | 26.53 | | 32.13 | | — | | 59.48 | | — | | 20.51 | | | 12.09 | | 47.61 | |
| Natural gas, per thousand cubic feet | 1.03 | | 1.03 | | 4.14 | | 4.21 | | 10.24 | | 9.10 | | 4.99 | | | 1.57 | | 7.75 | |
Average production costs, per barrel2 | 9.41 | | 14.28 | | 18.07 | | 6.80 | | 3.37 | | 16.43 | | 9.23 | | | 5.44 | | 2.89 | |
| 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 barrel2 | 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 barrel2 | 11.10 | | 17.00 | | 14.43 | | 8.49 | | 3.79 | | 12.00 | | 10.16 | | | 3.85 | | 3.36 | |
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.
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
Table V Proved Reserve Quantity Information*
Summary of Net Oil and Gas Reserves
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2024 | | 2023 | | 2022 |
| 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. | 1,207 | | — | | 615 | | 4,420 | | | 1,221 | | — | | 611 | | 4,543 | | | 1,198 | | — | | 450 | | 3,288 | |
| Other Americas | 181 | | — | | — | | 168 | | | 195 | | 598 | | 7 | | 298 | | | 174 | | 574 | | 7 | | 305 | |
| Africa | 392 | | — | | 67 | | 1,491 | | | 367 | | — | | 70 | | 1,632 | | | 392 | | — | | 72 | | 1,734 | |
| Asia | 246 | | — | | — | | 6,560 | | | 240 | | — | | — | | 6,974 | | | 235 | | — | | — | | 6,578 | |
| Australia | 72 | | — | | 1 | | 6,517 | | | 85 | | — | | 2 | | 6,951 | | | 99 | | — | | 3 | | 7,898 | |
| Europe | 23 | | — | | — | | 10 | | | 25 | | — | | — | | 9 | | | 26 | | — | | — | | 9 | |
| Total Consolidated | 2,121 | | — | | 683 | | 19,166 | | | 2,133 | | 598 | | 690 | | 20,407 | | | 2,124 | | 574 | | 532 | | 19,812 | |
| Affiliated Companies | | | | | | | | | | | | | | |
| TCO | 663 | | — | | 70 | | 1,118 | | | 478 | | — | | 67 | | 1,062 | | | 515 | | — | | 52 | | 895 | |
| Other | 2 | | — | | 12 | | 670 | | | 3 | | — | | 13 | | 323 | | | 3 | | — | | 13 | | 349 | |
| Total Consolidated and Affiliated Companies | 2,786 | | — | | 765 | | 20,954 | | | 2,614 | | 598 | | 770 | | 21,792 | | | 2,642 | | 574 | | 597 | | 21,056 | |
| Proved Undeveloped | | | | | | | | | | | | | | |
| Consolidated Companies | | | | | | | | | | | | | | |
| U.S. | 639 | | — | | 373 | | 2,730 | | | 721 | | — | | 413 | | 3,139 | | | 875 | | — | | 435 | | 3,543 | |
| Other Americas | 106 | | — | | — | | 146 | | | 129 | | — | | 8 | | 276 | | | 121 | | — | | 10 | | 240 | |
| Africa | 63 | | — | | 19 | | 703 | | | 78 | | — | | 27 | | 625 | | | 62 | | — | | 25 | | 756 | |
| Asia | 52 | | — | | — | | 1,351 | | | 61 | | — | | — | | 1,419 | | | 58 | | — | | — | | 1,959 | |
| Australia | 20 | | — | | — | | 2,422 | | | 22 | | — | | — | | 2,444 | | | 22 | | — | | — | | 2,444 | |
| Europe | 26 | | — | | — | | 8 | | | 28 | | — | | — | | 8 | | | 32 | | — | | — | | 11 | |
| Total Consolidated | 906 | | — | | 392 | | 7,360 | | | 1,039 | | — | | 448 | | 7,911 | | | 1,170 | | — | | 470 | | 8,953 | |
| Affiliated Companies | | | | | | | | | | | | | | |
| TCO | 224 | | — | | 2 | | 20 | | | 526 | | — | | 11 | | 233 | | | 611 | | — | | 21 | | 368 | |
| Other | — | | — | | — | | 41 | | | — | | — | | — | | 445 | | | — | | — | | — | | 487 | |
| Total Consolidated and Affiliated Companies | 1,130 | | — | | 394 | | 7,421 | | | 1,565 | | — | | 459 | | 8,589 | | | 1,781 | | — | | 491 | | 9,808 | |
| Total Proved Reserves | 3,916 | | — | | 1,159 | | 28,375 | | | 4,179 | | 598 | | 1,229 | | 30,381 | | | 4,423 | | 574 | | 1,088 | | 30,864 | |
* Reserve quantities include natural gas projected to be consumed in operations of 2,462, 2,655 and 2,737 billions of cubic feet and equivalent synthetic oil projected to be consumed in operations of 0, 27, and 28 millions of barrels as of December 31, 2024, 2023 and 2022, 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.
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.
Proved reserves are estimated by company asset teams composed of earth scientists and engineers. As part of the internal control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired by the Manager of Global Reserves, an organization that is separate from the business units that estimate reserves. The Manager of Global Reserves has more than 35 years of experience working in the oil and gas industry and holds both undergraduate and graduate degrees in geoscience. 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 company’s Audit Committee and Board of Directors. If major changes to reserves were to occur between the annual reviews, those matters would also be discussed with the Board.
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 2024, 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) | 2024 |
| Quantity at January 1 | 3,456 | |
| Revisions | (154) | |
| Improved recovery | 3 | |
| Extension and discoveries | 390 | |
| Purchases | 70 | |
| Sales | (54) | |
| Transfers to proved developed | (950) | |
| Quantity at December 31 | 2,761 | |
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
In 2024, revisions in the United States were primarily from the Denver-Julesburg (DJ) basin yielding a decrease of 98 million BOE mainly due to reservoir performance and portfolio optimization. A net decrease of 33 million BOE in the Midland and Delaware basins was due to reservoir performance.
In 2024, extensions and discoveries of 316 million BOE in the United States were primarily due to planned development of new locations in shale and tight assets in the DJ basin of 171 million BOE, the Midland and Delaware basins of 123 million BOE, and deepwater assets in the Gulf of America of 22 million BOE. In Other Americas, 58 million BOE of extensions and discoveries were from shale and tight assets in Argentina.
In 2024, purchases of 70 million BOE in the United States are primarily from newly identified proved undeveloped well locations associated with the acquisition of PDC.
The difference in 2024 extensions and discoveries of 161 million BOE, between the net quantities of proved reserves of 551 million BOE as reflected on pages 112 to 114 and net quantities of proved undeveloped reserves of 390 million BOE, is primarily due to proved extensions and discoveries that were not recognized as proved undeveloped reserves in the prior year and were recognized directly as proved developed reserves in 2024.
Transfers to proved developed reserves in 2024 include 464 million BOE in the United States, from 256 million BOE in the Midland and Delaware basins, 126 million BOE in the DJ basin, and 82 million BOE in the Gulf of America. Other significant transfers to proved developed were 329 million BOE in Kazakhstan, primarily at TCO, and 75 million BOE in Angola, primarily at Angola LNG. A combined 81 million BOE of transfers to proved developed were recorded in Argentina, Canada, Australia, Nigeria, China, and other international locations. These transfers are the consequence of development expenditures on completing wells and facilities.
During 2024, the company’s investments totaled approximately $8.2 billion in oil and gas producing activities, and about $0.1 billion in non-oil and gas producing activities, to advance the development of proved undeveloped reserves. The United States accounted for about $5.5 billion primarily related to various development activities in the Midland and Delaware basins, the Gulf of America and the DJ basin. In Africa, about $0.8 billion was expended on various offshore development and natural gas projects in Nigeria and Angola. An additional $0.5 billion was spent on development activities in Australia. Development activities in other international locations were primarily responsible for about $1.4 billion of expenditures. The company’s equity affiliates investments in oil and gas producing activities to advance development of proved undeveloped reserves in 2024 was $1.3 billion primarily related to development projects for TCO in Kazakhstan.
Reserves that remain proved undeveloped for five or more years are a result of several factors that affect optimal project development and execution. These factors may include the complex nature of the development project in adverse and remote locations, physical limitations of infrastructure or plant capacities that dictate project timing, compression projects that are pending reservoir pressure declines, and contractual limitations that dictate production levels.
At year-end 2024, the company held approximately 624 million BOE of proved undeveloped reserves that have remained undeveloped for five years or more. The majority of these reserves are in locations where the company has a proven track record of developing major projects. In Australia, approximately 223 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 138 million BOE have remained undeveloped for five years or more, due to facility constraints at various fields and infrastructure associated with the Escravos gas projects in Nigeria. Affiliates account for about 237 million BOE of proved undeveloped reserves with about 197 million BOE that have remained undeveloped for five years or more related to TCO. At TCO, further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with reservoir depletion and facility constraints.
Annually, the company assesses whether any changes have occurred in facts or circumstances, such as changes to development plans, regulations, or government policies, that would warrant a revision to reserve estimates. In 2024, lower natural gas prices in North America were primarily responsible for the negative impact to the economic limits of oil and gas properties, resulting in a proved reserve decrease of approximately 58 million BOE. The year-end reserves quantities have been updated for these circumstances and significant changes are discussed in the appropriate reserves sections herein. Over the past three years, the ratio of proved undeveloped reserves to total proved reserves has ranged between 28 percent and 35 percent.
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
Proved Reserve Quantities For the three-year period ended December 31, 2024, the pattern of net reserve changes shown in the following tables is not necessarily indicative of future trends. Apart from acquisitions, the company’s ability to add proved reserves can be affected by events and circumstances that are outside the company’s control, such as delays in government permitting, partner approvals of development plans, changes in oil and gas prices, OPEC constraints, geopolitical uncertainties, civil unrest, events of war or military conflicts.
At December 31, 2024, proved reserves for the company were 9.8 billion BOE. The company’s estimated net proved reserves of liquids, including crude oil, condensate and synthetic oil for the years 2022, 2023 and 2024, are shown in the table on page 112. The company’s estimated net proved reserves of natural gas liquids (NGLs) are shown on page 113, and the company’s estimated net proved reserves of natural gas are shown on page 114.
Noteworthy changes in crude oil, condensate and synthetic oil proved reserves for 2022 through 2024 are discussed below and shown in the table on the following page:
Revisions In 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 between Saudi Arabia and Kuwait (the Partitioned Zone), was responsible for the 48 million barrels increase. Reservoir performance in Nigeria was mainly responsible for the 37 million barrels increase in Africa.
In 2024, the 37 million barrels increase in Asia was due to reservoir performance, primarily in the Partitioned Zone.
Extensions and Discoveries In 2022, extensions and discoveries in the Midland, Delaware and DJ basins, and approval of the Ballymore Project in the Gulf of America, were primarily responsible for the 264 million barrels increase in the United States. In Other Americas, the 32 million barrels of extensions and discoveries were from Argentina and Canada.
In 2023, extensions and discoveries of 124 million barrels in the Midland and Delaware basins were primarily responsible for the 170 million barrels increase in the United States. In Other Americas, the 55 million barrels of extensions and discoveries increase was mainly from shale and tight assets in Argentina.
In 2024, extensions and discoveries of 119 million barrels in the Midland and Delaware basins, and 45 million barrels in the DJ basin, were primarily responsible for the 185 million barrels increase in the United States. In Other Americas, the 52 million barrels of extensions and discoveries increase was mainly from shale and tight assets in Argentina.
Purchases In 2022, the company exercised its option to acquire additional land acreage in the Athabasca Oil Sands project in Canada contributing 168 million barrels in synthetic oil. The extension of deepwater licenses in Nigeria and the Republic of Congo contributed 36 million barrels in Africa.
In 2023, the acquisition of PDC in the DJ and Delaware basins was primarily responsible for the 207 million barrels increase in the United States.
In 2024, the renewal of the Agbami field deepwater license in Nigeria increased reserves by 51 million barrels.
Sales In 2024, sales of 593 million barrels in synthetic oil were from the Athabasca oil sand assets in Canada and the 46 million barrels in Other Americas were from the divestment of shale and tight assets in Canada.
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
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. | Americas1 | Africa | Asia | Australia | Europe | Oil 2,5 | Total | | TCO | Oil | Other3 | | Companies |
| Reserves at January 1, 2022 | 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 | |
| Changes attributable to: | | | | | | | | | | | | | | |
| Revisions | 2 | | (7) | | 21 | | 37 | | — | | — | | (4) | | 49 | | | (13) | | — | | — | | | 36 | |
| Improved recovery | 9 | | 1 | | 1 | | — | | — | | — | | — | | 11 | | | — | | — | | — | | | 11 | |
| Extensions and discoveries | 185 | | 52 | | 4 | | — | | — | | — | | — | | 241 | | | — | | — | | — | | | 241 | |
| Purchases | 21 | | — | | 51 | | — | | — | | — | | 16 | | 88 | | | — | | — | | — | | | 88 | |
| Sales | (27) | | (46) | | — | | — | | — | | — | | (593) | | (666) | | | — | | — | | — | | | (666) | |
| Production | (286) | | (37) | | (67) | | (40) | | (15) | | (4) | | (17) | | (466) | | | (104) | | — | | (1) | | | (571) | |
Reserves at December 31, 2024 4, 5 | 1,846 | | 287 | | 455 | | 298 | | 92 | | 49 | | — | | 3,027 | | | 887 | | — | | 2 | | | 3,916 | |
1 Ending reserve balances in North America were 132, 188 and 185 and in South America were 155, 136 and 110 in 2024, 2023 and 2022, 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 8 percent, 6 percent and 6 percent for consolidated companies for 2024, 2023 and 2022, respectively.
5 Reserve quantities include synthetic oil projected to be consumed in operations of 0, 27, and 28 millions of barrels as of December 31, 2024, 2023 and 2022, respectively.
Noteworthy changes in NGLs proved reserves for 2022 through 2024 are discussed below and shown in the table on the following page:
Revisions In 2023, the 110 million barrels decrease in the United States was primarily in the Midland and Delaware basins with a decrease of 49 million barrels due to portfolio optimization and a decrease of 29 million barrels due to reservoir performance.
In 2024, the 41 million barrels decrease in the United States was primarily from a decrease of 65 million barrels in the DJ basin, which was partially offset by an increase of 31 million barrels from the Gulf of America.
Extensions and Discoveries In 2022, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 163 million barrels increase in the United States.
In 2023, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 92 million barrels increase in the United States.
In 2024, extensions and discoveries in the Midland and Delaware basins of 72 million barrels, and in the DJ basin of 52 million barrels, were responsible for the 124 million barrels increase in the United States.
Purchases In 2023, the acquisition of PDC in the DJ and Delaware basins was primarily responsible for the 262 million barrels increase in the United States.
Sales In 2022, sales of 35 million barrels in the United States were primarily from the divestment of the Eagle Ford shale assets and some properties in the Midland and Delaware basins.
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
Net Proved Reserves of Natural Gas Liquids
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated Companies | | Affiliated Companies | | Total
Consolidated |
| | Other | | | | | | | | | | and Affiliated |
| Millions of barrels | U.S. | Americas1 | Africa | Asia | Australia | Europe | Total | | TCO | Other2 | | Companies |
| Reserves at January 1, 2022 | 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, 20223 | 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, 20233 | 1,024 | | 15 | | 97 | | — | | 2 | | — | | 1,138 | | | 78 | | 13 | | | 1,229 | |
| Changes attributable to: | | | | | | | | | | | | |
| Revisions | (41) | | — | | (7) | | — | | — | | — | | (48) | | | 1 | | 1 | | | (46) | |
| Improved recovery | — | | — | | — | | — | | — | | — | | — | | | — | | — | | | — | |
| Extensions and discoveries | 124 | | — | | — | | — | | — | | — | | 124 | | | — | | — | | | 124 | |
| Purchases | 20 | | — | | — | | — | | — | | — | | 20 | | | — | | — | | | 20 | |
| Sales | (3) | | (13) | | — | | — | | — | | — | | (16) | | | — | | — | | | (16) | |
| Production | (136) | | (2) | | (4) | | — | | (1) | | — | | (143) | | | (7) | | (2) | | | (152) | |
Reserves at December 31, 20243 | 988 | | — | | 86 | | — | | 1 | | — | | 1,075 | | | 72 | | 12 | | | 1,159 | |
1 Reserves associated with North America.
2 Reserves associated with Africa.
3 Year-end reserve quantities related to PSC are not material for 2024, 2023 and 2022, respectively.
Noteworthy changes in natural gas proved reserves for 2022 through 2024 are discussed below and shown in the table on the following page:
Revisions In 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.
In 2024, a decrease of 425 BCF in the DJ basin, primarily related to reservoir performance, was mainly responsible for the 572 BCF decrease in the United States. The 504 BCF increase in Australia was mainly due to reservoir performance of the Jansz Io field.
Extensions and Discoveries In 2022, extensions and discoveries of 1.6 TCF in the United States were primarily in the Midland and Delaware basins.
In 2023, extensions and discoveries of 660 BCF in the United States were primarily in the Midland and Delaware basins.
In 2024, extensions and discoveries of 912 BCF in the United States were primarily in the DJ basin with 476 BCF, and the Midland and Delaware basins with 432 BCF.
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
Purchases In 2023, the acquisition of PDC in the DJ basin was primarily responsible for the 2.2 TCF in the United States.
In 2024, the 177 BCF in the United States was primarily associated with the acquisition of PDC in the DJ basin.
Sales In 2022, sales of 243 BCF in the United States were primarily in the Eagle Ford shale and Midland and Delaware basins.
In 2024, sales of 260 BCF in Other Americas were from the divestment of shale and tight assets in Canada.
Net Proved Reserves of Natural Gas
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated Companies | | Affiliated Companies | | Total
Consolidated |
| | Other | | | | | | | | | | and Affiliated |
| Billions of cubic feet (BCF) | U.S. | Americas1 | Africa | Asia | Australia | Europe | Total | | TCO | Other2 | | Companies |
| Reserves at January 1, 2022 | 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) | |
Production3 | (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) | |
Production3 | (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 | |
| Changes attributable to: | | | | | | | | | | | | |
| Revisions | (572) | | (54) | | (19) | | 118 | | 504 | | 3 | | (20) | | | (21) | | 30 | | | (11) | |
| Improved recovery | 2 | | — | | — | | — | | — | | — | | 2 | | | — | | — | | | 2 | |
| Extensions and discoveries | 912 | | 119 | | 83 | | — | | — | | — | | 1,114 | | | — | | — | | | 1,114 | |
| Purchases | 177 | | — | | 32 | | — | | — | | — | | 209 | | | — | | — | | | 209 | |
| Sales | (70) | | (260) | | — | | — | | — | | — | | (330) | | | — | | — | | | (330) | |
Production3 | (981) | | (65) | | (159) | | (600) | | (960) | | (2) | | (2,767) | | | (136) | | (87) | | | (2,990) | |
Reserves at December 31, 2024 4, 5 | 7,150 | | 314 | | 2,194 | | 7,911 | | 8,939 | | 18 | | 26,526 | | | 1,138 | | 711 | | | 28,375 | |
1 Ending reserve balances in North America and South America were 49, 363 and 407 and 265, 211 and 138 in 2024, 2023 and 2022, respectively.
2 Reserves associated with Africa.
3 Total “as sold” volumes were 2,768, 2,609 and 2,600 for 2024, 2023 and 2022, respectively.
4 Includes reserve quantities related to PSC. PSC-related reserve quantities were 6 percent, 7 percent and 8 percent for consolidated companies for 2024, 2023 and 2022, respectively.
5 Reserve quantities include natural gas projected to be consumed in operations of 2,462, 2,655 and 2,737 billions of cubic feet as of December 31, 2024, 2023 and 2022, respectively.
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
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 unweighted arithmetic average of the first-day-of-the-month oil and gas prices for the 12-month period prior to the end of the reporting period, estimated future development and production costs assuming the continuation of existing economic conditions, estimated costs for asset retirement obligations (includes costs to retire existing wells and facilities in addition to those future wells and facilities necessary to produce proved undeveloped reserves), and estimated future income taxes based on appropriate statutory tax rates. Discounted future net cash flows are calculated using 10 percent mid-period discount factors. 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, which could change over time as new information becomes available. The calculations are made as of December 31 each year and do not represent management’s estimate of the company’s future cash flows or value of its oil and gas reserves. 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, 2024 | | | | | | | | | | | | |
| Future cash inflows from production | $ | 163,846 | | $ | 21,827 | | $ | 43,539 | | $ | 58,245 | | $ | 84,026 | | $ | 3,999 | | $ | 375,482 | | | $ | 65,221 | | $ | 5,308 | | | $ | 446,011 | |
| Future production costs | (52,680) | | (5,896) | | (17,996) | | (13,355) | | (10,964) | | (1,188) | | (102,079) | | | (19,945) | | (392) | | | (122,416) | |
| Future development costs | (15,377) | | (2,131) | | (3,554) | | (2,290) | | (6,333) | | (420) | | (30,105) | | | (1,560) | | (30) | | | (31,695) | |
| Future income taxes | (18,919) | | (4,443) | | (12,345) | | (25,354) | | (25,891) | | (1,004) | | (87,956) | | | (13,115) | | (1,710) | | | (102,781) | |
| Undiscounted future net cash flows | 76,870 | | 9,357 | | 9,644 | | 17,246 | | 40,838 | | 1,387 | | 155,342 | | | 30,601 | | 3,176 | | | 189,119 | |
10 percent midyear annual discount for timing of estimated cash flows | (28,615) | | (3,492) | | (3,573) | | (8,157) | | (15,114) | | (503) | | (59,454) | | | (8,722) | | (1,003) | | | (69,179) | |
Standardized Measure Net Cash Flows | $ | 48,255 | | $ | 5,865 | | $ | 6,071 | | $ | 9,089 | | $ | 25,724 | | $ | 884 | | $ | 95,888 | | | $ | 21,879 | | $ | 2,173 | | | $ | 119,940 | |
| 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 | |
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
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, 2022 | | $ | 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 | |
| Sales and transfers of oil and gas produced net of production costs | | (38,457) | | | | (6,242) | | | | (44,699) | |
| Development costs incurred | | 12,809 | | | | 1,487 | | | | 14,296 | |
| Purchases of reserves | | 1,607 | | | | — | | | | 1,607 | |
| Sales of reserves | | (8,904) | | | | — | | | | (8,904) | |
| Extensions, discoveries and improved recovery less related costs | | 7,328 | | | | — | | | | 7,328 | |
| Revisions of previous quantity estimates | | 2,897 | | | | (154) | | | | 2,743 | |
| Net changes in prices, development and production costs | | (17,755) | | | | (1,898) | | | | (19,653) | |
| Accretion of discount | | 15,867 | | | | 3,601 | | | | 19,468 | |
| Net change in income tax | | 1,739 | | | | 1,007 | | | | 2,746 | |
| Net Change for 2024 | | (22,869) | | | | (2,199) | | | | (25,068) | |
| Present Value at December 31, 2024 | | $ | 95,888 | | | | $ | 24,052 | | | | $ | 119,940 | |
PART IV
Item 15. Exhibit and Financial Statement Schedules
(a)The following documents are filed as part of this report:
(1) Financial Statements:
(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, 2024.
(3) Exhibits:
The Exhibit Index on the following pages lists the exhibits that are filed as part of this report.
| | $ | | | | $ | | | | Additions (reductions) charged to expense | | | | () | | | | |
| Payments | () | | | () | | | () | |
| Balance at December 31 | $ | | | | $ | | | | $ | | |
| Expected Credit Losses | | | | | |
| Beginning allowance balance for expected credit losses | $ | | | | $ | | | | $ | | |
| Current period provision | () | | | () | | | | |
| | |
| Write-offs charged against the allowance, if any | | | | | | | | |
| | |
| Balance at December 31 | $ | | | | $ | | | | $ | | |
Deferred Income Tax Valuation Allowance* | | | | | |
| Balance at January 1 | $ | | | | $ | | | | $ | | |
| Additions to deferred income tax expense | | | | | | | | |
| Reduction of deferred income tax expense | () | | | () | | | () | |
| Balance at December 31 | $ | | | | $ | | | | $ | | |
Item 16. Form 10-K Summary
Not applicable.
EXHIBIT INDEX
| | | | | |
Exhibit No. | Description |
| 2.1 | |
| 3.1 | |
| 3.2 | |
| 4.1 | |
| 4.2 | |
| 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 | |
| 4.5 | |
10.1+ | |
10.2+ | |
| 10.3+* | |
| 10.4+ | |
| 10.5+ | |
| 10.6+ | |
| 10.7+ | Summary of Chevron Incentive Plan Award Criteria, filed as Exhibit 10.6 to Chevron Corporation's Annual Report on Form 10-K for the year ended December 31, 2022, and incorporated herein by reference. |
| 10.8+ | |
| 10.9+ | |
| 10.10+ | |
| 10.11+ | |
|
| | | | | |
| Exhibit No. | Description |
|
| 10.12+ | |
| 10.13+ | |
| 10.14+ | |
| 10.15+ | |
| 10.16+ | |
| 10.17+ | |
| 10.18+ | |
| 10.19+ | |
| 10.20+ | |
| 10.21+* | |
| 10.22+ | |
| 10.23+ | |
| 10.24+ | |
| 10.25+ | |
| 10.26+ | |
| 10.27+ | |
| 10.28+ | |
| 10.29+ | |
| 10.30+ | |
| |
| | | | | |
| Exhibit No. | Description |
| 10.31+ | |
| 10.32+ | |
| 10.33+ | |
| 10.34+ | |
| 10.35+ | |
| 10.36+ | |
|
| 19* | |
21.1* | |
| 22.1* | |
23.1* | |
24.1* | |
31.1* | |
31.2* | |
32.1** | |
32.2** | |
97.1+ | |
| 99.1* | |
| 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.
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 21st day of February, 2025.
| | | | | |
| 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 21st day of February, 2025.
| | | |
| Principal Executive Officer | |
| (and Director) | |
| |
/s/ MICHAEL K. WIRTH
Michael K. Wirth, Chairman of the
Board and Chief Executive Officer | |
| |
| |
| Principal Financial Officer | |
| |
/s/ EIMEAR P. BONNER
Eimear P. Bonner, 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 |
|
|
|
|
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