UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2023
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______ to ______
Commission File Number 001-00368
Chevron Corporation
(Exact name of registrant as specified in its charter)
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| | | | 6001 Bollinger Canyon Road |
| Delaware | | 94-0890210 | | San Ramon, California 94583-2324 |
(State or other jurisdiction of
incorporation or organization) | | (I.R.S. Employer
Identification No.) | | (Address of principal executive offices)
(Zip Code) |
| | | | | | |
| | | | | | |
Registrant’s telephone number, including area code (925) 842-1000
Securities registered pursuant to Section 12(b) of the Act:
| | | | | | | | | | | | | | |
| Title of each class | | Trading Symbol | | Name of each exchange on which registered |
| Common stock, par value $.75 per share | | CVX | | New York Stock Exchange |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes o No þ
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 No 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.
Yes 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).
Yes þ No o
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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| Large accelerated filer | ☑ | | 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
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal controls over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. o
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No þ
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 — $293.8 billion (As of June 30, 2023)
Number of Shares of Common Stock outstanding as of February 9, 2024 — 1,857,269,160
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of the 2024 Annual Meeting and 2024 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2024 Annual Meeting of Stockholders (in Part III)
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 and energy transition plans 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,” “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 war between Israel and Hamas and the global response to these hostilities; changing refining, marketing and chemicals margins; actions of competitors or regulators; timing of exploration expenses; timing of crude oil liftings; the competitiveness of alternate-energy sources or product substitutes; 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 ability to successfully integrate the operations of the company and PDC Energy, Inc. and achieve the anticipated benefits from the transaction, including the expected incremental annual free cash flow; the risk that Hess Corporation (Hess) stockholders do not approve the potential transaction, and the risk that regulatory approvals are not obtained or are obtained subject to conditions that are not anticipated by the company and Hess; uncertainties as to whether the potential transaction will be consummated on the anticipated timing or at all, or if consummated, will achieve its anticipated economic benefits, including as a result of regulatory proceedings and 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 26 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 Corporation,* 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, 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 building on 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 lower carbon businesses in renewable fuels, carbon capture and offsets, hydrogen and other 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 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.
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* 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.
3
Human Capital Management
Chevron invests in its workforce and culture, with the objective of engaging employees to develop their full potential to deliver energy solutions and enable human progress. The company hires, develops, and strives to retain a diverse workforce of high-performing talent, and fosters a culture that values diversity, inclusion and employee engagement.
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 the company’s investment in people and the company’s culture. 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 gender, where data is available, and by region as of December 31, 2023.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| At December 31, 2023 |
| Female | Male | Gender 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. | 5,713 | | 26 | % | 15,905 | | 74 | % | 20 | | — | % | 21,638 | | 47 | % |
| Other Americas | 1,122 | | 29 | % | 2,740 | | 71 | % | 12 | | — | % | 3,874 | | 8 | % |
| Africa | 611 | | 16 | % | 3,209 | | 84 | % | 3 | | — | % | 3,823 | | 8 | % |
| Asia | 2,550 | | 36 | % | 4,608 | | 64 | % | 16 | | — | % | 7,174 | | 16 | % |
| Australia | 562 | | 26 | % | 1,574 | | 74 | % | 4 | | — | % | 2,140 | | 5 | % |
| Europe | 442 | | 28 | % | 1,102 | | 71 | % | 19 | | 1 | % | 1,563 | | 3 | % |
| Total Non-Service Station Employees | 11,000 | | 27 | % | 29,138 | | 72 | % | 74 | | — | % | 40,212 | | 88 | % |
| Service Station Employees | 2,392 | | 44 | % | 2,011 | | 37 | % | 985 | | 18 | % | 5,388 | | 12 | % |
| Total Employees | 13,392 | | 29 | % | 31,149 | | 68 | % | 1,059 | | 2 | % | 45,600 | | 100 | % |
* Includes employees where gender data was not collected or employee chose not to disclose gender.
Hiring, Development and Retention
The company’s approach to attracting, developing and retaining a global, diverse workforce of high-performing talent is anchored in a long-term employment model that fosters 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 part 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 achieve their full potential by building technical, operating and leadership capabilities. The company’s leadership regularly reviews metrics on employee training and development programs, which are refined on an ongoing basis to meet the needs of our business. The company invests in developing leadership at every level, including coaching programs for frontline supervisors, managers and individual contributors.
In addition, leadership regularly 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, which includes executives, all levels of management, and the majority of its regular employee population. The voluntary attrition for this population in 2023 was 2.9 percent, a decrease from five-year 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, its long-term employment model, competitive pay and benefits, and its culture.
Diversity and Inclusion
Chevron believes human ingenuity has the power to solve difficult problems when diverse people, ideas and experiences come together in an inclusive environment.
Chevron also believes inclusive leadership development enhances performance and innovation. To that end, the company offers numerous leadership development programs, such as the Global Women’s Leadership Development Program and Transformational Leadership for Multicultural Women, which are designed to provide forums for discussion of potential headwinds, promote professional growth, and foster a more inclusive work environment.
The company also strives to build an inclusive environment through innovative programs such as the company’s MARC (Men Advocating Real Change) program launched in 2017, in partnership with the non-profit organization Catalyst, which is designed to facilitate discussions on gender equity in the workplace. MARC is active in over 35 Chevron locations on six continents around the world, with over 5,000 participants since inception. The success and impact of MARC led to the creation of Elevate in 2020, a program that seeks to take the inclusion dialogue beyond gender.
The company has 11 employee networks (voluntary groups of employees and allies that come together based on shared identity or interests) and a Chairman’s Inclusion Council, which provides the 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 collaborate and discuss how employee networks can reinforce the company’s values of diversity and inclusion. Across many of its selection processes, the company continues to use specially trained company leaders as inclusion counselors, who help challenge group think and unconscious biases and provide outside perspectives when hiring for a position.
The company also aims to support a diverse and inclusive supply chain that is reflective of the communities where we operate. We believe that a diverse supply chain contributes to our success and growth. The company maintains long-standing partnerships with non-profit organizations, including the National Minority Supplier Development Council, Women’s Business Enterprise National Council, National LGBT Chamber of Commerce and Disability:IN, that have helped many diverse businesses grow.
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. The company’s survey frequency enables the company to understand employee sentiment throughout the year and gain insights into employee well-being. Our surveys indicate high levels of employee engagement.
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 projects* in North America, South America, Europe, Africa, Asia and Australia. These activities are managed by the Oil, Products and Gas organization. Tabulations of segment sales and other operating revenues, earnings, assets, and income taxes for the three years ending December 31, 2023, and assets as of the end of 2023 and 2022 — 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, at the beginning of 2021 and at each year-end from 2021 through 2023. 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, 2023, 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. At December 31, 2023, 38 percent of the company’s net proved oil-equivalent reserves were located in the United States, 15 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 2021 through 2023 are shown in the following table:
| | | | | | | | | | | | | | | | | | | | |
| At December 31 | |
| 2023 | | 2022 | | 2021 | |
| Crude Oil, Condensate and Synthetic Oil — Millions of barrels | | | | | | |
| Consolidated Companies | 3,770 | | | 3,868 | | | 3,821 | | |
| Affiliated Companies | 1,007 | | | 1,129 | | | 1,254 | | |
| Total Crude Oil, Condensate and Synthetic Oil | 4,777 | | | 4,997 | | | 5,075 | | |
| Natural Gas Liquids — Millions of barrels | | | | | | |
| Consolidated Companies | 1,138 | | | 1,002 | | | 935 | | |
| Affiliated Companies | 91 | | | 86 | | | 103 | | |
| Total Natural Gas Liquids | 1,229 | | | 1,088 | | | 1,038 | | |
| Natural Gas — Billions of cubic feet | | | | | | |
| Consolidated Companies | 28,318 | | | 28,765 | | | 28,314 | | |
| Affiliated Companies | 2,063 | | | 2,099 | | | 2,594 | | |
| Total Natural Gas | 30,381 | | | 30,864 | | | 30,908 | | |
Oil-Equivalent — Millions of barrels* | | | | | | |
| Consolidated Companies | 9,628 | | | 9,664 | | | 9,475 | | |
| Affiliated Companies | 1,441 | | | 1,565 | | | 1,789 | | |
| Total Oil-Equivalent | 11,069 | | | 11,229 | | | 11,264 | | |
* Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil.
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* As used in this report, the term “project” may describe new upstream development activity, individual phases in a multiphase development, maintenance activities, certain existing assets, new investments in downstream and chemicals capacity, investments in emerging and sustainable energy activities, and certain 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.
6
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 2023, 2022 and 2021. Gross and Net Productive Wells
The following table summarizes gross and net productive wells at year-end 2023 for the company and its affiliates:
| | | | | | | | | | | | | | | | | | | | | | | |
| At December 31, 2023 | |
| Productive Oil Wells1 | Productive Gas Wells1 | |
| Gross | | Net | Gross | | Net | |
| United States | 36,547 | | | 26,111 | | 2,731 | | | 2,092 | | |
| Other Americas | 1,231 | | | 741 | | 284 | | | 189 | | |
| Africa | 1,645 | | | 643 | | 47 | | | 18 | | |
| Asia | 1,910 | | | 855 | | 1,366 | | | 414 | | |
| Australia | 532 | | | 299 | | 114 | | | 31 | | |
| Europe | 28 | | | 5 | | — | | | — | | |
| Total Consolidated Companies | 41,893 | | | 28,654 | | 4,542 | | | 2,744 | | |
Affiliates2 | 1,608 | | | 586 | | — | | | — | | |
| Total Including Affiliates | 43,501 | | | 29,240 | | 4,542 | | | 2,744 | | |
| Multiple completion wells included above | 685 | | | 379 | | 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 1,354 and net 459 productive oil wells for interests accounted for by the non-equity method. | |
Production Outlook
The company estimates its average worldwide oil-equivalent production in 2024 to increase four to seven percent over 2023, assuming a Brent crude oil price of $80 per barrel and including expected asset sales. This estimate is subject to many factors and uncertainties, as described beginning on page 38. 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, 2023, 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:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Undeveloped2 | | Developed | | Developed and Undeveloped | |
Thousands of acres1 | Gross | | Net | | Gross | | Net | | Gross | | Net | |
| United States | 4,168 | | | 3,665 | | | 4,147 | | | 2,763 | | | 8,315 | | | 6,428 | | |
| Other Americas | 15,508 | | | 9,049 | | | 1,020 | | | 228 | | | 16,528 | | | 9,277 | | |
| Africa | 10,986 | | | 5,275 | | | 1,273 | | | 551 | | | 12,259 | | | 5,826 | | |
| Asia | 19,723 | | | 10,050 | | | 1,102 | | | 425 | | | 20,825 | | | 10,475 | | |
| Australia | 2,814 | | | 1,913 | | | 2,067 | | | 814 | | | 4,881 | | | 2,727 | | |
| Europe | 106 | | | 21 | | | 12 | | | 2 | | | 118 | | | 23 | | |
| Total Consolidated Companies | 53,305 | | | 29,973 | | | 9,621 | | | 4,783 | | | 62,926 | | | 34,756 | | |
Affiliates3 | 694 | | | 288 | | | 110 | | | 50 | | | 804 | | | 338 | | |
| Total Including Affiliates | 53,999 | | | 30,261 | | | 9,731 | | | 4,833 | | | 63,730 | | | 35,094 | | |
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 2024, 2025 and 2026 if production is not established by certain required dates are 3,333, 394, and 676, 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 2023 and 2022 by the company and its affiliates. Worldwide oil-equivalent production of 3.1 million barrels per day in 2023 was up approximately 4 percent from 2022, mainly due to the acquisition of PDC Energy, Inc. (PDC), and production 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) | 2023 | 2022 | | 2023 | 2022 | | 2023 | 2022 | | 2023 | 2022 | |
| United States | 1,349 | | 1,181 | | | 710 | | 650 | | | 287 | | 238 | | | 2,112 | | 1,758 | | |
| Other Americas | | | | | | | | | | | | |
| Argentina | 43 | | 40 | | | 37 | | 35 | | | — | | — | | | 36 | | 34 | | |
| | | | | | | | | | | | |
Canada3 | 132 | | 139 | | | 109 | | 109 | | | 5 | | 7 | | | 110 | | 135 | | |
| Total Other Americas | 175 | | 179 | | | 146 | | 144 | | | 5 | | 7 | | | 146 | | 169 | | |
| Africa | | | | | | | | | | | | |
| Angola | 67 | | 70 | | | 55 | | 57 | | | 4 | | 4 | | | 48 | | 49 | | |
| Equatorial Guinea | 49 | | 56 | | | 11 | | 12 | | | 5 | | 7 | | | 198 | | 223 | | |
| Nigeria | 147 | | 152 | | | 104 | | 101 | | | 5 | | 6 | | | 227 | | 266 | | |
| Republic of Congo | 30 | | 31 | | | 28 | | 28 | | | — | | 1 | | | 9 | | 11 | | |
| Total Africa | 293 | | 309 | | | 198 | | 198 | | | 14 | | 18 | | | 482 | | 549 | | |
| Asia | | | | | | | | | | | | |
| Bangladesh | 104 | | 118 | | | 3 | | 2 | | | — | | — | | | 610 | | 696 | | |
| China | 30 | | 28 | | | 9 | | 10 | | | — | | — | | | 126 | | 109 | | |
Indonesia4 | 3 | | 3 | | | 1 | | 1 | | | — | | — | | | 11 | | 18 | | |
| Israel | 95 | | 101 | | | 1 | | 1 | | | — | | — | | | 566 | | 602 | | |
| Kazakhstan | 45 | | 40 | | | 26 | | 24 | | | — | | — | | | 114 | | 96 | | |
| Kurdistan Region of Iraq | — | | 1 | | | — | | 1 | | | — | | — | | | — | | — | | |
| Myanmar | 15 | | 17 | | | — | | — | | | — | | — | | | 87 | | 94 | | |
| Partitioned Zone | 61 | | 60 | | | 60 | | 58 | | | — | | — | | | 6 | | 7 | | |
Thailand5 | 42 | | 67 | | | 10 | | 18 | | | — | | — | | | 192 | | 298 | | |
| Total Asia | 395 | | 435 | | | 110 | | 115 | | | — | | — | | | 1,712 | | 1,920 | | |
| Australia | | | | | | | | | | | | |
| Australia | 488 | | 482 | | | 40 | | 42 | | | 2 | | — | | | 2,678 | | 2,643 | | |
| Total Australia | 488 | | 482 | | | 40 | | 42 | | | 2 | | — | | | 2,678 | | 2,643 | | |
| Europe | | | | | | | | | | | | |
| United Kingdom | 14 | | 14 | | | 12 | | 13 | | | — | | — | | | 11 | | 9 | | |
| Total Europe | 14 | | 14 | | | 12 | | 13 | | | — | | — | | | 11 | | 9 | | |
| Total Consolidated Companies | 2,714 | | 2,600 | | | 1,216 | | 1,162 | | | 308 | | 263 | | | 7,141 | | 7,048 | | |
Affiliates6 | 406 | | 399 | | | 281 | | 278 | | | 25 | | 16 | | | 603 | | 629 | | |
Total Including Affiliates7 | 3,120 | | 2,999 | | | 1,497 | | 1,440 | | | 333 | | 279 | | | 7,744 | | 7,677 | | |
| | | | | | | | | | | | |
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: | 51 | | 45 | | 51 | | 45 | | — | | — | | | — | | — | | |
| | | | | | | | | | | | |
4 Indonesia Deepwater Assets were sold in 2023. |
5 Chevron concessions expired in 2022. | |
6 Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil in Kazakhstan and Angola LNG in Angola. | |
7 Volumes include natural gas consumed in operations of 596 million and 570 million cubic feet per day in 2023 and 2022, respectively. Total “as sold” natural gas volumes were 7,148 million and 7,107 million cubic feet per day for 2023 and 2022, respectively. | |
Delivery Commitments
The company sells crude oil, NGLs and natural gas 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 31 million barrels of NGLs and 746 billion cubic feet of natural gas to third parties and affiliates from 2024 through 2026. 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 2.9 trillion cubic feet of natural gas to third parties and affiliates from 2024 through 2026 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 2023, 2022 and 2021. 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, 2023. 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 12/31/23 | | 2023 | | 2022 | | 2021 | |
| Gross | Net | | Prod. | Dry | | Prod. | Dry | | Prod. | Dry | |
| United States | 382 | | 324 | | | 697 | | 2 | | | 454 | | 2 | | | 319 | | 2 | | |
| Other Americas | 18 | | 15 | | | 39 | | — | | | 35 | | — | | | 54 | | — | | |
| Africa | 3 | | 1 | | | 7 | | — | | | 6 | | — | | | 4 | | — | | |
| Asia | 25 | | 11 | | | 58 | | 2 | | | 32 | | 1 | | | 35 | | — | | |
| Australia | — | | — | | | 3 | | — | | | 1 | | — | | | — | | — | | |
| Europe | 1 | | — | | | — | | — | | | 1 | | — | | | 1 | | — | | |
| Total Consolidated Companies | 429 | | 351 | | | 804 | | 4 | | | 529 | | 3 | | | 413 | | 2 | | |
| Affiliates | 5 | | 2 | | | 4 | | — | | | 6 | | — | | | 8 | | — | | |
| Total Including Affiliates | 434 | | 353 | | | 808 | | 4 | | | 535 | | 3 | | | 421 | | 2 | | |
| * 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 2023, 2022 and 2021. The following table summarizes the company’s net interests in productive and dry exploratory wells completed in each of the last three years, and the number of exploratory wells drilling at December 31, 2023. “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 12/31/23 | | 2023 | | 2022 | | 2021 | |
| Gross | Net | | Prod. | Dry | | Prod. | Dry | | Prod. | Dry | |
| United States | — | | — | | | — | | 2 | | | 3 | | 2 | | | 2 | | 2 | | |
| Other Americas | — | | — | | | — | | — | | | 1 | | 1 | | | — | | — | | |
| Africa | 1 | | — | | | — | | — | | | 1 | | — | | | — | | — | | |
| Asia | 3 | | 2 | | | 1 | | — | | | 2 | | — | | | — | | — | | |
| Australia | — | | — | | | — | | — | | | — | | — | | | — | | — | | |
| Europe | — | | — | | | — | | — | | | — | | — | | | — | | — | | |
| Total Consolidated Companies | 4 | | 2 | | | 1 | | 2 | | | 7 | | 3 | | | 2 | | 2 | | |
| Affiliates | — | | — | | | — | | — | | | — | | — | | | — | | — | | |
| Total Including Affiliates | 4 | | 2 | | | 1 | | 2 | | | 7 | | 3 | | | 2 | | 2 | | |
| * 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 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 in the Permian Basin. In August 2023, Chevron completed the acquisition of PDC, which added 25,000 net acres to our existing position in west Texas. In addition to ongoing emission reduction and water handling initiatives, a 50 percent joint venture solar power project in New Mexico became operational in 2023, with capacity to supply 20MW of renewable energy per day for nearby oil and gas operations. In 2023, Chevron’s net daily production in the Permian Basin averaged 359,000 barrels of crude oil, 205,000 barrels of NGLs and 1.3 billion cubic feet of natural gas.
Chevron also holds approximately 72,000 net acres in the Haynesville Shale in east Texas. The company is evaluating strategic opportunities for these assets.
In Colorado, development is focused on the Denver-Julesburg (DJ) Basin. The company 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, which helped to reduce surface footprint and greenhouse gas emissions. In August 2023, Chevron completed the acquisition of PDC, which added 275,000 net acres that are largely adjacent to its existing operations. Following the acquisition, Chevron is now the largest oil and natural gas producer in the state with approximately 605,000 net acres in the DJ Basin. The company plans to optimize the combined acreage position to efficiently develop its resources.
In 2023, Chevron’s net daily production in Colorado averaged 96,000 barrels of crude oil, 69,000 barrels of NGLs and 606 million cubic feet of natural gas. Chevron also has operations in Colorado’s Piceance Basin, as well as an acreage position in Wyoming.
In 2023, Chevron was one of the largest crude oil producers in California with an average net daily oil production of 77,000 barrels. Chevron owns and operates between 87 and 100 percent interests in six fields including Kern River, Cymric, Midway Sunset, San Ardo, Coalinga and Lost Hills.
During 2023, net daily production in the Gulf of Mexico averaged 170,000 barrels of crude oil, 11,000 barrels of NGLs and 97 million cubic feet of natural gas. Chevron is engaged in various operated and nonoperated exploration, development and production activities in the deepwater Gulf of Mexico. Chevron also holds nonoperated interests in several shelf fields.
Chevron has a 50 percent operated interest in the Jack Field, a 51 percent operated interest in the St. Malo Field and a 40.6 percent operated interest in the production host facility used for the joint development of both fields, all located in the
Walker Ridge area. In 2023, an additional Jack well delivered first oil, and an additional St. Malo well delivered first oil in early 2024. The St. Malo Stage 4 Waterflood project is expected to deliver first water injection and complete installation of multi-phase subsea pump modules in 2024. The Jack and St. Malo fields have an estimated remaining production life of more than 20 years.
Chevron has a 60 percent-owned and operated interest in the Big Foot project, located in the deepwater Walker Ridge area. Development drilling activities are ongoing with the first two injector wells online in 2023. The project has an estimated remaining production life of more than 30 years.
The company has a 58 percent-owned and operated interest in the deepwater Tahiti Field, located in the Green Canyon area. The Tahiti Field has an estimated remaining production life of more than 20 years.
Chevron has owned and operated interests of 62.9 to 75.4 percent in the unit areas containing the Anchor field, located in the Green Canyon area. Stage 1 of the Anchor development consists of a seven-well subsea development and a semi-submersible floating production unit. In 2023, Chevron completed the installation of the floating production unit and commenced final offshore commissioning activities. The company also drilled the second of two pre-drill development wells on the Anchor field. Proved reserves have been recognized for Anchor, with first production expected in mid-2024.
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-operated Blind Faith facility. The development includes three production wells, with first oil expected in 2025. Proved reserves have been recognized for this project.
The company has a 15.6 percent nonoperated working interest in the deepwater Mad Dog Field, located in the Green Canyon area. First oil from the Mad Dog 2 Project was achieved in April 2023. 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. The Perdido asset has an estimated remaining production life of more than 15 years.
The company has a 40 percent nonoperated working interest in the Whale discovery located in the Alaminos Canyon area. First production is expected for Whale in late 2024, and proved reserves have been recognized for this project.
Chevron has a 25 percent nonoperated working interest in the Stampede Field, which is located in the Green Canyon area. The Stampede Field has an estimated remaining production life of more than 20 years.
During 2023, Chevron was formally awarded 73 exploration blocks as a result of U.S. Gulf of Mexico lease sale 259 and has submitted winning bids on an additional 28 exploration blocks as a result of U.S. Gulf of Mexico lease sale 261, subject to government approval.
In March 2023, the Bayou Bend Carbon Capture and Sequestration hub, in which Chevron holds a 50 percent interest and serves as the operator, increased its holdings by 100,000 acres in onshore southeast Texas. This brings total acreage of the affiliate to nearly 140,000 acres supporting permanent carbon dioxide (CO2) sequestration.
In September 2023, Chevron acquired a majority interest in ACES Delta, LLC, a joint venture developing the Advanced Clean Energy Storage (ACES Delta) 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. Start-up of the ACES Delta Project is expected 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, 41 horizontal wells were drilled in 2023, with 44 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 2023, Chevron continued development on its unconventional resources with one drilling rig. The unconventional concession expires in 2057.
Brazil Chevron holds between 35 and 50 percent of both operated and nonoperated interests in four Blocks within the Campos and Santos Basin, following the relinquishment of seven Blocks in 2023 to the government. Chevron submitted winning bids for 15 additional exploration blocks in the South Santos and Pelotas basins in the December 2023 bid round, with contracts expected to be signed in 2024.
Canada Upstream interests in Canada are concentrated in Alberta and 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.
The company has a 20 percent nonoperated working interest in the Athabasca Oil Sands Project (AOSP) and associated Quest carbon capture and storage project in Alberta. Oil sands are mined from both the Muskeg River and the Jackpine mines, and bitumen is extracted from the oil sands and upgraded into synthetic oil. CO2 emissions from the upgrader are reduced by carbon capture and storage facilities.
Chevron has a 70 percent-owned and operated interest in most of its Duvernay shale acreage. By the end of 2023, a total of 261 wells have been tied into production facilities. The company will commence marketing its interest in these assets in 2024.
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 heavy oil Hebron Field, also offshore Atlantic Canada, which has an expected remaining economic life of 25 years.
The company has a 25 percent nonoperated working interest in blocks EL 1168 and EL 1148 located in offshore Atlantic Canada.
Colombia Chevron has a 40 percent-owned and operated interest in the offshore Colombia-3 and Guajira Offshore-3 Blocks. Chevron has initiated the relinquishment of Guajira Offshore-3 Block to the government, which is expected to complete in 2024.
Mexico All blocks in which Chevron has a participating interest are in the process of being relinquished to the government.
Suriname Chevron has a 60 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.
Venezuela Chevron’s interests in Venezuela are located in western Venezuela, the Orinoco Belt and offshore Venezuela. As of December 31, 2023, no proved reserves are recognized for these interests. In 2023, the company conducted activities in Venezuela consistent with the authorization provided pursuant to general 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. Both licenses were extended in 2023 from 2026 to 2041. Chevron has a 30 percent interest in Petropiar, which operates the heavy oil Huyapari Field under an agreement expiring in 2033 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 2035.
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
In Africa, the company is engaged in upstream activities in Angola, the Republic of Congo (ROC), Cameroon, Egypt, Equatorial Guinea, Namibia and Nigeria. Acreage for Africa can be found in the Acreage table. Net daily oil-equivalent production from these countries can be found in the Net Production of Crude Oil, Natural Gas Liquids and Natural Gas table. Angola The company operates and holds a 39.2 percent interest in Block 0, a concession adjacent to the Cabinda coastline. In May 2023, the extension for this Block was fully approved until 2050. The Block 0 Sanha Lean Gas Connection Project
(SLGC) execution continues and is expected to be completed in 2024. SLGC is 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 August 2023, construction started at the South N’Dola project located in Area B of Block 0. Fabrication is ongoing, and first oil is expected in fourth quarter 2025.
Chevron also operates and holds a 31 percent interest in a production sharing contract (PSC) for deepwater Block 14 which expires in 2028.
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 liquefied natural gas (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 have not been recognized for this project.
Angola-Democratic Republic of Congo (DRC) Joint Development Area In December 2023, Chevron signed 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. Chevron has a 31 percent-owned and operated working interest under the PSA.
Angola-Republic of Congo Joint Development Area Chevron operates and holds a 31.25 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 June 2023, the company initiated the process to sell its interest in the ROC portion of Lianzi, while retaining the Angolan portion.
Republic of Congo In June 2023, the company initiated the process to sell its 31.5 percent nonoperated interest in the offshore Haute Mer permit area. The Haute Mer permits of Nkossa, Nsoko and Moho-Bilondo expire in 2040.
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 field located in Equatorial Guinea Block I.
Egypt In the Mediterranean Sea, Chevron holds a 63 percent-owned and operated interest in North Sidi Barrani (Block 2) and North El Dabaa (Block 4) and a 45 percent interest in the Nargis block, as well as a 27 percent nonoperated working interest in both North Marina (Block 6) and North Cleopatra (Block 7). In 2023, the company successfully completed its first exploration well in the Nargis Offshore area. 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 and the Yolanda fields in Block I and a 45 percent-owned and operated interest in the Alen Field in Block O.
The company also holds a 32 percent nonoperated interest in the Alba Field, a 28 percent nonoperated interest in the Alba LPG Plant and a 45 percent interest in the Atlantic Methanol Production Company.
Namibia Chevron has an 80 percent-owned and operated interest in PEL90 (Block 2813B) in the Orange Basin, offshore Namibia. Chevron acquired a 3-D seismic survey in 2023 and is assessing the exploration potential of this Block.
Nigeria Chevron operates and holds a 40 percent interest in six concessions, five operated and one nonoperated in the onshore and near-offshore regions of the Niger Delta. The company also holds acreage positions in four operated and six nonoperated deepwater blocks, with working interests ranging from 20 to 100 percent.
Chevron operates and holds a 67.3 percent interest in the Agbami field, located in deepwater Oil Mining Lease (OML) 127 and OML 128. OML 127 expires in 2024 and OML 128 expires in 2042. In 2023, Chevron executed relevant agreements for the conversion of OML 127 to Petroleum Mining Leases and Petroleum Prospecting Licenses under the Petroleum Industry Act 2021. 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 interest, in both the deepwater Nsiko discoveries in OML 140. Chevron also holds a 27 percent nonoperated 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.
Also, in the deepwater area, the Aparo field in OML 132 and OML 140 and the third-party-owned Bonga South West field in OML 118 share a common geologic structure and would be developed jointly. 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 2023, no proved reserves were recognized for this project.
In 2023, Chevron acquired a 40 percent-owned and operated interest of Oil Prospecting License (OPL) 215 that covers 618,000 acres. A new 3-D seismic survey is in the process of being acquired over this exploration block to assess its potential.
Chevron is the operator of the Escravos Gas Plant with 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, Kurdistan Region of Iraq, Myanmar, 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 Jalalabad expire in 2034, from Moulavi Bazar in 2038 and from Bibiyana in 2034. In 2023, drilling commenced on an appraisal well in the Bibiyana Field.
China Chevron has nonoperated working interests in several areas in China. The company has a 49 percent nonoperated working interest in the Chuandongbei project, including the Loujiazhai and Gunziping natural gas fields located onshore in the Sichuan Basin. The company also has nonoperated working interests of 32.7 percent in Block 16/19 in the Pearl River Mouth Basin and 24.5 percent in the Qinhuangdao (QHD) 32-6 Block in the Bohai Bay. The PSCs for Block 16/19 and QHD 32-6 expire in 2028 and 2024, respectively.
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 July 2023, an appraisal well was completed, confirming estimates related to size and scope of the gas deposit. An optimized development plan is currently under discussion with the government of Cyprus.
Indonesia In October 2023, Chevron closed the sale of its 62 percent interest in two PSCs in the Kutei Basin (Rapak and Ganal) and its 72 percent interest in the Makassar Strait PSC.
Israel Chevron holds a 39.7 percent-owned and operated interest in the Leviathan field, which operates under a concession that expires in 2044. In July 2023, Chevron announced a final investment decision to install a third gathering pipeline that is expected to increase gas production capacity from approximately 1.2 to nearly 1.4 billion cubic feet per day from the Leviathan reservoir. Proved reserves were recognized for this project, which is scheduled for completion in 2025. Chevron is evaluating expansion options to further monetize gas resources at Leviathan, including opportunities via existing and planned regional infrastructure as well as potential avenues for entry into the global LNG market.
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 to 1.2 billion cubic feet per day. This project is scheduled for completion in 2025. Chevron reached final investment decision on Phase 2 of the project in February 2024, which is expected to further increase capacity to approximately 1.6 billion cubic feet of gas per day and includes investment in additional midstream infrastructure. In late 2023, Israel’s Ministry of Energy amended Chevron’s export permit to allow increased quantities to our customer in Egypt.
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 2023 crude oil production was exported through the Caspian Pipeline Consortium (CPC) pipeline.
In 2023, TCO achieved mechanical completion at the Future Growth Project (FGP). In first half 2024, the Wellhead Pressure Management Project (WPMP) is expected to begin field conversion of gathering stations to low pressure continuing through two major train turnarounds. FGP is expected to start-up during first half 2025 and ramp up to full production within three months. Proved reserves have been recognized for the FGP/WPMP.
The Karachaganak field is located in northwest Kazakhstan, and operations are conducted under a PSC that expires in 2038. During 2023, a majority of the exported liquids were transported through the CPC pipeline, with the remaining shipped through diversified routes. Development continued on the Karachaganak Expansion Project Stage 1A and Stage 1B, which are expected to complete in second half 2024 and 2026, respectively. Proved reserves have been recognized for both projects.
Kazakhstan/Russia Chevron has a 15 percent interest in the CPC. In January 2023, CPC announced that the debottlenecking project achieved mechanical completion which will enable increased throughput capacity for the start-up of FGP. 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 In 2023, the company relinquished its 50 percent nonoperated working interest in the Sarta PSC and the 40 percent nonoperated working interest in Qara Dagh PSC expired. Chevron expects an exit from the Kurdistan Region of Iraq in 2024 on execution of the final Relinquishment and Termination Agreements with the government.
Myanmar Chevron has a 41.1 percent nonoperated working interest in a PSC for the production of natural gas from the Yadana, Badamyar and Sein fields, within Blocks M5 and M6, in the Andaman Sea. The PSC expires in 2028. The company also has a 41.1 percent nonoperated working interest in a pipeline company that transports natural gas to the Myanmar-Thailand border for delivery to power plants in Thailand.
In 2022, Chevron signed an agreement to sell the company’s interest in all Myanmar assets and plans to exit the country in 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. Current activities focus on base business optimization and safely re-starting drilling activities. Drilling commenced on an exploration well in late 2023.
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. In May 2023, Chevron was awarded 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. The Gorgon Stage 2 project achieved first gas in May 2023. Progress on the Jansz-Io Compression project continued during 2023 with first gas expected in 2027, and 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 17 years.
Chevron has a 16.7 percent nonoperated working interest in the North West Shelf (NWS) Venture in Western Australia. The company continues to evaluate exploration and appraisal activity across the Carnarvon Basin, in which it holds more than 1.8 million 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 nonoperated working interests ranging from 20 to 50 percent, in three greenhouse gas assessment permits to evaluate the potential of carbon storage. The blocks, including two in the Carnarvon Basin off the northwestern coast of Western Australia and one in the Bonaparte Basin offshore Northern Territory, total nearly 7.8 million acres.
United Kingdom
Chevron holds a 19.4 percent nonoperated working interest in the Clair field, located west of the Shetland Islands. The Clair Ridge project is the second development phase of the Clair field, with a design capacity of 120,000 barrels of crude oil and 100 million cubic feet of natural gas per day. 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 376,000 and 247,000 barrels per day, respectively, in 2023.
During 2023, U.S. and international sales of natural gas averaged 4.7 billion and 6.0 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, Indonesia, 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 2023, the company had a refining network capable of processing 1.8 million barrels per day. Operable capacity at December 31, 2023, and daily refinery inputs for the company and affiliate refineries for 2021 through 2023, are summarized in the table below. Average crude unit distillation capacity utilization was 89.8 percent in 2023 and 88.6 percent in 2022.
At U.S. refineries, crude unit distillation capacity utilization, which includes all crude oil and other inputs, averaged 90.8 percent in 2023, compared with 87.3 percent in 2022. Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 60 percent of Chevron’s U.S. refinery inputs in both 2023 and 2022.
In the United States, the company continued work on projects aimed at improving refinery flexibility and reliability. In 2023, the Pasadena Refinery continued progress on a project that is expected to increase light crude oil throughput capacity to 125,000 barrels per day in 2024. This project is expected to 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. In July 2023, the Richmond refinery commenced making API Group III base oils.
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 Map Ta Phut, Thailand, continues to supply high-quality petroleum products into regional markets.
| | | | | | | | | | | | | | | | | | | | | | | |
| Petroleum Refineries: Locations, Capacities and Crude Oil Inputs | |
| Capacities and inputs in thousands of barrels per day | December 31, 2023 | Refinery Crude Oil Inputs* | |
| Locations | Number | Operable Capacity | 2023 | 2022 | 2021 | |
| Pascagoula | Mississippi | 1 | | 369 | | 346 | | 320 | | 333 | | |
| El Segundo | California | 1 | | 290 | | 226 | | 248 | | 233 | | |
| Richmond | California | 1 | | 257 | | 225 | | 167 | | 211 | | |
| Pasadena | Texas | 1 | | 85 | | 83 | | 77 | | 76 | | |
| Salt Lake City | Utah | 1 | | 58 | | 54 | | 53 | | 50 | | |
| Total Consolidated Companies — United States | 5 | | 1,059 | | 934 | | 865 | | 903 | | |
| Map Ta Phut | Thailand | 1 | | 175 | | 153 | | 156 | | 135 | | |
| | | | | | | |
| | | | | | | |
| Total Consolidated Companies — International | 1 | | 175 | | 153 | | 156 | | 135 | | |
| Affiliates | Various Locations | 2 | | 545 | | 473 | | 483 | | 441 | | |
| Total Including Affiliates — International | 3 | | 720 | | 626 | | 639 | | 576 | | |
| Total Including Affiliates — Worldwide | 8 | | 1.779 | | 1,560 | | 1,504 | | 1,479 | | |
*In addition to crude oil inputs, the company processed other feedstocks of 38, 72 and 58 thousand barrels per day in 2023, 2022 and 2021, respectively. | |
Renewable Fuels
The company develops and produces renewable fuels, including but not limited to renewable diesel, renewable gasoline, biodiesel, sustainable aviation fuel and renewable natural gas (RNG).
In 2023, the El Segundo refinery in California successfully converted the diesel hydrotreater (DHT) to process 100 percent renewable feedstock. The DHT maintains flexibility to process either traditional or renewable feedstocks. El Segundo also produced sustainable aviation fuel and renewable gasoline blendstocks through renewable feed co-processing in the Fluid Catalytic Cracker.
Chevron Renewable Energy Group, Inc. owns and operates 11 biofuel refineries located in the U.S. and Germany, 10 biofuel refineries producing biodiesel and one producing renewable diesel. Work at the Emden refinery in Germany to enhance feedstock flexibility was completed in 2023. Expansion work at the Geismar renewable diesel plant in Louisiana to increase production capacity from 7,000 to 22,000 barrels per day continues on schedule, with full operations expected in 2024.
Chevron holds a 50 percent working interest in Bunge Chevron Ag Renewables LLC, which produces soybean oil from processing facilities in Destrehan, Louisiana, and Cairo, Illinois. Soybean oil can be used as a renewable feedstock to make renewable diesel, biodiesel and sustainable aviation fuel.
The company continues to advance its dairy biomethane activities with its joint venture partners, Brightmark Fund Holdings LLC (Brightmark) and California Bioenergy, LLC (CalBio). In 2023, Chevron’s joint venture with Brightmark achieved commercial operations on seven new anaerobic digestion dairy farm projects across Michigan, Florida and Arizona. Also, in California, construction began on seven new anaerobic digestion dairy farm projects jointly owned with CalBio.
Chevron participates in the RNG value chain through its ownership of Beyond6, LLC and its nationwide network of 56 compressed natural gas stations.
Marketing Operations
The company markets petroleum products under the principal brands of “Chevron,” “Texaco” and “Caltex” throughout many parts of the world. The following table identifies the company’s and its affiliates’ refined products sales volumes, excluding intercompany sales, for the three years ended December 31, 2023.
| | | | | | | | | | | | | | |
| Refined Products Sales Volumes | |
| Thousands of barrels per day | 2023 | 2022 | 2021 | |
| United States | | | | |
Gasoline1 | 642 | | 639 | 655 | |
| Jet Fuel | 260 | | 212 | 173 | |
Diesel/Gas Oil1 | 227 | | 216 | 179 | |
| Fuel Oil | 44 | | 56 | 39 | |
Other Petroleum Products2 | 114 | | 105 | 93 | |
| Total United States | 1,287 | | 1,228 | | 1,139 | | |
International3 | | | | |
| Gasoline | 353 | | 336 | 321 | |
| Jet Fuel | 234 | | 196 | 140 | |
Diesel/Gas Oil1 | 472 | | 464 | 471 | |
| Fuel Oil | 161 | | 168 | 177 | |
Other Petroleum Products2 | 225 | | 222 | 206 | |
| Total International | 1,445 | | 1,386 | | 1,315 | | |
Total Worldwide3 | 2,732 | | 2,614 | | 2,454 | | |
1 Includes products sold by Chevron Renewable Energy Group: | 44 | | 24 | — | |
2 Principally naphtha, lubricants, asphalt and coke. | | |
3 Includes share of affiliates’ sales: | 389 | | 389 | 357 | |
In the United States, the company markets primarily under the principal brands of “Chevron” and “Texaco”. At year-end 2023, the company supplied directly or through retailers and marketers approximately 8,300 Chevron- and Texaco-branded service stations, primarily in the southern and western states. Approximately 365 of these outlets are company-owned or -leased stations.
Outside the United States, Chevron supplied directly or through retailers and marketers approximately 5,600 branded service stations, including affiliates. The company markets in Latin America using the Texaco brand. In the Asia-Pacific region and the Middle East, the company uses the Caltex brand. In South Korea, the company operates through its 50 percent-owned affiliate, GSC. The rebranding project to transition service stations in Australia from Puma to the Caltex brand is expected to complete in 2024.
Chevron markets commercial aviation fuel to 57 airports worldwide. The company also markets an extensive line of lubricant and coolant products under the product names Havoline, Delo, Ursa, Meropa, Rando, Clarity and Taro in the United States and worldwide under these three brands: Chevron, Texaco and Caltex.
Chemicals Operations
Chevron Oronite Company develops, manufactures and markets performance additives for lubricating oils and fuels and conducts research and development for additive component and blended packages. At the end of 2023, the company manufactured, blended or conducted research at 11 locations around the world.
Chevron owns a 50 percent interest in Chevron Phillips Chemical Company LLC (CPChem). CPChem produces olefins, polyolefins and alpha olefins and is a supplier of aromatics and polyethylene pipe, in addition to participating in the specialty chemical and specialty plastics markets. At the end of 2023, CPChem owned or had joint-venture interests in 30 manufacturing facilities and two research and development centers around the world.
CPChem has two major integrated polymer projects under construction, the Golden Triangle Polymers Project in Orange, Texas, for which CPChem holds a 51 percent-owned and operated interest and the Ras Laffan Petrochemical Project in Ras Laffan, Qatar, for which CPChem holds a 30 percent nonoperated working interest. Start-up for both projects is targeted for 2026.
CPChem continued development of the Low Viscosity Poly Alpha Olefin Expansion Project at the CPChem Beringen, Belgium site, with a targeted startup in 2024. In 2023, CPChem completed several other projects at existing facilities in the U.S. Gulf Coast region, including: an Ethylene Plant Project in Cedar Bayou, Texas, a C3 Splitter Project in Cedar Bayou, Texas, and a 1-Hexene plant in Old Ocean, Texas.
Chevron is also involved in the petrochemical business through the operations of GSC, the company’s 50 percent-owned affiliate in South Korea. GSC manufactures aromatics, including benzene, toluene and xylene. These base chemicals are used to produce a range of products, including adhesives, plastics and textile fibers. GSC also produces olefins such as ethylene, polyethylene and polypropylene, which are used to make automotive and home appliance parts, food packaging, laboratory equipment, building materials, adhesives, paint and textiles.
Transportation
Pipelines Chevron owns and operates a network of crude oil, natural gas and product pipelines and other infrastructure assets in the United States. In addition, Chevron operates pipelines for its 50 percent-owned CPChem affiliate. The company also has direct and indirect interests in other U.S. and international pipelines.
Refer to Nigeria and Kazakhstan/Russia in the Upstream section for information on the West African Gas Pipeline and the Caspian Pipeline Consortium. Shipping The company’s marine fleet includes both U.S. and foreign flagged vessels. The operated fleet consists of conventional crude tankers, product carriers and LNG vessels. These vessels transport crude oil, LNG, refined products and feedstock in support of the company’s global upstream and downstream businesses. In 2023, contracts were executed for construction of two additional LNG vessels, and an agreement was signed to retrofit four existing LNG vessels with technology to reduce their carbon intensity.
Chevron is a strategic partner of the Global Centre for Maritime Decarbonisation. This Singapore-based nonprofit supports cross-industry collaboration to help the International Maritime Organization meet its greenhouse gas emissions reduction goals for 2030 and 2050.
Other Businesses
Chevron Technical Center The company aims to scale affordable, innovative technology solutions to support a sustainable, resilient energy system. Chevron Technical Center conducts research, develops and qualifies technology, and provides technical services and competency development in support of business outcomes. Areas of expertise include earth sciences, reservoir and production engineering, facilities engineering, reserve governance and reporting, capital projects, drilling and completions, technology ventures, and downstream technology and services.
The company is focused on technologies that are ready to adopt and scale today, as well as breakthrough technologies in support of its traditional and new energy businesses, including shale and tight recovery, deepwater development, lowering the carbon intensity of heavy oil, advancing facilities of the future, renewable fuels, carbon capture utilization and storage, hydrogen and geothermal energy.
Chevron leverages its in-house expertise to undertake internal research and development to advance energy solutions. The company holds more than 4,400 patents for new technologies, with over 3,200 additional patents pending, making Chevron one of the leading patent holders in the industry.
Collaboration is increasingly important to close innovation gaps and integrate emerging technologies into existing energy value chains. Chevron works with startups, universities, national laboratories, joint ventures, and service companies to explore, evaluate, and scale solutions. Chevron is also enabling efficient and responsible artificial intelligence solutions through work with other companies and institutions.
The Chevron Technology Ventures (CTV) unit identifies and invests in externally developed technologies and new business solutions with the potential to enhance the way Chevron produces and delivers affordable, reliable and lower carbon energy. CTV has more than two decades of being the primary on-ramp for external innovation into Chevron, including venture investing, with eight funds that have supported more than 140 startups and worked with more than 350 co-investors.
In addition to the company’s own managed funds, Chevron also makes investments indirectly through the following funds: the Oil and Gas Climate Initiative (OGCI) Climate Investments’ Catalyst Fund I, which targets decarbonization within the oil and gas, industrial, built environments and commercial transportation sectors; Emerald funds, one of which targets
energy, water, food, mobility, industrial IT and advanced materials and another that focuses on sustainable packaging; Carbon Direct Capital, a growth equity investor in carbon management technologies; and the HX Venture Fund that targets Houston, Texas high-growth start-up companies.
Some of the investments the company makes in the areas described above are in new or unproven technologies and business processes; therefore, the ultimate technical or commercial successes of these investments are not certain. Refer to Note 27 Other Financial Information for quantification of the company’s research and development expenses. Information Technology The company’s information technology organization integrates computing, data management and analytics, cybersecurity and other key infrastructure technologies to provide a digital foundation to enable Chevron’s global operations and business processes. Building on decades of analytics and data science expertise, the company accelerated its application of artificial intelligence in 2023 to drive innovation, increase employee productivity and deliver business outcomes.
Chevron New Energies The new energies organization is advancing the company’s strategy by bringing together dedicated resources focused on developing new lower carbon businesses that have the potential to scale. Its focus includes commercialization opportunities in hydrogen, carbon capture and storage, carbon offsets and emerging technologies such as geothermal. These businesses are expected to support the company’s efforts to lower the carbon intensity of its operations and become high-growth opportunities with the potential to generate competitive returns.
Environmental Protection The company designs, operates and maintains its facilities to avoid potential spills or leaks and to minimize the impact of those that may occur. Chevron requires its facilities and operations to have operating standards and processes and emergency response plans that address significant risks identified through site-specific risk and impact assessments. Chevron also requires that sufficient resources be available to execute these plans. In the unlikely event that a major spill or leak occurs, Chevron also maintains a Worldwide Emergency Response Team comprised of employees who are trained in various aspects of emergency response, including post-incident remediation.
To complement the company’s capabilities, Chevron maintains active membership in international oil spill response cooperatives, including the Marine Spill Response Corporation, which operates in U.S. territorial waters, and Oil Spill Response, Ltd., which operates globally. The company is a founding member of the Marine Well Containment Company, whose primary mission is to expediently deploy containment equipment and systems to capture and contain crude oil in the unlikely event of a future loss of control of a deepwater well in the Gulf of Mexico. In addition, the company is a member of the Subsea Well Response Project, which has the objective to further develop the industry’s capability to contain and shut in subsea well control incidents in different regions of the world.
The company aims to lower the carbon intensity of its oil and gas operations and comply with the greenhouse gas-related laws and regulations to which it is subject. Refer to Item 1A. Risk Factors for further discussion of greenhouse gas regulation and climate change and the associated risks to Chevron’s business. Refer to Management’s Discussion and Analysis of Financial Conditions and Results of Operations Business Environment and Outlook on pages 34 through 36 for further discussion of climate change related trends and uncertainties. Item 1A. Risk Factors
As a global energy company, Chevron is subject to a variety of risks that could materially impact the company’s results of operations and financial condition.
BUSINESS AND OPERATIONAL RISK FACTORS
Chevron is exposed to the effects of changing commodity prices Chevron is primarily in a commodities business that has a history of price volatility. The most significant factor that affects the company’s results of operations is the price of crude oil, which can be influenced by general economic conditions and level of economic growth, including low or negative growth; industry production and inventory levels; technology advancements, including those in pursuit of a lower carbon economy; production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries or other producers; weather-related damage and disruptions due to other natural or human causes beyond our control; competing fuel prices; geopolitical risks; the pace of energy transition; customer and consumer preferences and the use of
substitutes; and governmental regulations, policies and other actions regarding the development of oil and gas reserves, as well as greenhouse gas emissions and climate change. Chevron evaluates the risk of changing commodity prices as a core part of its business planning process. An investment in the company carries significant exposure to fluctuations in global crude oil prices.
Extended periods of low prices for crude oil can have a material adverse impact on the company’s results of operations, financial condition and liquidity. Among other things, the company’s upstream earnings, cash flows, and capital expenditure programs could be negatively affected, as could its production and proved reserves. Upstream assets may also become impaired. Downstream earnings could be negatively affected because they depend upon the supply and demand for refined products and the associated margins on refined product sales. A significant or sustained decline in liquidity could adversely affect the company’s credit ratings, potentially increase financing costs and reduce access to capital markets. The company may be unable to realize anticipated cost savings, expenditure reductions and asset sales that are intended to compensate for such downturns, and such downturns may also slow the pace and scale at which we are able to invest in our business, including our Chevron New Energies organization. In some cases, transferred liabilities, including for abandonment and decommissioning of divested oil and gas assets, have returned and may continue to return to the company when an acquirer of those assets subsequently declares bankruptcy. In addition, extended periods of low commodity prices can have a material adverse impact on the results of operations, financial condition and liquidity of the company’s suppliers, vendors, partners and equity affiliates upon which the company’s own results of operations and financial condition depend.
The scope of Chevron’s business will decline if the company does not successfully develop resources The company is in an extractive business; therefore, if it is not successful in replacing the crude oil and natural gas it produces with good prospects for future organic opportunities or through acquisitions, exploration or technology, the company’s business will decline. Creating and maintaining an inventory of economic projects depends on many factors, including obtaining and renewing rights to explore, develop and produce hydrocarbons; drilling success; reservoir optimization; technology advancements; ability to bring long-lead-time, capital-intensive projects to completion on budget and on schedule; partner alignment, including strategic support; and efficient and profitable operation of mature properties.
The company’s operations could be disrupted by natural or human causes beyond its control Chevron operates in both urban areas and remote and sometimes inhospitable regions. The company’s operations are therefore subject to disruption from natural or human causes beyond its control, including risks from hurricanes, severe storms, floods, heat waves, other forms of severe weather, wildfires, ambient temperature increases, sea level rise, war or other military conflicts such as the war between Israel and Hamas and the military conflict between Russia and Ukraine, accidents, civil unrest, political events, fires, earthquakes, system failures, cyber threats, terrorist acts and epidemic or pandemic diseases, some of which may be impacted by climate change and any of which could result in suspension of operations or harm to people or the natural environment.
Chevron’s risk management systems are designed to assess potential physical and other risks to its operations and assets and to plan for their resiliency. While capital investment reviews and decisions incorporate potential ranges of physical risks such as storm severity and frequency, sea level rise, air and water temperature, precipitation, fresh water access, wind speed, and earthquake severity, among other factors, it is difficult to predict with certainty the timing, frequency or severity of such events, any of which could have a material adverse effect on the company's results of operations or financial condition.
Cyberattacks targeting Chevron’s operational technology networks or other digital infrastructure could have a material adverse impact on the company’s business and results of operations There are numerous and evolving risks to Chevron’s cybersecurity and privacy from cyber threat actors, including criminal hackers, state-sponsored intrusions, industrial espionage and employee malfeasance. These cyber threat actors, whether internal or external to Chevron, are becoming more sophisticated and coordinated in their attempts to access the company’s information technology (IT) systems and data, including the IT systems of cloud providers and other third parties with whom the company conducts business through, without limitation, malicious software; data privacy breaches by employees, insiders or others with authorized access; cyber or phishing-attacks; ransomware; attempts to gain unauthorized access to our data and systems; and other electronic security breaches. The cyber risk landscape changes over time due to a variety of internal and external factors, including during political tensions, war or other military conflicts, or civil unrest. Although Chevron devotes significant resources to prevent unwanted intrusions and to protect its systems and data, whether such data is housed internally or by external third parties, the company has experienced and will continue to experience cyber incidents of varying degrees in the conduct of its business. Cyber threat actors could compromise the company’s operational technology networks or other
critical systems and infrastructure, resulting in disruptions to its business operations, injury to people, harm to the environment or its assets, disruptions in access to its financial reporting systems, or loss, misuse or corruption of its critical data and proprietary information, including without limitation its intellectual property and business information and that of its employees, customers, partners and other third parties. Any of the foregoing can be exacerbated by a delay or failure to detect a cyber incident or the full extent of such incident. Further, the company is increasingly experiencing cyber incidents related to its third-party vendors. Some third-party vendors house the company’s critical data and proprietary information on their IT systems, including the cloud; others have access to Chevron’s IT systems or provide software through which threat actors could gain access or introduce malware to Chevron’s IT systems. Regardless of the precise method or form, cyber events could result in significant financial losses, legal or regulatory violations, reputational harm, and legal liability and could ultimately have a material adverse effect on the company’s business and results of operations.
The company’s operations have inherent risks and hazards that require significant and continuous oversight Chevron’s results depend on its ability to identify and mitigate the risks and hazards inherent to operating in the energy industry. The company seeks to minimize these operational risks by carefully designing and building its facilities and conducting its operations in a safe and reliable manner. However, failure to manage these risks effectively could impair our ability to operate and result in unexpected incidents, including releases, explosions or mechanical failures resulting in personal injury, loss of life, environmental damage, loss of revenues, legal liability and/or disruption to operations. Chevron has implemented and maintains a system of corporate policies, standards, processes and systems, behaviors and compliance mechanisms to manage safety, health, environmental, reliability and efficiency risks; to verify compliance with applicable laws and policies; and to respond to and learn from unexpected incidents. In certain situations where Chevron is not the operator, the company may have limited influence and control over third parties, which may limit its ability to manage and control such risks.
The company does not insure against all potential losses, which could result in significant financial exposure The company does not have commercial insurance or third-party indemnities to fully cover all operational risks or potential liability in the event of a significant incident or series of incidents causing catastrophic loss. As a result, the company is, to a substantial extent, self-insured for such events. The company relies on existing liquidity, financial resources and borrowing capacity to meet short-term obligations that would arise from such an event or series of events. The occurrence of a significant incident, series of events, or unforeseen liability for which the company is self-insured, not fully insured or for which insurance recovery is significantly delayed could have a material adverse effect on the company’s results of operations or financial condition.
Chevron may not complete the acquisition of Hess Corporation within the time frame the company anticipates or at all, which could have adverse effects on Chevron The completion of the acquisition of Hess Corporation (Hess) is subject to a number of conditions, including regulatory approvals and approval by Hess stockholders of the adoption of the merger agreement. Additionally, Hess and Chevron have been engaged in discussions with Exxon Mobil Corporation and China National Offshore Oil Corporation regarding a right of first refusal provision in the joint operating agreement for the Stabroek Block offshore Guyana. If these discussions do not result in an acceptable resolution and arbitration (if pursued) does not result in a confirmation that such right of first refusal provision is inapplicable to the merger, then there would be a failure of a closing condition under the Merger Agreement, in which case the merger would not close. For additional information, please see the section entitled “The Merger—Stabroek JOA” in Chevron’s preliminary registration statement on Form S-4 to be filed on February 26, 2024.
Further, on December 7, 2023, Chevron and Hess each received a request for additional information and documentary materials (Second Request) from the Federal Trade Commission (FTC) in connection with the FTC’s review of the merger. Issuance of the Second Request extends the waiting period imposed by the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, until 30 days after Chevron and Hess have substantially complied with the Second Request, unless that period is extended voluntarily by Chevron and Hess or terminated sooner by the FTC.
The failure to satisfy all of the required conditions could delay the completion of the acquisition for a significant period of time or prevent it from occurring at all. In addition, the terms and conditions of the required regulatory authorizations and consents for the acquisition that are granted, if any, may impose requirements, limitations or costs or place restrictions on the conduct of the company’s business after the transaction or materially delay the completion of the acquisition. A delay in completing the acquisition could cause the company to realize some or all of the benefits later than we otherwise expect to realize them if the acquisition is successfully completed within the anticipated timeframe, which could result in additional transaction costs or in other negative effects associated with uncertainty about completion of the acquisition.
Acquisitions may cause Chevron’s financial results to differ from the company’s expectations or the expectations of the investment community, the company may not achieve the anticipated benefits of the acquisition, and the acquisition may disrupt the company’s current plans or operations The success of prior acquisitions, such as PDC Energy, Inc. (PDC), and the pending acquisition of Hess will depend, in part, on Chevron’s ability to successfully integrate each of the businesses of PDC and Hess and realize the anticipated benefits, including synergies. Difficulties in integrating PDC and Hess may result in the failure to realize anticipated synergies in the expected timeframes, in operational challenges, and in the diversion of management’s attention from ongoing business concerns, as well as in unforeseen expenses associated with the acquisitions, which may have an adverse impact on the company’s financial results.
LEGAL, REGULATORY AND ESG-RELATED RISK FACTORS
Chevron’s business subjects the company to liability risks from litigation or government action The company produces, transports, refines and markets potentially hazardous materials, and it purchases, handles and disposes of other potentially hazardous materials in the course of its business. Chevron’s operations also produce byproducts, which may be considered pollutants. Often these operations are conducted through joint ventures over which the company may have limited influence and control. Any of these activities could result in liability or significant delays in operations arising from private litigation or government action. For example, liability or delays could result from an accidental, unlawful discharge or from new conclusions about the effects of the company’s operations on human health or the environment. In addition, to the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.
For information concerning some of the litigation in which the company is involved, see Note 16 Litigation. Political instability and significant changes in the legal and regulatory environment could harm Chevron’s business The company’s operations, particularly exploration and production, can be affected by changing political, regulatory and economic environments in the various countries in which it operates. As has occurred in the past, actions could be taken by governments to increase public ownership of the company’s partially or wholly owned businesses, to force contract renegotiations, or to impose additional taxes or royalties. In certain locations, governments have proposed or imposed restrictions on the company’s operations, trade, currency exchange controls, burdensome taxes, and public disclosure requirements that might harm the company’s competitiveness or relations with other governments or third parties. In other countries, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries, and internal unrest, acts of violence or strained relations between a government and the company or other governments may adversely affect the company’s operations. Those developments have, at times, significantly affected the company’s operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries. Further, Chevron is required to comply with sanctions and other trade laws and regulations of the United States and other jurisdictions where we operate, such as sanctions imposed in Venezuela and Russia, which, depending upon their scope, could adversely impact the company’s operations and financial results in these countries. In addition, litigation or 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, such as those related to the use of hydraulic fracturing or bans on drilling, or any law or regulation that impacts the demand for our products, could adversely affect the company’s current or anticipated future operations and profitability.
Legislative or regulatory changes in tax laws may expose Chevron to additional tax liabilities Changes in tax laws and regulations around the world are regularly enacted due to political or economic factors beyond the company’s control. Chevron’s taxes in the jurisdictions where the company conducts business activities have been and may be adversely affected by changes in tax laws or regulations, including but not limited to, substantive changes in, reductions in, or the repeal or expiration of tax incentives, such as U.S. federal tax incentives for biodiesel blending, which expire in 2024. Furthermore, Chevron’s tax returns are subject to audit by taxing authorities around the world. There is no assurance that taxing authorities or courts will agree with the positions that Chevron has reflected on the company’s tax returns, in which case interest and penalties could be imposed that may have a material adverse effect on the company’s results of operations or financial condition.
During periods of high profitability for certain companies or industries, there are often calls for increased taxes on profits, often called “windfall profit” taxes. Governments in various jurisdictions, including California and Australia, have announced, proposed, or implemented windfall profit taxes for companies operating in the energy and oil and gas sectors. Such taxes may be imposed on us or may be increased in the future in these or other jurisdictions. The imposition of, or
increase in, such windfall profit taxes could adversely affect the company’s current or anticipated future operations and profitability.
Legislation, regulation, and other government actions and shifting customer and consumer preferences and other private efforts related to greenhouse gas (GHG) emissions and climate change could continue to increase Chevron’s operational costs and reduce demand for Chevron’s hydrocarbon and other products, resulting in a material adverse effect on the company’s results of operations and financial condition Chevron has experienced and may be further challenged by increases in the impacts of international and domestic legislation, regulation, or other government actions relating to GHG emissions (e.g., carbon dioxide and methane) and climate change. International agreements and national, regional, and state legislation and regulatory measures that aim to directly or indirectly limit or reduce GHG emissions are in various stages of implementation.
Legislation, regulation, and other government actions related to GHG emissions and climate change could reduce demand for Chevron’s hydrocarbon and other products and/or continue to increase Chevron’s operational costs and reduce its return on investment. The Paris Agreement went into effect in November 2016, and a number of countries in which we operate have adopted and may adopt additional policies intended to meet their Paris Agreement goals. Globally, multiple jurisdictions are considering adopting or are in the process of implementing laws or regulations to directly regulate GHG emissions through a carbon tax, a cap-and-trade program, performance standards or other mechanisms, or to attempt to indirectly advance reduction of GHG emissions through restrictive permitting, procurement standards, trade barriers, minimum renewable usage requirements, financing standards, standards or requirements for environmental benefit claims, increased GHG reporting and climate-related disclosure requirements, or tax advantages or other incentives to promote the use of alternative energy, fuel sources or lower-carbon technologies. For example, the company is currently subject to implemented programs in certain jurisdictions, such as the Renewable Fuel Standard program in the U.S., California’s Cap-and-Trade Program and Low Carbon Fuel Standard, and newly approved mandates such as the California Air Resources Board Advanced Clean Cars II regulations, as well as other indirect regulation of GHG emissions, which may, among other things, ban or restrict technologies or products that use the company’s products. GHG emissions that may be directly regulated through such efforts include, among others, those associated with the company’s exploration and production of hydrocarbons; the upgrading of production from oil sands into synthetic oil; power generation; the conversion of crude oil, natural gas and biofeedstocks into refined hydrocarbon products; the processing, liquefaction, and regasification of natural gas; the transportation of crude oil, natural gas, and other products; and customers’ and consumers’ use of the company’s hydrocarbon products. In addition, the U.S. Inflation Reduction Act (IRA) implements various incentives for lower carbon activities, including carbon capture and storage and the production of hydrogen and sustainable aviation fuel. Although the IRA offers incentives that could support certain lower carbon lines of business, those same incentives could negatively impact supply and/or demand for our oil and gas products in the future or any existing or future lower carbon business lines. Many of these actions, as well as customers’ and consumers’ preferences and use of the company’s products or substitute products, and actions taken by the company’s competitors in response to legislation and regulations, are beyond the company’s control.
Similar to any significant changes in the regulatory environment, climate change-related legislation, regulation, or other government actions may curtail profitability in oil and gas and lower carbon businesses, as well as render the extraction of the company’s hydrocarbon resources economically infeasible. In particular, GHG emissions-related legislation, regulations, and other government actions, and shifting customer and consumer preferences and other private efforts aimed at reducing GHG emissions may result in increased and substantial capital, compliance, operating, and maintenance costs and could, among other things, reduce demand for hydrocarbons and the company’s hydrocarbon-based products; increase demand for lower carbon products and alternative energy sources; make the company’s products more expensive; adversely affect the economic feasibility of the company’s resources; impact or limit our business plans; and adversely affect the company’s sales volumes, revenues, margins and reputation. For example, some jurisdictions are in various stages of design, adoption, and implementation of policies and programs that cap emissions and/or require short-, medium-, and long-term GHG reductions by operators at the asset or facility level, which may not be technologically feasible, or which could require significant capital expenditure, increase costs of or limit production, result in impairment of assets and limit Chevron’s ability to cost-effectively reduce GHG emissions across its global portfolio.
The ultimate effect of international agreements; national, regional, and state legislation and regulation; and government and private actions related to GHG emissions and climate change on the company’s financial performance, and the timing of
these effects, will depend on a number of factors. Such factors include, among others, the sectors covered, the GHG emissions reductions required, standardized carbon accounting, the extent to which Chevron would be able to receive, generate, or purchase credits, the price and availability of credits and the extent to which the company is able to recover, or continue to recover, the costs incurred through the pricing of the company’s products in the competitive marketplace. Further, the ultimate impact of GHG emissions and climate change-related agreements, legislation, regulation, and government actions on the company’s financial performance is highly uncertain because the company is unable to predict with certainty, for a multitude of individual jurisdictions, the outcome of political decision-making processes, including the actual laws and regulations enacted, the variables and trade-offs that inevitably occur in connection with such processes, and market conditions, including the responses of consumers to such changes.
Increasing attention to environmental, social, and governance (ESG) matters impacts our company Increasing attention to ESG matters, including those related to climate change and sustainability, increasing societal, investor and legislative pressure on companies to address ESG matters, and potential customer and consumer use of substitutes to Chevron’s products have resulted and may continue to result in changes to the portfolio and company activities, increased costs, reduced demand for our products, reduced profits, increased investigations and litigation or threats thereof, negative impacts on our stock price and access to capital markets, impaired participation in public discourse and debate by the company relating to mandatory and voluntary standards and regulations, and damage to our reputation. For example, increasing attention to ESG matters, including climate change, may result in demand shifts for our hydrocarbon products and additional litigation and governmental investigations, or threats thereof, against the company. For instance, we have received investigative requests and demands from the U.S. Congress for information relating to climate change, methane leak detection and repair, and other topics, and further requests and/or demands are possible. At this time, Chevron cannot predict the ultimate impact any Congressional or other investigations may have on the company. Information related to climate-change related litigation matters is included in Note 16 Litigation under the heading “Climate Change.”
Some stakeholders, including but not limited to sovereign wealth, pension, and endowment funds, have been divesting and promoting divestment of or screening out of fossil fuel equities and urging lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Further, voluntary carbon-related and target-setting frameworks have developed, and continue to develop, that limit the ability of certain sectors, including the oil and gas sector, from participating, and may result in exclusion of the company’s equity from being included as an investment option in portfolios. In addition, some stakeholders, including some of our investors, have divergent and evolving views on our ESG-related strategies and priorities, vis-à-vis our lines of business, calling for focus on increased production of oil and gas products rather than new business lines and climate-related targets. These circumstances, among others, may result in pressure from activists on production; unfavorable reputational impacts, including inaccurate perceptions or a misrepresentation of our actual ESG policies, practices and performance; diversion of management’s attention and resources; and proxy fights, among other material adverse impacts on our businesses.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters, including climate change and climate-related risks (including entities commonly referred to as “raters and rankers”). Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and investment community divestment initiatives, among other actions, may lead to negative investor sentiment toward Chevron and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Additionally, evolving expectations on various ESG matters, including biodiversity, waste and water, have increased, and may continue to increase, costs, require changes in how we operate and lead to negative stakeholder sentiment.
Our aspirations, targets and disclosures related to ESG matters subject us to numerous risks that may negatively impact our reputation and stock price or result in other material adverse impacts to the company Chevron has announced an aspiration to achieve net zero Scope 1 and 2 emissions in upstream by 2050. The company also has set nearer-term GHG emission-related targets for zero routine flaring, upstream carbon intensity, and portfolio carbon intensity. These and other aspirations, targets or objectives reflect our current plans and aspirations, and Chevron may change them for various reasons, including evolving market conditions; changes in our portfolio; and financial, operational, regulatory, reputational, legal and other factors.
Our ability to achieve any aspiration, target or objective, including with respect to climate-related initiatives, our lower carbon strategy outlined in the Management’s Discussion and Analysis of Financial Condition and Results of Operations, pages 34 through 36, and any lower carbon new energy businesses, is subject to numerous risks, many of which are outside of our control. Examples of such risks include: (1) sufficient and substantial advances in technology, including the
continuing progress of commercially viable technologies and low- or non-carbon-based energy sources; (2) the granting of necessary permits by governing authorities; (3) the availability and acceptability of cost-effective, verifiable carbon credits; (4) the availability of suppliers that can meet our sustainability and other standards; (5) evolving regulatory requirements, including changes to IPCC’s Global Warming Potentials, affecting ESG standards or disclosures; (6) evolving standards for tracking and reporting on emissions and emission reductions and removals; (7) customers’ and consumers’ preferences and use of the company’s products or substitute products; and (8) actions taken by the company’s competitors in response to legislation and regulations.
The standards and regulations for tracking, reporting, marketing and advertising related to ESG matters are relatively new, have not been harmonized and continue to evolve. Our selection of disclosure frameworks that seek to align with various voluntary reporting standards may change from time to time and may result in a lack of comparative data from period to period.
Our processes and controls may not always align with evolving voluntary standards for identifying, measuring, and reporting ESG metrics, our interpretation of reporting standards may differ from those of others, and such standards may change over time, including through non-public processes, any of which could result in significant revisions to our goals or reported progress in achieving such goals. In addition, Chevron participates, along with other companies, institutes, universities, trade associations and other organizations, in various initiatives, campaigns, and other projects that express various ambitions, aspirations and goals related to climate change, emissions and energy transition. Chevron’s individual ambitions, future performance or policies may differ from the ambitions of such organizations or the individual ambitions of other participants in these various initiatives, campaigns, and other projects, and Chevron may unilaterally change its individual ambitions, aspirations and goals. Achievement of or efforts to achieve aspirations, targets, goals and objectives such as the foregoing and future internal climate-related initiatives has, and may continue to, increase costs, and, in addition, may require purchase of carbon credits, or limit or impact the company’s business plans, operations and financial results, potentially resulting in the reduction to the economic end-of-life of certain assets, impairing the associated net book value, among other material adverse impacts. Our failure or perceived failure to pursue or fulfill such aspirations, targets, goals and objectives or to satisfy various reporting standards within the timelines we announce, or at all, could have a negative impact on the company’s reputation, investor sentiment, ratings outcomes for evaluating the company’s approach to ESG matters, stock price, and cost of capital and expose us to government enforcement actions and private litigation, among other material adverse impacts.
GENERAL RISK FACTORS
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 preparing the company’s periodic reports under the Securities Exchange Act of 1934, including its financial statements, Chevron’s management is required under applicable rules and regulations to make estimates and assumptions as of a specified date. These estimates and assumptions are based on management’s best estimates and experience as of that date and are subject to substantial risk and uncertainty. Materially different results may occur as circumstances change and additional information becomes known. Areas requiring significant estimates and assumptions by management include impairments to property, plant and equipment and investments in affiliates; estimates of crude oil and natural gas recoverable reserves; accruals for estimated liabilities, including litigation reserves; and measurement of benefit obligations for pension and other postretirement benefit plans. Changes in estimates or assumptions or the information underlying the assumptions, such as changes in the company’s business plans, general market conditions, the pace of energy transition, or changes in the company’s outlook on commodity prices, could affect reported amounts of assets, liabilities or expenses.
Item 1B. Unresolved Staff Comments
None.
Item 1C. Cybersecurity
Chevron’s business and proprietary information, information technology (IT) and operational technology (OT) networks are essential to its success. The company’s cybersecurity program is designed to protect its information assets and operations from external and internal cyber threats by identifying and appropriately managing and mitigating risks while ensuring business resiliency. This program is integrated within the company’s Enterprise Risk Management (ERM) process, which is the company’s systematic approach to identifying, managing and assessing major risks and safeguards,
including cybersecurity risks. Chevron uses a risk-based information security process aligned with the National Institute of Standards and Technology (NIST) Cybersecurity Framework to identify, prioritize and mitigate cyber risks.
The company’s worldwide team of cybersecurity professionals undertakes a range of preemptive activities to protect its people, assets and reputation globally. The company also leverages internal and external resources to monitor cybersecurity threats to its systems and networks and to understand the broader threat environment. The company seeks to remove exploitable weaknesses in its systems or devices before they become a threat. Chevron security experts use automated threat intelligence feeds to increase vulnerability awareness, taking action to mitigate the highest risks. The company’s cybersecurity guardrails, which are high-level design requirements expected to be built into any new digital solutions being deployed, are also updated on an ongoing basis to align with changes in industry standards and the evolving threat environment.
Chevron’s cyber risk management process includes testing and risk assessments of technologies, third-party suppliers, and its IT and OT networks. These assessments ensure that our focus is on the highest priorities to maintain the security of our company’s assets. To further protect the company’s systems and data, Chevron’s cybersecurity organization has threat intelligence capabilities to monitor security breaches impacting third-party suppliers. As third-party risks increase, the company’s approach to third-party supplier risk management and qualification continues to evolve, including the ongoing expansion of its current supplier risk management program beyond IT vendors to other high-risk, third-party vendors.
Chevron’s Chief Information Security Officer (CISO) leads a global cybersecurity team that operationalizes and manages the company’s cybersecurity program and strategy. Chevron’s CISO has more than 20 years of cybersecurity experience and is responsible for providing a single and consolidated view of the company’s enterprise cybersecurity risk. Before joining Chevron, he held a leadership role in cyber threat analysis with the U.S. Department of State’s Bureau of Diplomatic Security. Chevron’s CISO reports to the Chief Information Officer (CIO) who is responsible for Chevron’s broader IT program, including resiliency and ability to remediate and recover from a cybersecurity incident to minimize impacts to the business and operations. He has more than 30 years of experience in IT and the oil and gas industry.
Chevron operates four Cyber Intelligence Centers around the world, some co-located with critical assets, with cyber professionals who monitor and respond to cyber threats 24 hours a day, 365 days a year, to limit the scope and impact of cyber incidents in its networks. Chevron’s CISO regularly receives cybersecurity operations reports detailing prevention, detection, mitigation and remediation efforts associated with cyber incidents, both on Chevron’s networks and third-party supplier networks. The CISO has authority to mobilize a cross-functional cyber incident response team, including outside cybersecurity experts, to drive mitigation and remediation actions. Status updates on incidents are provided to senior management and to the Board, as appropriate.
The company’s dedicated cyber risk organization meets regularly with business units to raise cyber risk awareness and keep diverse cybersecurity skill sets connected across the enterprise. Chevron has invested in broad cybersecurity awareness and required training to educate those with access to Chevron’s networks on company policy and best practices. The company conducts regular phishing tests to train and assess its workforce’s ability to identify malicious emails.
Chevron’s Corporate Audit Department has a dedicated team responsible for IT and information security (including cybersecurity) audits. Chevron also leverages external resources to reinforce its cybersecurity capabilities. On a regular basis, external consultants provide a maturity assessment of the company’s cybersecurity program.
The company’s approach to managing risks, including cybersecurity risks, is embedded within the enterprise Operational Excellence (OE) Management System (OEMS). The OEMS provides a systematic process that enables the company to manage risk and implement safeguards and foster a culture of learning across different focus areas for Chevron’s business, including cybersecurity. The company’s Business Continuity Planning OE Process, a component of the OEMS, is designed to prepare Chevron to continue operations during an unplanned event or disruption, which aligns with its OE objective to prevent high-consequence security and cybersecurity incidents. Chevron works to identify critical business processes and dependent IT applications and document the processes for continuing operations without IT systems. Cross-functional teams also conduct regular multidisciplinary exercises, including an expansive cybersecurity exercise in 2023, to test and improve response plans.
The Board provides oversight of Chevron’s cybersecurity program, receives reports from management on cybersecurity risks in connection with Chevron’s operations and projects, and also reviews cybersecurity risks as part of the company’s broader annual ERM process. In support of the Board’s oversight of the company’s policies and processes with respect to risk management and the company’s major financial risk exposures, including cybersecurity, the Audit Committee meets with Chevron’s CISO and CIO at least twice a year to review cybersecurity risks and implications, including the results of
independent third-party assessments. The CISO and CIO present cybersecurity matters to the Board of Directors at least annually. The CISO and CIO also provide new Board members with a cybersecurity briefing as part of the onboarding process. In 2023, the Audit Committee hosted an external expert to discuss cybersecurity and digital risk management topics.
To date, the company has not experienced a cybersecurity threat or incident that has materially affected or is reasonably likely to materially affect the company, including its business strategy, results of operations or financial condition; however, the company has experienced and will continue to experience cyber incidents of varying degrees. Despite the cybersecurity measures that the company is taking to mitigate such risks, there can be no guarantee that such measures will be sufficient to protect the company’s systems, information, intellectual property and other assets from significant harm and that future cybersecurity incidents will not have a material adverse effect on the company or its results of operations or financial condition or cause reputational or other harm to the company. Refer to Item 1A. Risk Factors on pages 21 through 22 for further discussion of cyberattacks and the associated risks to Chevron’s business. Item 2. Properties
The location and character of the company’s crude oil and natural gas properties and its refining, marketing, transportation, and chemicals facilities are described beginning on page 3 under Item 1. Business. Information required by Subpart 1200 of Regulation S-K (“Disclosure by Registrants Engaged in Oil and Gas Producing Activities”) is also contained in Item 1 and in Tables I through VII on pages 102 through 114 and Note 18 Properties, Plant and Equipment. Item 3. Legal Proceedings
The following is a description of legal proceedings that involve governmental authorities as a party and the company reasonably believes would result in $1.0 million or more of monetary sanctions, exclusive of interest and costs, under federal, state and local laws that have been enacted or adopted regulating the discharge of materials into the environment or primarily for the purpose of protecting the environment.
As previously disclosed, Chevron received correspondence from California’s Bay Area Air Quality Management District (BAAQMD) seeking to resolve certain Notices of Violation (NOVs) related to alleged violations that occurred at Chevron’s refinery in Richmond, California, between 2019 and 2022. The parties negotiated a resolution of the NOVs, including additional NOVs from the first half of 2023, in a settlement effective February 12, 2024. Resolution of these alleged violations will result in the payment of a civil penalty of $20 million.
As previously disclosed, the California Department of Fish and Wildlife, Office of Spill Prevention and Response (CDFW, OSPR) issued a Complaint - NOV to Chevron for alleged violations related to oil spills and impacted habitat and species occurring between January 2018 and May 2022 at different Chevron fields within Kern County, California. Chevron is negotiating a potential resolution of the NOVs with CDFW, OSPR. Resolution of the alleged violations will result in the payment of a civil penalty of $1.0 million or more.
As previously disclosed, the California Department of Conservation, California Geologic Energy Management Division (CalGEM) (previously known as the Division of Oil, Gas and Geothermal Resources) promulgated revised rules pursuant to the Underground Injection Control program that took effect April 1, 2019. Subsequent to that date, CalGEM issued NOVs and two orders to Chevron related to seeps that occurred in the Cymric Oil Field in Kern County, California. An October 2, 2019 CalGEM order seeks a civil penalty of approximately $2.7 million. Chevron has filed an appeal of this order. Chevron is currently in discussions with CalGEM regarding a settlement to resolve the order and all past and present seeps in the Cymric Field, which will increase the amount of penalty paid.
On March 17, 2022, the Texas Commission on Environmental Quality and Harris County, Texas filed a civil lawsuit alleging violations of the Texas Clean Air Act in connection with a fire at Chevron’s Pasadena, Texas refinery. The Pasadena refinery is currently negotiating a potential resolution that may result in the payment of a civil penalty of $1.0 million or more.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of February 9, 2024, stockholders of record numbered approximately 100,000. There are no restrictions on the company’s ability to pay dividends. The information on Chevron’s dividends are contained in the Quarterly Results tabulation. Chevron Corporation Issuer Purchases of Equity Securities for Quarter Ended December 31, 2023
| | | | | | | | | | | | | | |
| Total Number | Average | Total Number of Shares | Approximate Dollar Values of Shares that |
| of Shares | Price Paid | Purchased as Part of Publicly | May Yet be Purchased Under the Program |
| Period | Purchased * | per Share | Announced Program | (Billions of dollars)* |
| October 1 – October 31, 2023 | 9,396,099 | $162.01 | 9,396,099 | $65.7 |
| November 1 – November 30, 2023 | 6,818,060 | $144.50 | 6,818,060 | $64.7 |
| December 1 – December 31, 2023 | 6,180,512 | $147.74 | 6,180,512 | $63.8 |
| Total October 1 – December 31, 2023 | 22,394,671 | $152.74 | 22,394,671 | |
Item 6. [Reserved]
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The index to Management’s Discussion and Analysis of Financial Condition and Results of Operations is presented in the Financial Table of Contents. Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures The company’s management has evaluated, with the participation of the Chief Executive Officer and the Chief Financial Officer, the effectiveness of the company’s disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (Exchange Act)) as of the end of the period covered by this report. Based on this evaluation, management concluded that the company’s disclosure controls and procedures were effective as of December 31, 2023.
(b) Management’s Report on Internal Control Over Financial Reporting The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in the Exchange Act Rules 13a-15(f) and 15d-15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s internal control over financial reporting based on the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the results of this evaluation, the company’s management concluded that internal control over financial reporting was effective as of December 31, 2023.
The company excluded PDC Energy, Inc. (PDC) from our assessment of internal control over financial reporting as of December 31, 2023 because it was acquired by the company in a business combination during 2023. Total assets and total
revenues of PDC, a wholly-owned subsidiary, represent five percent and one percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2023.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2023, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein.
(c) Changes in Internal Control Over Financial Reporting During the quarter ended December 31, 2023, there were no changes in the company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the company’s internal control over financial reporting.
Item 9B. Other Information
Rule 10b5-1 Plan Elections
Michael K. Wirth, Chairman of the Board and Chief Executive Officer, entered into a pre-arranged stock trading plan on November 22, 2023. Mr. Wirth’s plan provides for the potential exercise of vested stock options and the associated sale of up to 404,500 shares of Chevron common stock between February 27, 2024 and January 28, 2025.
R. Hewitt Pate, Vice President and General Counsel, entered into a pre-arranged stock trading plan on November 27, 2023. Mr. Pate’s plan provides for the potential exercise of vested stock options and the associated sale of up to 250,742 shares of Chevron common stock between February 27, 2024 and February 7, 2025.
Alana K. Knowles, Vice President and Controller, entered into a pre-arranged stock trading plan on November 27, 2023. Ms. Knowles’ plan provides for the potential exercise of vested stock options and the associated sale of up to 17,534 shares of Chevron common stock between February 27, 2024 and November 30, 2024.
These trading plans were entered into during an open insider trading window and are each intended to satisfy the affirmative defense of Rule 10b5-1(c) under the Securities Exchange Act of 1934, as amended, and Chevron’s policies regarding transactions in Chevron securities.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Information about our Executive Officers at February 26, 2024
Members of the Corporation’s Executive Committee are the Executive Officers of the Corporation:
| | | | | | | | | | | |
| Name | Age | Current and Prior Positions (up to five years) | Primary Areas of Responsibility |
| Michael K. Wirth | 63 | Chairman of the Board and Chief Executive Officer (since Feb 2018)
| Chairman of the Board and
Chief Executive Officer |
Pierre R. Breber* | 59 | Vice President and Chief Financial Officer (since Apr 2019)
Executive Vice President, Downstream (Jan 2016 - Mar 2019) | Finance; Investor Relations |
| Mark A. Nelson | 60 | Vice Chairman (since Feb 2023) Executive Vice President, Strategy, Policy & Development (Oct 2022 - Sept 2023) Executive Vice President, Downstream (Mar 2019 - Sep 2022) Vice President, Midstream, Strategy and Policy (Feb 2018 - Feb 2019) | Strategy & Sustainability; Corporate Affairs; Corporate Business Development; Procurement/Supply Chain Management; Information Technology |
| A. Nigel Hearne | 56 | Executive Vice President, Oil, Products & Gas (since Oct 2022)
President, Chevron Eurasia Pacific Exploration & Production (July
2020 - Oct 2022)
President, Chevron Asia Pacific Exploration & Production (Jan 2019
- June 2020) | Upstream - Worldwide Exploration and Production;
Downstream - Worldwide Manufacturing, Marketing, Lubricants, and Chemicals;
Midstream - Worldwide; Asset Performance and Process Safety; Health, Safety and Environment |
Eimear P. Bonner* | 49 | Vice President (since Aug 2021) President and Chief Technology Officer, Chevron Technical Center (Feb 2021 - Dec 2023) General Director, Tengizchevroil (Dec 2018 - Jan 2021) | Finance; Investor Relations |
| Jeff B. Gustavson | 51 | Vice President, Lower Carbon Energies (since Aug 2021)
Vice President, Midcontinent (Feb 2018 - July 2021) | Lower Carbon Solutions |
| Balaji Krishnamurthy | 47 | Vice President (since Oct 2022); Vice President, Chevron Technical Center (since Jan 2024) Vice President, Strategy & Sustainability (Oct 2022 - Sept 2023) President, Chevron Canada Limited (June 2021 - Sept 2022) General Manager, Corporate Transformation and Integration Management (Dec 2019 - May 2021) Deputy Managing Director, Eurasia Business Unit (June 2018 - Dec 2019) | Subsurface; Global Reserves; Wells; Facilities Designs and Solutions; Capital Projects; Downstream Technology |
| Rhonda J. Morris | 58 | Vice President and Chief Human Resources Officer (since Feb 2019) | Human Resources; Diversity and Inclusion |
| | | |
| R. Hewitt Pate | 61 | Vice President and General Counsel (since Aug 2009) | Law, Governance and Compliance |
* Effective March 1, 2024, Ms. Bonner will assume the position of Vice President and Chief Financial Officer. |
The information about directors required by Item 401(a), (d), (e) and (f) of Regulation S-K and contained under the heading “Election of Directors” in the Notice of the 2024 Annual Meeting of Stockholders and 2024 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act in connection with the company’s 2024 Annual Meeting (the 2024 Proxy Statement), is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 405 of Regulation S-K and contained under the heading “Delinquent Section 16(a) Reports” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 406 of Regulation S-K and contained under the heading “Business Conduct and Ethics Code” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(d)(4) and (5) of Regulation S-K and contained under the heading “Corporate Governance — Board Committees” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 408(b) of Regulation S-K and contained under the heading “Insider Trading and Prohibited Transactions Involving Chevron Securities” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
Item 11. Executive Compensation
The information required by Item 402 of Regulation S-K and contained under the headings “Executive Compensation,” “Director Compensation” and “CEO Pay Ratio” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(e)(5) of Regulation S-K and contained under the heading “Corporate Governance — Management Compensation Committee Report” in the 2024 Proxy Statement is incorporated herein by reference into this Annual Report on Form 10-K. Pursuant to the rules and regulations of the SEC under the Exchange Act, the information under such caption incorporated by reference from the 2024 Proxy Statement shall not be deemed to be “soliciting material,” or to be “filed” with the Commission, or subject to Regulation 14A or 14C or the liabilities of Section 18 of the Exchange Act, nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by Item 403 of Regulation S-K and contained under the heading “Stock Ownership Information — Security Ownership of Certain Beneficial Owners and Management” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 201(d) of Regulation S-K and contained under the heading “Equity Compensation Plan Information” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by Item 404 of Regulation S-K and contained under the heading “Related Person Transactions” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(a) of Regulation S-K and contained under the heading “Corporate Governance — Director Independence” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
Item 14. Principal Accountant Fees and Services
The information required by Item 9(e) of Schedule 14A and contained under the heading “Board Proposal to Ratify PricewaterhouseCoopers LLP as the Independent Registered Public Accounting Firm for 2024” in the 2024 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
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| Management's Discussion and Analysis of Financial Condition and Results of Operations | |
Key Financial Results
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| Millions of dollars, except per-share amounts | 2023 | | 2022 | | 2021 |
| Net Income (Loss) Attributable to Chevron Corporation | $ | 21,369 | | | $ | 35,465 | | | $ | 15,625 | |
| Per Share Amounts: | | | | | |
| Net Income (Loss) Attributable to Chevron Corporation | | | | | |
| – Basic | $ | 11.41 | | | $ | 18.36 | | | $ | 8.15 | |
| – Diluted | $ | 11.36 | | | $ | 18.28 | | | $ | 8.14 | |
| Dividends | $ | 6.04 | | | $ | 5.68 | | | $ | 5.31 | |
| Sales and Other Operating Revenues | $ | 196,913 | | | $ | 235,717 | | | $ | 155,606 | |
| Return on: | | | | | |
| Capital Employed | 11.9 | % | | 20.3 | % | | 9.4 | % |
| Stockholders’ Equity | 13.3 | % | | 23.8 | % | | 11.5 | % |
| Earnings by Major Operating Area |
| Millions of dollars | 2023 | | 2022 | | 2021 |
| Upstream | | | | | |
| United States | $ | 4,148 | | | $ | 12,621 | | | $ | 7,319 | |
| International | 13,290 | | | 17,663 | | | 8,499 | |
| Total Upstream | 17,438 | | | 30,284 | | | 15,818 | |
| Downstream | | | | | |
| United States | 3,904 | | | 5,394 | | | 2,389 | |
| International | 2,233 | | | 2,761 | | | 525 | |
| Total Downstream | 6,137 | | | 8,155 | | | 2,914 | |
| All Other | (2,206) | | | (2,974) | | | (3,107) | |
Net Income (Loss) Attributable to Chevron Corporation1,2 | $ | 21,369 | | | $ | 35,465 | | | $ | 15,625 | |
1 Includes foreign currency effects: | $ | (224) | | | $ | 669 | | | $ | 306 | |
2 Income net of tax, also referred to as “earnings” in the discussions that follow. |
Refer to the Results of Operations section for a discussion of financial results by major operating area for the three years ended December 31, 2023. Throughout the document, certain totals and percentages may not sum to their component parts due to rounding. Business Environment and Outlook
Chevron Corporation is a global energy company with direct and indirect subsidiaries and affiliates that conduct substantial business activities in the following countries: Angola, Argentina, Australia, Bangladesh, Brazil, Canada, China, Egypt, Equatorial Guinea, Israel, Kazakhstan, Mexico, Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait, the Philippines, Republic of Congo, Singapore, South Korea, Thailand, the United Kingdom, the United States and Venezuela.
The company’s objective is to safely deliver higher returns, lower carbon and superior shareholder value in any business environment. Earnings of the company depend mostly on the profitability of its upstream business segment. The most significant factor affecting the results of operations for the upstream segment is the price of crude oil, which is determined in global markets outside of the company’s control. In the company’s downstream business, crude oil is the largest cost component of refined products. Periods of sustained lower commodity prices could result in the impairment or write-off of specific assets in future periods and cause the company to adjust operating expenses, including employee reductions, and capital expenditures, along with other measures intended to improve financial performance.
Governments, companies, communities and other stakeholders are increasingly supporting efforts to address climate change. International initiatives and national, regional and state legislation and regulations that aim to directly or indirectly reduce GHG emissions are in various stages of design, adoption and implementation. These policies and programs, some of which support the global net zero emissions ambitions of the Paris Agreement, can change the amount of energy consumed, the rate of energy-demand growth, the energy mix and the relative economics of one fuel versus another. Implementation of jurisdiction-specific policies and programs can be dependent on, and can affect the pace of, technological advancements, the granting of necessary permits by governing authorities, the availability of cost-effective, verifiable carbon credits, the availability of suppliers that can meet sustainability and other standards, evolving regulatory or other requirements affecting ESG standards or other disclosures and evolving standards for tracking, reporting, marketing and advertising relating to emissions and emission reductions and removals.
Some of these policies and programs include renewable and low carbon fuel standards, such as the Renewable Fuel Standard program in the U.S. and California’s Low Carbon Fuel Standard; programs that price GHG emissions, including
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| Management's Discussion and Analysis of Financial Condition and Results of Operations | |
California’s Cap-and-Trade Program; performance standards, including methane-specific regulations such as the U.S. EPA’s Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources; and measures that provide various incentives for lower carbon activities, including carbon capture and storage and the production of hydrogen and sustainable aviation fuel, such as the U.S. Inflation Reduction Act. Requirements for these and other similar policies and programs are complex, ever changing, program specific and encompass: (1) the blending of renewable fuels into transportation fuels; (2) the purchasing, selling, utilizing and retiring of allowances and carbon credits; and (3) other emissions reduction measures including efficiency improvements and capturing GHG emissions. These compliance policies and programs have had and may continue to have negative impacts on the company now and in the future including, but not limited to, the displacement of hydrocarbon and other products and/or the impairment of assets. These policies have also enabled opportunities for Chevron in its lower carbon businesses. For example, the acquisition of Renewable Energy Group, Inc. (REG) in 2022 grew the company’s renewable fuels production capacity and increased the company’s carbon credit generation activities. Although we expect the company’s costs to comply with these policies and programs to continue to increase, these costs currently do not have a material impact on the company’s financial condition or results of operations.
Significant uncertainty remains as to the pace and extent to which the transition to a lower carbon future will progress, which is dependent, in part, on further advancements and changes in policy, technology, and customer and consumer preferences. The level of expenditure required to comply with new or potential climate change-related laws and regulations and the amount of additional investments needed in new or existing technology or facilities, such as carbon capture and storage, is difficult to predict with certainty and is expected to vary depending on the actual laws and regulations enacted, available technology options, customer and consumer preferences, the company’s activities and market conditions. As discussed below, in 2021, the company announced planned capital spend of approximately $10 billion through 2028 in lower carbon investments. Although the future is uncertain, many published outlooks conclude that fossil fuels will remain a significant part of an energy system that increasingly incorporates lower carbon sources of supply for many years to come.
Chevron supports the Paris Agreement’s global approach to governments addressing climate change and continues to take actions to help lower the carbon intensity of its operations while continuing to meet the demand for energy. Chevron believes that broad, market-based mechanisms are the most efficient approach to addressing GHG emission reductions. Chevron integrates climate change-related issues and the regulatory and other responses to these issues into its strategy and planning, capital investment reviews and risk management tools and processes, where it believes they are applicable. They are also factored into the company’s long-range supply, demand and energy price forecasts. These forecasts reflect estimates of long-range effects from climate change-related policy actions, such as electric vehicle and renewable fuel penetration, energy efficiency standards and demand response to oil and natural gas prices.
The company will continue to develop oil and gas resources to meet customers’ and consumers’ demand for energy. At the same time, Chevron believes that the future of energy is lower carbon. The company will continue to maintain flexibility in its portfolio to be responsive to changes in policy, technology and customer and consumer preferences. Chevron aims to grow its oil and gas business, lower the carbon intensity of its operations and grow lower carbon businesses in renewable fuels, carbon capture and offsets, hydrogen and other emerging technologies. To grow its lower carbon businesses, Chevron plans to target sectors of the economy where emissions are harder to abate or that cannot be easily electrified, while leveraging the company’s capabilities, assets, partnerships and customer relationships. The company’s oil and gas business may increase or decrease depending upon regulatory or market forces, among other factors.
In 2021, Chevron announced the following aspirations and targets that are aligned with its lower carbon strategy:
2050 Net Zero Upstream Aspiration Chevron aspires to achieve net zero for upstream production Scope 1 and 2 GHG emissions on an equity basis by 2050. The company believes accomplishing this aspiration depends on, among other things, partnerships with multiple stakeholders including customers, continuing progress on commercially viable technology, government policy, successful negotiations for carbon capture and storage and nature-based projects, availability and acceptability of cost-effective, verifiable offsets in the global market, and granting of necessary permits by governing authorities.
2028 Upstream Production GHG Intensity Targets These metrics include Scope 1, direct emissions, and Scope 2, indirect emissions associated with imported electricity and steam, and are net of emissions from exported electricity and steam. The 2028 GHG emissions intensity targets on an equity ownership basis include:
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•Oil production GHG intensity of 24 kilograms (kg) carbon dioxide equivalent per barrel of oil-equivalent (CO2e/boe),
•Gas production GHG intensity of 24 kg CO2e/boe,
•Methane intensity of 2 kg CO2e/boe, and
•Flaring GHG intensity of 3 kg CO2e/boe.
The company also targets no routine flaring by 2030. Chevron uses emissions intensity targets, which enable the company to assess, quantify and transparently communicate its own carbon performance in a standardized way.
2028 Portfolio Carbon Intensity Target The company also introduced a portfolio carbon intensity (PCI) metric, which is a measure of the carbon intensity across the full value chain of Chevron’s entire business. This metric encompasses the company’s upstream and downstream business and includes Scope 1 (direct emissions), Scope 2 (indirect emissions from imported electricity and steam), and certain Scope 3 (primarily emissions from use of sold products) emissions. The company’s PCI target is 71 grams (g) carbon dioxide equivalent (CO2e) per megajoule (MJ) by 2028.
Planned Lower-Carbon Capital Spend through 2028 In 2021, the company established planned capital spend of approximately $10 billion through 2028 to advance its lower carbon strategy, which includes approximately $2 billion to lower the carbon intensity of its oil and gas operations, and approximately $8 billion for lower carbon investments in renewable fuels, hydrogen and carbon capture and offsets. We anticipate additional capital spending as the company progresses toward its 2050 upstream production Scope 1 and 2 net zero aspiration and further grows its lower carbon business lines.
Since 2021, the company has spent $6.5 billion in lower carbon investments, including $2.9 billion associated with the acquisition of REG in 2022.
Chevron’s goals, targets and aspirations reflect Chevron’s current plans, and Chevron may change them for various reasons, including market conditions; changes in its portfolio; and financial, operational, regulatory, reputational, legal and other factors. Refer to “Risk Factors” in Part I, Item 1A, on pages 20 through 26 for further discussion of GHG regulation and climate change and the associated risks to Chevron’s business, including the risks impacting Chevron’s lower carbon strategy and its aspirations, targets and plans.
Income Taxes The effective tax rate for the company can change substantially during periods of significant earnings volatility. This is due to the mix effects that are impacted by both the absolute level of earnings or losses and whether they arise in higher or lower tax rate jurisdictions. As a result, a decline or increase in the effective income tax rate in one period may not be indicative of expected results in future periods. Additional information related to the company’s effective income tax rate is included in Note 17 Taxes to the Consolidated Financial Statements. The Inflation Reduction Act (IRA), enacted in the United States on August 16, 2022, imposes several new taxes that were effective in 2023, including a 15 percent minimum tax on book income and a one percent excise tax on stock repurchases. The IRA also implements various incentives for lower carbon activities, including carbon capture and storage and the production of hydrogen and sustainable aviation fuel, and extends the federal biodiesel mixture excise tax credit through December 31, 2024. The IRA has not had a material impact on our results of operations.
In December 2021, the Organization for Economic Co-operation and Development (OECD) issued model rules for a new 15 percent global minimum tax (Pillar Two), and various jurisdictions in which the company operates enacted or are in the process of enacting Pillar Two legislation. Certain aspects of the tax under the Pillar Two framework will be effective beginning in 2024 in some jurisdictions and in 2025 (or later) in others. Although we do not currently expect that Pillar Two will have a material impact on our results of operations, we are continuing to evaluate the impact of legislative adoption by individual countries.
Supply Chain and Inflation Impacts The company is actively managing its contracting, procurement and supply chain activities to effectively manage costs and facilitate supply chain resiliency and continuity in support of the company’s operational goals. Third party costs for capital and operating expenses can be subject to external factors beyond the company’s control including, but not limited to: severe weather or civil unrest, delays in construction, global and local supply chain distribution issues, inflation, tariffs or other taxes imposed on goods or services, and market-based prices charged by the industry’s material and service providers. Chevron utilizes contracts with various pricing mechanisms, which may result in a lag before the company’s costs reflect changes in market trends.
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While macroeconomic inflation is easing, trends in the costs of goods and services vary by spend category. The labor market remains tight, and suppliers are passing along wage rate increases for labor intensive operations. Chevron has applied inflation mitigation strategies in an effort to temper these cost increases, including fixed price and index-based contracts. Lead times for key capital equipment remain long. Chevron has addressed lead times by partnering with suppliers on demand planning, volume commitments, standardization and scope optimization. Raw material prices have declined, leading to a lower cost for drilling pipe, chemicals and construction materials. Onshore drilling activity in the United States declined; however, availability of specialized offshore drilling rigs, supply vessels and equipment to perform onshore hydraulic fracturing remains under pressure.
Acquisition and Disposition of Assets The company continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value and to acquire assets or operations complementary to its asset base to help augment the company’s financial performance and value growth. Asset dispositions and restructurings may result in significant gains or losses in future periods. In addition, some assets are sold along with their related liabilities, such as abandonment and decommissioning obligations. In certain instances, such transferred obligations have, and may in the future, revert to the company and result in losses that could be significant. In fourth quarter 2023, the company recognized an after-tax loss of $1.9 billion related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S. Gulf of Mexico, as companies that purchased these assets have filed for protection under Chapter 11 of the U.S. Bankruptcy Code, and the company believes it is now probable and estimable that a portion of these obligations will revert to the company. The cash outlays for these abandonment and decommissioning obligations are expected to take place over the next decade.
Other Impacts The company closely monitors developments in the financial and credit markets, the level of worldwide economic activity, and the implications for the company of movements in prices for crude oil and natural gas. Management takes these developments into account in the conduct of daily operations and for business planning.
Earnings trends for the company’s major business areas are described as follows:
Upstream Earnings for the upstream segment are closely aligned with industry prices for crude oil and natural gas. Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry production and inventory levels, technology advancements, production quotas or other actions imposed by OPEC+ countries, actions of regulators, weather-related damage and disruptions, competing fuel prices, natural and human causes beyond the company’s control, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. Any of these factors could also inhibit the company’s production capacity in an affected region. The company closely monitors developments in the countries in which it operates and holds investments and seeks to manage risks in operating its facilities and businesses.
The longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to efficiently find, acquire and produce crude oil and natural gas, changes in fiscal terms of contracts, the pace of energy transition, and changes in tax, environmental and other applicable laws and regulations.
The company has begun to experience regulatory challenges and delays in obtaining permits to conduct operations in certain jurisdictions. These challenges have, and may continue to, impact the company’s plans for future investments. For example, during fourth quarter 2023, the company impaired a portion of its U.S. upstream assets, primarily in California, due to continuing regulatory challenges in the state that have resulted in lower anticipated future investment levels in its business plans. The company expects to continue operating the impacted assets for many years to come.
Chevron has interests in Venezuelan assets operated by independent affiliates. Chevron has been conducting limited activities in Venezuela consistent with the authorization provided pursuant to general licenses issued by the United States government. In fourth quarter 2022, Chevron received General License 41 from the United States government, enabling the company to resume activity in Venezuela subject to certain limitations, and the company continues such activities under this General License. The financial results for Chevron’s business in Venezuela are being recorded as non-equity investments since 2020, where income is only recognized when cash is received and production and reserves are not included in the company's results. Crude oil liftings in Venezuela started in first quarter 2023, which have positively impacted the company’s 2023 results, but future results remain uncertain.
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Governments (including Russia) have imposed and may impose additional sanctions and other trade laws, restrictions and regulations that could lead to disruption in our ability to produce, transport and/or export crude in the region around Russia. An adverse effect on the Caspian Pipeline Consortium (CPC) operations could have a negative impact on the Tengiz field in Kazakhstan and the company’s results of operations and financial position. The financial impacts of such risks, including presently imposed sanctions, are not currently material for the company; however, it remains uncertain how long these conditions may last or how severe they may become.
Chevron holds a 39.7 percent interest in the Leviathan field and a 25 percent interest in the Tamar gas field in Israel. In early October 2023, due to a war between Israel and Hamas, the Government of Israel directed the company to shut down production at the Tamar gas field. Approximately one month later, the company resumed production, and the Tamar gas field is currently operational. The Leviathan gas field was not impacted by the war and is currently operational. The financial impacts of the Tamar shutdown and other operational impacts were not material for the company. However, given the ongoing conflict, the future impacts on the company’s results of operations and financial condition remain uncertain.
Commodity Prices The following chart shows the trend in benchmark prices for Brent crude oil, West Texas Intermediate (WTI) crude oil and U.S. Henry Hub natural gas. The Brent price averaged $83 per barrel for the full-year 2023, compared to $101 in 2022. As of mid-February 2024, the Brent price was $85 per barrel. The WTI price averaged $78 per barrel for the full-year 2023, compared to $95 in 2022. As of mid-February 2024, the WTI price was $77 per barrel. The majority of the company’s equity crude production is priced based on the Brent benchmark.
Crude prices were volatile in 2023 due to tapering of post-pandemic demand resurgence, OPEC+ supply cuts, Federal Reserve interest rate action, and the proliferation of geopolitical conflict. The company’s average realization for U.S. crude oil and NGLs in 2023 was $59 per barrel, down 23 percent from 2022. The company’s average realization for international crude oil and NGLs in 2023 was $72 per barrel, down 21 percent from 2022.
In contrast to price movements in the global market for crude oil, prices for natural gas are also impacted by regional supply and demand and infrastructure conditions in local markets. In the United States, prices at Henry Hub averaged $2.56 per thousand cubic feet (MCF) during 2023, compared with $6.36 per MCF during 2022. High storage levels and strong production resulted in these lower prices. As of mid-February 2024, the Henry Hub spot price was $1.73 per MCF. (See page 45 for the company’s average natural gas realizations for the U.S.)
Outside the United States, prices for natural gas also depend on a wide range of supply, demand and regulatory circumstances. The company’s long-term contract prices for liquefied natural gas (LNG) are typically linked to crude oil prices. Most of the equity LNG offtake from the operated Australian LNG projects is committed under binding long-term contracts, with some sold in the Asian spot LNG market. International natural gas realizations averaged $7.69 per MCF during 2023, compared with $9.75 per MCF during 2022, mainly due to lower LNG prices.
Production The company’s worldwide net oil-equivalent production in 2023 was 3.1 million barrels per day, 4 percent higher than in 2022 primarily due to the acquisition of PDC Energy, Inc. (PDC) and growth in the Permian Basin. About 26 percent of the company’s net oil-equivalent production in 2023 occurred in OPEC+ member countries of Angola, Equatorial Guinea, Kazakhstan, Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait and Republic of Congo.
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The company estimates its net oil-equivalent production in 2024 to increase four to seven percent over 2023, assuming a Brent crude oil price of $80 per barrel and including expected asset sales. This estimate is subject to many factors and uncertainties, including quotas or other actions that may be imposed by OPEC+; price effects on entitlement volumes; changes in fiscal terms or restrictions on the scope of company operations; delays in construction; reservoir performance; greater-than-expected declines in production from mature fields; start-up or ramp-up of projects; acquisition and divestment of assets; fluctuations in demand for crude oil and natural gas in various markets; weather conditions that may shut in production; civil unrest; changing geopolitics; delays in completion of maintenance turnarounds; storage constraints or economic conditions that could lead to shut-in production; or other disruptions to operations. The outlook for future production levels is also affected by the size and number of economic investment opportunities and the time lag between initial exploration and the beginning of production. The company has increased its investment emphasis on short-cycle projects.
Proved Reserves Net proved reserves for consolidated companies and affiliated companies totaled 11.1 billion barrels of oil-equivalent at year-end 2023, a slight decrease from year-end 2022. The reserve replacement ratio in 2023 was 86 percent. The 5 and 10 year reserve replacement ratios were 82 percent and 99 percent, respectively. Refer to Table V for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2021 and each year-end from 2021 through 2023, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2023. Refer to the “Results of Operations” section on pages 41 and 42 for additional discussion of the company’s upstream business.
Downstream Earnings for the downstream segment are closely tied to margins on the refining, manufacturing and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil, fuel and lubricant additives, petrochemicals and renewable fuels. Industry margins are sometimes volatile and can be affected by the global and regional supply-and-demand balance for refined products and petrochemicals, and by changes in the price of crude oil, other refinery and petrochemical feedstocks, and natural gas. Industry margins can also be influenced by inventory levels, geopolitical events, costs of materials and services, refinery or chemical plant capacity utilization, maintenance programs, and disruptions at refineries or chemical plants resulting from unplanned outages due to severe weather, fires or other operational events.
Other factors affecting profitability for downstream operations include the reliability and efficiency of the company’s refining, marketing and petrochemical assets, the effectiveness of its crude oil and product supply functions, and the volatility of tanker-charter rates for the company’s shipping operations, which are driven by the industry’s demand for crude oil and product tankers. Other factors beyond the company’s control include the general level of inflation and energy
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| Management's Discussion and Analysis of Financial Condition and Results of Operations | |
costs to operate the company’s refining, marketing and petrochemical assets, and changes in tax, environmental, and other applicable laws and regulations.
The company’s most significant marketing areas are the West Coast and Gulf Coast of the United States and Asia Pacific. Chevron operates or has significant ownership interests in refineries in each of these areas. Additionally, the company has a growing presence in renewable fuels in the United States after acquiring REG in 2022.
Refer to the “Results of Operations” section on page 42 for additional discussion of the company’s downstream operations.
All Other consists of worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities and technology companies.
Noteworthy Developments
Key noteworthy developments and other events during 2023 and early 2024 included the following:
Angola Received approvals to extend Block 0 concession through 2050.
Australia Achieved first natural gas production from the Gorgon Stage 2 development, supporting long-term energy supply in the Asia-Pacific region.
Israel Reached final investment decision to construct a third gathering pipeline that is expected to increase natural gas production capacity from approximately 1.2 to nearly 1.4 billion cubic feet per day from the Leviathan reservoir.
Japan Announced agreements to conduct pilot tests on advanced closed loop geothermal technology.
Kazakhstan Achieved mechanical completion on the Future Growth Project at the company’s 50 percent-owned affiliate, Tengizchevroil.
United States Announced an agreement to install new technologies on the company’s LNG vessels that are intended to reduce the carbon intensity of its LNG fleet operations.
United States Expanded the Bayou Bend carbon capture and sequestration hub on the U.S. Gulf Coast through an acquisition of nearly 100,000 acres, and became the operator of the hub.
United States Announced commercial collaboration to purchase next generation renewable feedstocks that are intended to benefit farmers and increase supplies to meet a growing demand for lower carbon renewable fuels.
United States Acquired 73 exploration blocks in Gulf of Mexico lease sale 259 and submitted winning bids on an additional 28 exploration blocks in Gulf of Mexico lease sale 261, subject to final government approval.
United States Achieved first oil at the Mad Dog 2 project in the Gulf of Mexico.
United States Started operations of a solar power project with a joint venture partner in New Mexico to provide lower carbon energy for the Permian Basin.
United States Converted the diesel hydrotreater at the El Segundo, California refinery to process either 100 percent renewable or traditional feedstocks.
United States Completed the acquisition of PDC, adding 275,000 net acres in the Denver-Julesburg (DJ) Basin and 25,000 net acres in the Permian Basin.
United States Completed the acquisition of a majority stake in ACES Delta, LLC, which is developing a green hydrogen production and storage hub in Utah.
United States Announced a definitive agreement to acquire Hess Corporation (Hess), which is expected to strengthen Chevron’s long-term performance by adding world-class assets and people.
Venezuela Received approval to extend licenses with PetroBoscan, S.A. and PetroIndependiente, S.A. through 2041.
Common Stock Dividends The 2023 annual dividend was $6.04 per share, making 2023 the 36th consecutive year that the company increased its annual per share dividend payout. In January 2024, the company’s Board of Directors increased its quarterly dividend by $0.12 per share, approximately eight percent, to $1.63 per share payable in March 2024.
Common Stock Repurchase Program The company repurchased $14.9 billion of its common stock in 2023 under its stock repurchase program. For more information on the common stock repurchase program, see Liquidity and Capital Resources.
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| Management's Discussion and Analysis of Financial Condition and Results of Operations | |
Results of Operations
The following section presents the results of operations and variances on an after-tax basis for the company’s business segments – Upstream and Downstream – as well as for “All Other.” Earnings are also presented for the U.S. and international geographic areas of the Upstream and Downstream business segments. Refer to Note 14 Operating Segments and Geographic Data for a discussion of the company’s “reportable segments.” This section should also be read in conjunction with the discussion in Business Environment and Outlook. Refer to the Selected Operating Data for a three-year comparison of production volumes, refined product sales volumes and refinery inputs. A discussion of variances between 2022 and 2021 can be found in the “Results of Operations” section on pages 39 through 40 of the company’s 2022 Annual Report on Form 10-K filed with the SEC on February 23, 2023.
U.S. Upstream
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| Unit * | 2023 | | 2022 | | 2021 |
| Earnings | $MM | $ | 4,148 | | | $ | 12,621 | | | $ | 7,319 | |
| Net Oil-Equivalent Production | MBOED | 1,349 | | | 1,181 | | 1,139 |
| Liquids Production | MBD | 997 | | 888 | | 858 |
| Natural Gas Production | MMCFD | 2,112 | | 1,758 | | 1,689 |
| Liquids Realization | $/BBL | $ | 59.19 | | | $ | 76.71 | | | $ | 56.06 | |
| Natural Gas Realization | $/MCF | $ | 1.67 | | | $ | 5.55 | | | $ | 3.11 | |
* MBD — thousands of barrels per day; MMCFD — millions of cubic feet per day; BBL — Barrel; MCF — thousands of cubic feet; MBOED — thousands of barrels of oil-equivalent per day. |
U.S. upstream earnings decreased by $8.5 billion primarily due to lower realizations of $6.2 billion, $1.9 billion in charges related to abandonment and decommissioning obligations for previously sold oil and gas producing assets in the U.S. Gulf of Mexico, and higher impairment charges of $1.8 billion, mainly from assets in California. Partially offsetting these items are higher sales volumes of $1.9 billion. Higher 2023 operating expenses of $460 million were more than offset by the absence of a 2022 early contract termination at Sabine Pass of $600 million.
Net oil-equivalent production was up 168,000 barrels per day, or 14 percent, primarily due to the acquisition of PDC and growth in the Permian Basin.
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International Upstream
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| Unit (2) | 2023 | | 2022 | | 2021 |
Earnings (1) | $MM | $ | 13,290 | | | $ | 17,663 | | | $ | 8,499 | |
| Net Oil-Equivalent Production | MBOED | 1,771 | | | 1,818 | | 1,960 |
| Liquids Production | MBD | 833 | | 831 | | 956 |
| Natural Gas Production | MMCFD | 5,632 | | 5,919 | | 6,020 |
| Liquids Realization | $/BBL | $ | 71.70 | | | $ | 90.71 | | | $ | 64.53 | |
| Natural Gas Realization | $/MCF | $ | 7.69 | | | $ | 9.75 | | | $ | 5.93 | |
(1) Includes foreign currency effects: | | $ | 376 | | | $ | 816 | | | $ | 302 | |
(2) MBD — thousands of barrels per day; MMCFD — millions of cubic feet per day; BBL — Barrel; MCF — thousands of cubic feet; MBOED — thousands of barrels of oil-equivalent per day. |
International upstream earnings decreased by $4.4 billion primarily due to lower realizations of $7.2 billion and lower sales volumes of $280 million, partially offset by lower depreciation expense of $1.4 billion mainly due to absence of write-off and impairment charges in 2022, lower operating expenses of $820 million and a favorable one-time tax benefit in Nigeria of $560 million. Foreign currency effects had an unfavorable impact on earnings of $440 million between periods.
Net oil-equivalent production was down 47,000 barrels per day, or 3 percent. The decrease was primarily due to normal field declines, shutdowns and lower production following expiration of the Erawan concession in Thailand.
U.S. Downstream
| | | | | | | | | | | | | | | | | | | | |
| Unit * | 2023 | | 2022 | | 2021 |
| Earnings | $MM | $ | 3,904 | | | $ | 5,394 | | | $ | 2,389 | |
| Refinery Crude Oil Inputs | MBD | 934 | | 866 | | 903 |
| Refined Product Sales | MBD | 1,287 | | 1,228 | | 1,139 |
* MBD — thousands of barrels per day. |
U.S. downstream earnings decreased by $1.5 billion primarily due to lower margins on refined product sales of $660 million, higher operating expenses of $490 million and lower earnings from the 50 percent-owned CPChem of $220 million.
Refinery crude oil input was up 68,000 barrels per day, or 8 percent, primarily due to a smaller impact from planned turnaround activity at the Richmond, California refinery and higher crude oil processed in place of other feedstocks at the Pascagoula, Mississippi refinery. These increases were partially offset by planned turnaround impacts at the El Segundo, California refinery in first quarter 2023.
Refined product sales were up 59,000 barrels per day, or 5 percent, primarily due to higher jet fuel demand and higher renewable fuel sales following the REG acquisition.
International Downstream
| | | | | | | | | | | | | | | | | | | | |
| Unit (2) | 2023 | | 2022 | | 2021 |
Earnings (1) | $MM | $ | 2,233 | | | $ | 2,761 | | | $ | 525 | |
| Refinery Crude Oil Inputs | MBD | 626 | | 639 | | 576 |
| Refined Product Sales | MBD | 1,445 | | 1,386 | | 1,315 |
(1) Includes foreign currency effects: | | $ | (12) | | | $ | 235 | | | $ | 185 | |
(2) MBD — thousands of barrels per day. | | | | | | |
International downstream earnings decreased by $528 million primarily due to higher operating expenses of $360 million and an unfavorable swing in foreign currency effects of $247 million between periods.
Refinery crude oil input was down 13,000 barrels per day, or 2 percent, compared to the year-ago period.
Refined product sales were up 59,000 barrels per day, or 4 percent, primarily due to higher demand for jet fuel and gasoline.
| | | | | | | | |
| Management's Discussion and Analysis of Financial Condition and Results of Operations | |
All Other
| | | | | | | | | | | | | | | | | | | | | | | |
| Unit | 2023 | | | 2022 | | 2021 |
Net charges* | $MM | $ | (2,206) | | | | $ | (2,974) | | | $ | (3,107) | |
*Includes foreign currency effects: | | $ | (588) | | | | $ | (382) | | | $ | (181) | |
All Other consists of worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology companies.
Net charges decreased by $768 million primarily due to lower employee benefit costs and higher interest income, partially offset by an unfavorable swing of $206 million in foreign currency effects.
Consolidated Statement of Income
Comparative amounts for certain income statement categories are shown below. A discussion of variances between 2022 and 2021 can be found in the “Consolidated Statement of Income” section on pages 41 and 42 of the company’s 2022 Annual Report on Form 10-K.
| | | | | | | | | | | | | | | | | | | | |
| Millions of dollars | 2023 | | | 2022 | | 2021 | |
| Sales and other operating revenues | $ | 196,913 | | | | $ | 235,717 | | | $ | 155,606 | |
Sales and other operating revenues decreased in 2023 mainly due to lower commodity prices, partially offset by higher refined product sales volumes.
| | | | | | | | | | | | | | | | | | | | |
| Millions of dollars | 2023 | | | 2022 | | 2021 | |
| Income (loss) from equity affiliates | $ | 5,131 | | | | $ | 8,585 | | | $ | 5,657 | |
Income from equity affiliates decreased in 2023 mainly due to lower upstream-related earnings from Tengizchevroil in Kazakhstan and Angola LNG and lower downstream-related earnings from GS Caltex in Korea and CPChem. Refer to Note 15 Investments and Advances for a discussion of Chevron’s investments in affiliated companies. | | | | | | | | | | | | | | | | | | | | |
| Millions of dollars | 2023 | | | 2022 | | 2021 | |
| Other income (loss) | $ | (1,095) | | | | $ | 1,950 | | | $ | 1,202 | |
Other income decreased in 2023 mainly due to charges related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S. Gulf of Mexico, an unfavorable swing in foreign currency effects and lower gains on asset sales, partially offset by income from Venezuela non-equity investments and higher interest income.
| | | | | | | | | | | | | | | | | | | | |
| Millions of dollars | 2023 | | | 2022 | | 2021 | |
| Purchased crude oil and products | $ | 119,196 | | | | $ | 145,416 | | | $ | 92,249 | |
Crude oil and product purchases decreased in 2023 primarily due to lower commodity prices.
| | | | | | | | | | | | | | | | | | | | |
| Millions of dollars | 2023 | | | 2022 | | 2021 | |
| Operating, selling, general and administrative expenses | $ | 29,028 | | | | $ | 29,026 | | | $ | 24,740 | |
Operating, selling, general and administrative expenses were relatively unchanged compared to last year. Higher transportation and materials and supplies expenses were offset by lower employee benefit costs and the absence of early contract termination fees at Sabine Pass in 2022.
| | | | | | | | | | | | | | | | | | | | |
| Millions of dollars | 2023 | | | 2022 | | 2021 | |
| Exploration expense | $ | 914 | | | | $ | 974 | | | $ | 549 | |
Exploration expenses in 2023 decreased primarily due to lower charges for well write-offs.
| | | | | | | | | | | | | | | | | | | | |
| Millions of dollars | 2023 | | | 2022 | | 2021 | |
| Depreciation, depletion and amortization | $ | 17,326 | | | | $ | 16,319 | | | $ | 17,925 | |
Depreciation, depletion and amortization expenses increased in 2023 primarily due to higher impairment charges and higher production, partially offset by lower rates.
| | | | | | | | |
| Management's Discussion and Analysis of Financial Condition and Results of Operations | |
| | | | | | | | | | | | | | | | | | | | |
| Millions of dollars | 2023 | | | 2022 | | 2021 | |
| Taxes other than on income | $ | 4,220 | | | | $ | 4,032 | | | $ | 3,963 | |
Taxes other than on income increased in 2023 primarily due to higher excise taxes.
| | | | | | | | | | | | | | | | | | | | |
| Millions of dollars | 2023 | | | 2022 | | 2021 | |
| Interest and debt expense | $ | 469 | | | | $ | 516 | | | $ | 712 | |
Interest and debt expenses decreased in 2023 mainly due to higher capitalized interest and lower debt balances.
| | | | | | | | | | | | | | | | | | | | |
| Millions of dollars | 2023 | | | 2022 | | 2021 | |
| Other components of net periodic benefit costs | $ | 212 | | | | $ | 295 | | | $ | 688 | |
Other components of net periodic benefit costs decreased in 2023 primarily due to lower pension settlement costs as fewer lump-sum pension distributions were made in the current year, partially offset by the impact of higher interest rates.
| | | | | | | | | | | | | | | | | | | | |
| Millions of dollars | 2023 | | | 2022 | | 2021 | |
| Income tax expense (benefit) | $ | 8,173 | | | | $ | 14,066 | | | $ | 5,950 | |
The decrease in income tax expense in 2023 of $5.9 billion is due to the decrease in total income before tax for the company of $20.1 billion. The decrease in income before taxes for the company is primarily the result of lower upstream realizations and downstream margins.
U.S. income before tax decreased from $21.0 billion in 2022 to $8.6 billion in 2023. This $12.4 billion decrease in income was primarily driven by lower upstream realizations and downstream margins, charges related to abandonment and decommissioning obligations, and higher impairment charges, partially offset by higher sales volumes. The decrease in income had a direct impact on the company’s U.S. income tax resulting in a decrease to tax expense of $2.7 billion between year-over-year periods, from $4.5 billion in 2022 to $1.8 billion in 2023.
International income before tax decreased from $28.7 billion in 2022 to $21.0 billion in 2023. This $7.7 billion decrease in income was primarily driven by lower upstream realizations, partly offset by the absence of a 2022 write-off and impairment charges. The decrease in income primarily drove the $3.2 billion decrease in international income tax expense between year-over-year periods, from $9.6 billion in 2022 to $6.4 billion in 2023.
Refer also to the discussion of the effective income tax rate in Note 17 Taxes.
| | | | | | | | |
| Management's Discussion and Analysis of Financial Condition and Results of Operations | |
Selected Operating Data1,2
| | | | | | | | | | | | | | | | | | | | | |
| Unit | 2023 | | 2022 | | 2021 | |
| U.S. Upstream | | | | | | | |
| Net Crude Oil and Natural Gas Liquids (NGLs) Production | MBD | 997 | | 888 | | 858 | |
Net Natural Gas Production3 | MMCFD | 2,112 | | 1,758 | | 1,689 | |
| Net Oil-Equivalent Production | MBOED | 1,349 | | 1,181 | | 1,139 | |
Sales of Natural Gas4 | MMCFD | 4,637 | | 4,354 | | 3,986 | |
| Sales of NGLs | MBD | 354 | | 276 | | 201 | |
| Revenues from Net Production | | | | | | | |
| Crude | $/BBL | $ | 75.04 | | | $ | 92.41 | | | $ | 65.29 | | |
| NGLs | $/BBL | $ | 20.04 | | | $ | 33.80 | | | $ | 28.46 | | |
| Liquids (weighted average of Crude and NGLs) | $/BBL | $ | 59.19 | | | $ | 76.71 | | | $ | 56.06 | | |
| Natural Gas | $/MCF | $ | 1.67 | | | $ | 5.55 | | | $ | 3.11 | | |
| | | | | | | |
| International Upstream | | | | | | | |
Net Crude Oil and NGLs Production5 | MBD | 833 | | 831 | | 956 | |
Net Natural Gas Production3 | MMCFD | 5,632 | | 5,919 | | 6,020 | |
| | | | | | | |
Net Oil-Equivalent Production5 | MBOED | 1,771 | | 1,818 | | 1,960 | |
| Sales of Natural Gas | MMCFD | 6,025 | | 5,786 | | 5,178 | |
| Sales of NGLs | MBD | 94 | | 107 | | 84 | |
| Revenues from Liftings | | | | | | | |
| Crude | $/BBL | $ | 74.29 | | | $ | 93.73 | | | $ | 65.77 | | |
| NGLs | $/BBL | $ | 24.01 | | | $ | 37.56 | | | $ | 40.35 | | |
| Liquids (weighted average of Crude and NGLs) | $/BBL | $ | 71.70 | | | $ | 90.71 | | | $ | 64.53 | | |
| Natural Gas | $/MCF | $ | 7.69 | | | $ | 9.75 | | | $ | 5.93 | | |
| | | | | | | |
| Worldwide Upstream | | | | | | | |
Net Oil-Equivalent Production5 | | | | | | | |
| United States | MBOED | 1,349 | | 1,181 | | 1,139 | |
| International | MBOED | 1,771 | | 1,818 | | 1,960 | |
| Total | MBOED | 3,120 | | 2,999 | | 3,099 | |
| | | | | | | |
| U.S. Downstream | | | | | | | |
Gasoline Sales6 | MBD | 642 | | 639 | | 655 | |
| Other Refined Product Sales | MBD | 645 | | 589 | | 484 | |
| Total Refined Product Sales | MBD | 1,287 | | 1,228 | | 1,139 | |
Sales of Natural Gas4 | MMCFD | 32 | | 24 | | 21 | |
| Sales of NGLs | MBD | 22 | | 27 | | 29 | |
| Refinery Crude Oil Input | MBD | 934 | | 866 | | 903 | |
| | | | | | | |
| International Downstream | | | | | | | |
Gasoline Sales6 | MBD | 353 | | 336 | | 321 | |
| Other Refined Product Sales | MBD | 1,092 | | 1,050 | | 994 | |
Total Refined Product Sales7 | MBD | 1,445 | | 1,386 | | 1,315 | |
Sales of Natural Gas4 | MMCFD | 1 | | 3 | | — | |
| Sales of NGLs | MBD | 153 | | 127 | | 96 | |
| Refinery Crude Oil Input | MBD | 626 | | 639 | | 576 | |
1 Includes company share of equity affiliates. | |
2 MBD – thousands of barrels per day; MMCFD – millions of cubic feet per day; MBOED – thousands of barrels of oil-equivalents per day; Bbl – barrel; MCF – thousands of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil; MBOED - thousands of barrels of oil-equivalent per day. | |
3 Includes natural gas consumed in operations: | |
| United States | MMCFD | 64 | | | 53 | | | 44 | | |
| International | MMCFD | 532 | | | 517 | | | 548 | | |
4 Downstream sales of Natural Gas separately identified from Upstream. | | | | | | | |
5 Includes net production of synthetic oil: | | | | | | | |
| Canada | MBD | 51 | | | 45 | | | 55 | | |
6 Includes branded and unbranded gasoline. | | | | | | | |
7 Includes sales of affiliates: | MBD | 389 | | | 389 | | | 357 | | |
| |
| | | | | | | | |
| Management's Discussion and Analysis of Financial Condition and Results of Operations | |
Liquidity and Capital Resources
Sources and Uses of Cash The strength of the company’s balance sheet enables it to fund any timing differences throughout the year between cash inflows and outflows.
Cash, Cash Equivalents and Marketable Securities Total balances were $8.2 billion and $17.9 billion at December 31, 2023 and 2022, respectively. The company holds its cash with a diverse group of major financial institutions and has processes and safeguards in place designed to manage its cash balances and mitigate the risk of loss. Cash provided by operating activities in 2023 was $35.6 billion, compared to $49.6 billion in 2022, primarily due to lower upstream realizations and refining margins. Cash provided by operating activities was net of contributions to employee pension plans of approximately $1.1 billion in 2023 and $1.3 billion in 2022. Capital expenditures totaled $15.8 billion in 2023 compared to $12.0 billion in 2022. Proceeds and deposits related to asset sales and return of investments totaled $669 million in 2023 compared to $2.6 billion in 2022. Cash flow from financing activities includes proceeds from shares issued for stock options of $261 million in 2023, compared with a higher than typical $5.8 billion in 2022 when a large number of stock options were exercised.
Restricted cash of $1.1 billion and $1.4 billion at December 31, 2023 and 2022, respectively, was held in cash and short-term marketable securities and recorded as “Deferred charges and other assets” and “Prepaid expenses and other current assets” on the Consolidated Balance Sheet. These amounts are generally associated with upstream decommissioning activities, tax payments and funds held in escrow for tax-deferred exchanges.
Dividends Dividends paid to common stockholders were $11.3 billion in 2023 and $11.0 billion in 2022.
Debt and Finance Lease Liabilities Total debt and finance lease liabilities were $20.8 billion at December 31, 2023, down from $23.3 billion at year-end 2022.
The $2.5 billion decrease in total debt and finance lease liabilities during 2023 was primarily due to the repayment of long-term notes that matured during the year. The company’s debt and finance lease liabilities due within one year, consisting primarily of the current portion of long-term debt and redeemable long-term obligations, totaled $5.1 billion at December 31, 2023, compared with $6.0 billion at year-end 2022. Of these amounts, $4.5 billion and $4.1 billion were reclassified to long-term debt at the end of 2023 and 2022, respectively. At year-end 2023, settlement of these obligations was not expected to require the use of working capital in 2024, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.
During third quarter 2023, the company assumed $1.5 billion of debt in conjunction with the PDC acquisition, including balances outstanding under the revolving credit facility, PDC’s 6.125% notes due 2024 (2024 notes) and PDC’s 5.75% notes due 2026 (2026 notes). The outstanding balances under the revolving credit facility and the 2024 notes were repaid during third quarter 2023. The company also irrevocably deposited sufficient U.S. Treasury securities with U.S. Bank Trust Company, N.A., as trustee, to fund the redemption of the 2026 notes, resulting in the indenture being satisfied and discharged.
The company has access to a commercial paper program as a financing source for working capital or other short-term needs. The company had no commercial paper outstanding as of December 31, 2023.
| | | | | | | | |
| Management's Discussion and Analysis of Financial Condition and Results of Operations | |
The major debt rating agencies routinely evaluate the company’s debt, and the company’s cost of borrowing can increase or decrease depending on these debt ratings. The company has outstanding public bonds issued by Chevron Corporation, Chevron U.S.A. Inc. (CUSA), Noble Energy, Inc. (Noble), and Texaco Capital Inc. Most of these securities are the obligations of, or guaranteed by, Chevron Corporation and are rated AA- by Standard and Poor’s Corporation and Aa2 by Moody’s Investors Service. The company’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and P-1 by Moody’s. All of these ratings denote high-quality, investment-grade securities.
The company’s future debt level is dependent primarily on results of operations, cash that may be generated from asset dispositions, the capital program, lending commitments to affiliates and shareholder distributions. Based on its high-quality debt ratings, the company believes that it has substantial borrowing capacity to meet unanticipated cash requirements. During extended periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, the company has the ability to modify its capital spending plans and discontinue or curtail the stock repurchase program. This provides the flexibility to continue paying the common stock dividend and remain committed to retaining the company’s high-quality debt ratings.
Committed Credit Facilities Information related to committed credit facilities is included in Note 19 Short-Term Debt. Summarized Financial Information for Guarantee of Securities of Subsidiaries CUSA issued bonds that are fully and unconditionally guaranteed on an unsecured basis by Chevron Corporation (together, the “Obligor Group”). The tables below contain summary financial information for Chevron Corporation, as Guarantor, excluding its consolidated subsidiaries, and CUSA, as the issuer, excluding its consolidated subsidiaries. The summary financial information of the Obligor Group is presented on a combined basis, and transactions between the combined entities have been eliminated. Financial information for non-guarantor entities has been excluded.
| | | | | | | | | | | |
| Year Ended December 31, 2023 | | Year Ended December 31, 2022 |
| (Millions of dollars) (unaudited) |
| Sales and other operating revenues | $ | 100,405 | | | $ | 126,911 | |
| Sales and other operating revenues - related party | 44,553 | | | 50,082 | |
| Total costs and other deductions | 102,773 | | | 121,757 | |
| Total costs and other deductions - related party | 35,781 | | | 43,042 | |
| Net income (loss) | $ | 12,190 | | | $ | 15,043 | |
| | | |
| | | | | | | | |
| Management's Discussion and Analysis of Financial Condition and Results of Operations | |
| | | | | | | | | | | |
| At December 31,
2023 | | At December 31,
2022 |
| | (Millions of dollars) (unaudited) |
| Current assets | $ | 19,006 | | | $ | 28,781 | |
| Current assets - related party | 18,375 | | | 12,326 | |
| Other assets | 54,558 | | | 50,505 | |
| Current liabilities | 20,512 | | | 22,663 | |
| Current liabilities - related party | 132,474 | | | 118,277 | |
| Other liabilities | 28,849 | | | 27,353 | |
| Total net equity (deficit) | $ | (89,896) | | | $ | (76,681) | |
Common Stock Repurchase Program In first quarter 2023, the company purchased a total of 22.4 million shares for $3.7 billion under the February 2019 stock repurchase program. On January 25, 2023, the Board of Directors authorized the repurchase of the company’s shares of common stock in an aggregate amount of $75 billion (the “2023 Program”). The 2023 Program took effect on April 1, 2023, and does not have a fixed expiration date. As of December 31, 2023, the company had purchased a total of 70.4 million shares for $11.2 billion, resulting in $63.8 billion remaining under the 2023 Program. In aggregate, the company purchased 92.8 million shares for $14.9 billion in 2023. In connection with the pending transaction with Hess, share repurchases have been restricted pursuant to SEC regulations since the acquisition announcement and will be restricted until the date of the Hess stockholder vote. Chevron expects share repurchases in the first quarter of 2024 to be around $3 billion plus or minus 20 percent, depending primarily on the timing of the Hess definitive proxy statement mailing.
Repurchases of shares of the company’s common stock may be made from time to time in the open market, by block purchases, in privately negotiated transactions or in such other manner as determined by the company. The timing of the repurchases and the actual amount repurchased will depend on a variety of factors, including the market price of the company’s shares, general market and economic conditions, and other factors. The stock repurchase program does not obligate the company to acquire any particular amount of common stock and may be suspended or discontinued at any time.
Capital Expenditures Capital expenditures (Capex) primarily includes additions to fixed asset or investment accounts for the company’s consolidated subsidiaries and is disclosed in the Consolidated Statement of Cash Flows. Capex by business segment for 2023, 2022 and 2021 is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year ended December 31 |
| Capex | 2023 | | | 2022 | | | 2021 |
| Millions of dollars | U.S. | Int’l. | Total | | | U.S. | Int’l. | Total | | | U.S. | Int’l. | Total |
| Upstream | $ | 9,842 | | $ | 3,836 | | $ | 13,678 | | | | $ | 6,847 | | $ | 2,718 | | $ | 9,565 | | | | $ | 4,554 | | $ | 2,221 | | $ | 6,775 | |
| Downstream | 1,536 | | 237 | | 1,773 | | | | 1,699 | | 375 | | 2,074 | | | | 806 | | 234 | | 1,040 | |
| All Other | 351 | | 27 | | 378 | | | | 310 | | 25 | | 335 | | | | 221 | | 20 | | 241 | |
| Capex | $ | 11,729 | | $ | 4,100 | | $ | 15,829 | | | | $ | 8,856 | | $ | 3,118 | | $ | 11,974 | | | | $ | 5,581 | | $ | 2,475 | | $ | 8,056 | |
Capex for 2023 was $15.8 billion, 32 percent higher than 2022 due to higher investments in the United States, including about $450 million invested in PDC assets post-acquisition and approximately $650 million of inorganic spend, mainly due to the acquisition of a majority stake in ACES Delta, LLC. Capex excludes the acquisition cost of PDC.
The company estimates that 2024 Capex will be approximately $16 billion. In the upstream business, Capex is estimated to be $14 billion, two-thirds of which is expected to be in the U.S., and includes around $5 billion for Permian Basin development and roughly $1.5 billion for other shale & tight assets in the U.S. About 25 percent of U.S upstream Capex is planned for projects in the Gulf of Mexico. Worldwide downstream spending in 2024 is estimated to be $1.5 billion with 80 percent allocated in the U.S. In addition, investments in technology businesses and other corporate operations in 2024 are projected to be about $0.5 billion. Lower carbon Capex included in the upstream and downstream segments totals around $2 billion, including investments to lower the carbon intensity of Chevron’s traditional operations and grow new energy business lines.
Affiliate Capital Expenditures Equity affiliate capital expenditures (Affiliate Capex) primarily includes additions to fixed asset and investment accounts in the equity affiliate companies’ financial statements and does not require cash outlays by the company.
Affiliate Capex by business segment for 2023, 2022 and 2021 is as follows:
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| Management's Discussion and Analysis of Financial Condition and Results of Operations | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year ended December 31 |
| Affiliate Capex | 2023 | | | 2022 | | | 2021 |
| Millions of dollars | U.S. | Int’l. | Total | | | U.S. | Int’l. | Total | | | U.S. | Int’l. | Total |
| Upstream | $ | — | | $ | 2,310 | | $ | 2,310 | | | | $ | — | | $ | 2,406 | | $ | 2,406 | | | | $ | 2 | | $ | 2,404 | | $ | 2,406 | |
| Downstream | 983 | | 241 | | 1,224 | | | | 768 | | 192 | | 960 | | | | 365 | | 396 | | 761 | |
| All Other | — | | — | | — | | | | — | | — | | — | | | | — | | — | | — | |
| Affiliate Capex | $ | 983 | | $ | 2,551 | | $ | 3,534 | | | | $ | 768 | | $ | 2,598 | | $ | 3,366 | | | | $ | 367 | | $ | 2,800 | | $ | 3,167 | |
Affiliate Capex for 2023 was $3.5 billion, 5 percent higher than 2022 due to higher spend at CPChem’s two major integrated polymer projects.
Affiliate Capex is expected to be $3 billion in 2024. Nearly half of Affiliate Capex is for Tengizchevroil’s FGP/WPMP Project in Kazakhstan and about a third is for CPChem.
The company monitors market conditions and can adjust future capital outlays should conditions change.
Noncontrolling Interests The company had noncontrolling interests of $972 million at December 31, 2023 and $960 million at December 31, 2022. Distributions to noncontrolling interests net of contributions totaled $40 million and $114 million in 2023 and 2022, respectively. Included within noncontrolling interests at December 31, 2023 is $166 million of redeemable noncontrolling interest.
Pension Obligations Information related to pension plan contributions is included in Note 23 Employee Benefit Plans, under the heading “Cash Contributions and Benefit Payments.” Contractual Obligations Information related to the company’s significant contractual obligations is included in Note 19 Short-Term Debt, in Note 20 Long-Term Debt and in Note 5 Lease Commitments. The aggregate amount of interest due on these obligations, excluding leases, is: 2024 – $554; 2025 – $494; 2026 – $413; 2027 – $358; 2028 – $319; after 2028 – $3,212. Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements Information related to these off-balance sheet matters is included in Note 24 Other Contingencies and Commitments, under the heading “Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements.”
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| Management's Discussion and Analysis of Financial Condition and Results of Operations | |
Financial Ratios and Metrics
The following represent several metrics the company believes are useful measures to monitor the financial health of the company and its performance over time:
Current Ratio Current assets divided by current liabilities, which indicates the company’s ability to repay its short-term liabilities with short-term assets. The current ratio in all periods is adversely affected by the fact that Chevron’s inventories are valued on a last-in, first-out basis. At year-end 2023, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $6.5 billion.
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| At December 31 | |
| Millions of dollars | 2023 | | | | 2022 | | | 2021 | |
| Current assets | $ | 41,128 | | | | | $ | 50,343 | | | | $ | 33,738 | | |
| Current liabilities | 32,258 | | | | | 34,208 | | | | 26,791 | | |
| Current Ratio | 1.3 | | | | 1.5 | | | 1.3 | |
Interest Coverage Ratio Income before income tax expense, plus interest and debt expense and amortization of capitalized interest, less net income attributable to noncontrolling interests, divided by before-tax interest costs. This ratio indicates the company’s ability to pay interest on outstanding debt.
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| Year ended December 31 | | |
| Millions of dollars | 2023 | | | | 2022 | | 2021 | | |
| Income (Loss) Before Income Tax Expense | $ | 29,584 | | | | | $ | 49,674 | | | $ | 21,639 | | | |
| Plus: Interest and debt expense | 469 | | | | | 516 | | | 712 | | | |
| Plus: Before-tax amortization of capitalized interest | 223 | | | | | 199 | | | 215 | | | |
| Less: Net income attributable to noncontrolling interests | 42 | | | | | 143 | | | 64 | | | |
| Subtotal for calculation | 30,234 | | | | | 50,246 | | | 22,502 | | | |
| Total financing interest and debt costs | $ | 617 | | | | | $ | 630 | | | $ | 775 | | | |
| Interest Coverage Ratio | 49.0 | | | | | 79.8 | | | 29.0 | | | |
Free Cash Flow The cash provided by operating activities less capital expenditures, which represents the cash available to creditors and investors after investing in the business.
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| Year ended December 31 | |
| Millions of dollars | 2023 | | | | 2022 | | 2021 | |
| Net cash provided by operating activities | $ | 35,609 | | | | | $ | 49,602 | | | $ | 29,187 | | |
| Less: Capital expenditures | 15,829 | | | | | 11,974 | | | 8,056 | | |
| Free Cash Flow | $ | 19,780 | | | | | $ | 37,628 | | | $ | 21,131 | | |
Debt Ratio Total debt as a percentage of total debt plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage.
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| At December 31 | | |
| Millions of dollars | 2023 | | | | 2022 | | 2021 | | |
| Short-term debt | $ | 529 | | | | | $ | 1,964 | | | $ | 256 | | | |
| Long-term debt | 20,307 | | | | | 21,375 | | | 31,113 | | | |
| Total debt | 20,836 | | | | | 23,339 | | | 31,369 | | | |
| Total Chevron Corporation Stockholders’ Equity | 160,957 | | | | | 159,282 | | | 139,067 | | | |
| Total debt plus total Chevron Corporation Stockholders’ Equity | $ | 181,793 | | | | | $ | 182,621 | | | $ | 170,436 | | | |
| Debt Ratio | 11.5 | | % | | | 12.8 | | % | 18.4 | | % | |
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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 and marketable securities as a percentage of total debt less cash and cash equivalents and marketable securities, plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage, net of its cash balances.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| At December 31 | |
| Millions of dollars | 2023 | | | | 2022 | | 2021 | |
| Short-term debt | $ | 529 | | | | | $ | 1,964 | | | $ | 256 | | |
| Long-term debt | 20,307 | | | | | 21,375 | | | 31,113 | | |
| Total Debt | 20,836 | | | | | 23,339 | | | 31,369 | | |
| Less: Cash and cash equivalents | 8,178 | | | | | 17,678 | | | 5,640 | | |
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| Less: Marketable securities | 45 | | | | | 223 | | | 35 | | |
| Total adjusted debt | 12,613 | | | | | 5,438 | | | 25,694 | | |
Total Chevron Corporation Stockholders’ Equity | 160,957 | | | | | 159,282 | | | 139,067 | | |
| Total adjusted debt plus total Chevron Corporation Stockholders’ Equity | $ | 173,570 | | | | | $ | 164,720 | | | $ | 164,761 | | |
| Net Debt Ratio | 7.3 | | % | | | 3.3 | | % | 15.6 | | % |
Capital Employed The sum of Chevron Corporation Stockholders’ Equity, total debt and noncontrolling interests, which represents the net investment in the business.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| At December 31 | |
| Millions of dollars | 2023 | | | | 2022 | | 2021 | |
| Chevron Corporation Stockholders’ Equity | $ | 160,957 | | | | | $ | 159,282 | | | $ | 139,067 | | |
| Plus: Short-term debt | 529 | | | | | 1,964 | | | 256 | | |
| Plus: Long-term debt | 20,307 | | | | | 21,375 | | | 31,113 | | |
| Plus: Noncontrolling interest | 972 | | | | | 960 | | | 873 | | |
| Capital Employed at December 31 | $ | 182,765 | | | | | $ | 183,581 | | | $ | 171,309 | | |
Return on Average Capital Employed (ROCE) Net income attributable to Chevron (adjusted for after-tax interest expense and noncontrolling interest) divided by average capital employed. Average capital employed is computed by averaging the sum of capital employed at the beginning and end of the year. ROCE is a ratio intended to measure annual earnings as a percentage of historical investments in the business.
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| Year ended December 31 | |
| Millions of dollars | 2023 | | | | 2022 | | 2021 | |
| Net income attributable to Chevron | $ | 21,369 | | | | | $ | 35,465 | | | $ | 15,625 | | |
| Plus: After-tax interest and debt expense | 432 | | | | | 476 | | | 662 | | |
| Plus: Noncontrolling interest | 42 | | | | | 143 | | | 64 | | |
| Net income after adjustments | 21,843 | | | | | 36,084 | | | 16,351 | | |
| Average capital employed | $ | 183,173 | | | | | $ | 177,445 | | | $ | 174,175 | | |
| Return on Average Capital Employed | 11.9 | | % | | | 20.3 | | % | 9.4 | | % |
Return on Stockholders’ Equity (ROSE) Net income attributable to Chevron divided by average Chevron Corporation Stockholders’ Equity. Average stockholders’ equity is computed by averaging the sum of stockholders’ equity at the beginning and end of the year. ROSE is a ratio intended to measure earnings as a percentage of shareholder investments.
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| Year ended December 31 | |
| Millions of dollars | 2023 | | | | 2022 | | 2021 | |
| Net income attributable to Chevron | $ | 21,369 | | | | | $ | 35,465 | | | $ | 15,625 | | |
| Chevron Corporation Stockholders’ Equity at December 31 | 160,957 | | | | | 159,282 | | | 139,067 | | |
| Average Chevron Corporation Stockholders’ Equity | 160,120 | | | | | 149,175 | | | 135,378 | | |
| Return on Average Stockholders’ Equity | 13.3 | | % | | | 23.8 | | % | 11.5 | | % |
Financial and Derivative Instrument Market Risk
The market risk associated with the company’s portfolio of financial and derivative instruments is discussed below. The estimates of financial exposure to market risk do not represent the company’s projection of future market changes. The actual impact of future market changes could differ materially due to factors discussed elsewhere in this report, including those set forth under the heading Item 1A. Risk Factors.
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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 2023.
The company’s market exposure positions are monitored on a daily basis by an internal Risk Control group in accordance with the company’s risk management policies. The company’s risk management practices and its compliance with policies are reviewed by the Audit Committee of the company’s Board of Directors.
Derivatives beyond those designated as normal purchase and normal sale contracts are recorded at fair value on the Consolidated Balance Sheet with resulting gains and losses reflected in income. Fair values are derived principally from published market quotes and other independent third-party quotes. The change in fair value of Chevron’s derivative commodity instruments in 2023 was not material to the company’s results of operations.
The company uses the Monte Carlo simulation method as its Value-at-Risk (VaR) model to estimate the maximum potential loss in fair value, at the 95 percent confidence level with a one-day holding period, from the effect of adverse changes in market conditions on derivative commodity instruments held or issued. Based on these inputs, the VaR for the company’s primary risk exposures in the area of derivative commodity instruments at December 31, 2023 and 2022 was not material to the company’s cash flows or results of operations.
Foreign Currency The company may enter into foreign currency derivative contracts to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments. The foreign currency derivative contracts, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. There were no open foreign currency derivative contracts at December 31, 2023.
Interest Rates The company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Interest rate swaps, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. At year-end 2023, the company had no interest rate swaps.
Transactions With Related Parties
Chevron enters into a number of business arrangements with related parties, principally its equity affiliates. These arrangements include long-term supply or offtake agreements and long-term purchase agreements. Refer to “Other Information” in Note 15 Investments and Advances for further discussion. Management believes these agreements have been negotiated on terms consistent with those that would have been negotiated with an unrelated party. Litigation and Other Contingencies
Ecuador Information related to Ecuador matters is included in Note 16 Litigation under the heading “Ecuador.” Climate Change Information related to climate change-related matters is included in Note 16 Litigation under the heading “Climate Change.” Louisiana Information related to Louisiana coastal matters is included in Note 16 Litigation under the heading “Louisiana.” Environmental The following table displays the annual changes to the company’s before-tax environmental remediation reserves, including those for U.S. federal Superfund sites and analogous sites under state laws.
| | | | | | | | | | | | | | | | | |
| Millions of dollars | 2023 | | 2022 | | 2021 |
| Balance at January 1 | $ | 868 | | | $ | 960 | | | $ | 1,139 | |
| Net additions | 327 | | | 182 | | | 114 | |
| Expenditures | (259) | | | (274) | | | (293) | |
| Balance at December 31 | $ | 936 | | | $ | 868 | | | $ | 960 | |
The company records asset retirement obligations when there is a legal obligation associated with the retirement of long-lived assets and the liability can be reasonably estimated. These asset retirement obligations include costs related to
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| Management's Discussion and Analysis of Financial Condition and Results of Operations | |
environmental issues. The liability balance of approximately $13.8 billion for asset retirement obligations at year-end 2023 is related primarily to upstream properties.
For the company’s other ongoing operating assets, such as refineries and chemicals facilities, no provisions are made for exit or cleanup costs that may be required when such assets reach the end of their useful lives unless a decision to sell or otherwise decommission the facility has been made, as the indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the asset retirement obligation.
Refer to the discussion below for additional information on environmental matters and their impact on Chevron, and on the company’s 2023 environmental expenditures. Refer to Note 24 Other Contingencies and Commitments for additional discussion of environmental remediation provisions and year-end reserves, and for abandonment and decommissioning obligations for previously sold assets. Refer also to Note 25 Asset Retirement Obligations for additional discussion of the company’s asset retirement obligations. Environmental Matters
The company is subject to various international and U.S. federal, state and local environmental, health and safety laws, regulations and market-based programs. These laws, regulations and programs continue to evolve and are expected to increase in both number and complexity over time and govern not only the manner in which the company conducts its operations, but also the products it sells. Consideration of environmental issues and the responses to those issues through international agreements and national, regional or state legislation or regulations are integrated into the company’s strategy and planning, capital investment reviews and risk management tools and processes, where applicable. They are also factored into the company’s long-range supply, demand and energy price forecasts. These forecasts reflect long-range effects from renewable fuel penetration, energy efficiency standards, climate-related policy actions, and demand response to oil and natural gas prices. In addition, legislation and regulations intended to address hydraulic fracturing also continue to evolve in many jurisdictions where we operate. Refer to Item 1A. Risk Factors for a discussion of some of the inherent risks of increasingly restrictive environmental and other regulation that could materially impact the company’s results of operations or financial condition. Refer to Business Environment and Outlook on pages 34 through 36 for a discussion of legislative and regulatory efforts to address climate change. Most of the costs of complying with existing laws and regulations pertaining to company operations and products are embedded in the normal costs of doing business. However, it is not possible to predict with certainty the amount of additional investments in new or existing technology or facilities or the amounts of increased operating costs to be incurred in the future to prevent, control, reduce or eliminate releases of hazardous materials or other pollutants into the environment; remediate and restore areas damaged by prior releases of hazardous materials; or comply with new environmental laws or regulations. Although these costs may be significant to the results of operations in any single period, the company does not presently expect them to have a material adverse effect on the company’s liquidity or financial position.
Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. The company may incur expenses for corrective actions at various owned and previously owned facilities and at third-party-owned waste disposal sites used by the company. An obligation may arise when operations are closed or sold or at non-Chevron sites where company products have been handled or disposed of. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered acceptable at the time but now require investigative or remedial work or both to meet current standards.
Using definitions and guidelines established by the American Petroleum Institute, Chevron estimated its worldwide environmental spending in 2023 at approximately $2.5 billion for its consolidated companies. Included in these expenditures were approximately $0.5 billion of environmental capital expenditures and $2.0 billion of costs associated
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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 2024, total worldwide environmental capital expenditures are estimated at $0.5 billion. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites.
Critical Accounting Estimates and Assumptions
Management makes many estimates and assumptions in the application of accounting principles generally accepted in the United States of America (GAAP) that may have a material impact on the company’s consolidated financial statements and related disclosures and on the comparability of such information over different reporting periods. Such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on management’s experience and other information available prior to the issuance of the financial statements. Materially different results can occur as circumstances change and additional information becomes known.
The discussion in this section of “critical” accounting estimates and assumptions is according to the disclosure guidelines of the SEC, wherein:
1.the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters, or the susceptibility of such matters to change; and
2.the impact of the estimates and assumptions on the company’s financial condition or operating performance is material.
The development and selection of accounting estimates and assumptions, including those deemed “critical,” and the associated disclosures in this discussion have been discussed with the Audit Committee of the Board of Directors. The areas of accounting and the associated “critical” estimates and assumptions made by the company are as follows:
Oil and Gas Reserves Crude oil, NGLs and natural gas reserves are estimates of future production that impact certain asset and expense accounts included in the Consolidated Financial Statements. Proved reserves are the estimated quantities of oil and gas that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in the future under existing economic conditions, operating methods and government regulations. Proved reserves include both developed and undeveloped volumes. Proved developed reserves represent volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for recompletion. Variables impacting Chevron’s estimated volumes of crude oil and natural gas reserves include field performance, available technology, commodity prices, and development, production and carbon costs.
The estimates of crude oil, NGLs and natural gas reserves are important to the timing of expense recognition for costs incurred and to the valuation of certain oil and gas producing assets. Impacts of oil and gas reserves on Chevron’s Consolidated Financial Statements, using the successful efforts method of accounting, include the following:
1.Depreciation, Depletion and Amortization (DD&A) - Capitalized exploratory drilling and development costs are depreciated on a unit-of-production (UOP) basis using proved developed reserves. Acquisition costs of proved properties are amortized on a UOP basis using total proved reserves. During 2023, Chevron’s UOP DD&A for oil and gas properties was $10.8 billion, and proved developed reserves at the beginning of 2023 were 6.5 billion barrels for consolidated companies. If the estimates of proved reserves used in the UOP calculations for consolidated operations had been lower by five percent across all oil and gas properties, UOP DD&A in 2023 would have increased by approximately $600 million.
2.Impairment - Oil and gas reserves are used in assessing oil and gas producing properties for impairment. A significant reduction in the estimated reserves of a property would trigger an impairment review. Proved reserves (and, in some cases, a portion of unproved resources) are used to estimate future production volumes in the cash flow model. For a further discussion of estimates and assumptions used in impairment assessments, see Impairment of Properties, Plant and Equipment and Investments in Affiliates below.
Refer to Table V, “Proved Reserve Quantity Information,” for the changes in proved reserve estimates for each of the three years ended December 31, 2021, 2022 and 2023, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” for estimates of proved reserve values for each of the three years ended December 31, 2021, 2022 and 2023.
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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 net proceeds exceed the carrying value of the asset or asset group, no impairment charge is required. Such calculations are reviewed each period until the asset or asset group is disposed. Assets that are not impaired on a held-and-used basis could possibly become impaired if a decision is made to sell such assets. That is, the assets would be impaired if they are classified as held-for-sale and the estimated proceeds from the sale, less costs to sell, are less than the assets’ associated carrying values.
Investments in common stock of affiliates that are accounted for under the equity method, as well as investments in other securities of these equity investees, are reviewed for impairment when the fair value of the investment falls below the company’s carrying value. When this occurs, a determination must be made as to whether this loss is other-than-temporary, in which case the investment is impaired. Because of the number of differing assumptions potentially affecting whether an investment is impaired in any period or the amount of the impairment, a sensitivity analysis is not practicable.
A sensitivity analysis of the impact on earnings for these periods if other assumptions had been used in impairment reviews and impairment calculations is not practicable, given the broad range of the company’s PP&E and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired, or resulted in larger impacts on impaired assets.
Asset Retirement Obligations In the determination of fair value for an asset retirement obligation (ARO), the company uses various assumptions and judgments, including such factors as the existence of a legal obligation, estimated amounts and timing of settlements, discount and inflation rates, and the expected impact of advances in technology and process improvements. A sensitivity analysis of the ARO impact on earnings for 2023 is not practicable, given the broad range of the company’s long-lived assets and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions would have reduced estimated future obligations, thereby lowering accretion expense and amortization costs, whereas unfavorable changes would have the opposite effect. Refer to Note 25 Asset Retirement Obligations for additional discussions on asset retirement obligations. Pension and Other Postretirement Benefit Plans Note 23 Employee Benefit Plans includes information on the funded status of the company’s pension and other postretirement benefit (OPEB) plans reflected on the Consolidated Balance Sheet; the components of pension and OPEB expense reflected on the Consolidated Statement of Income; and the related underlying assumptions.
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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 2023, the company used an expected long-term rate of return of 7.0 percent and a discount rate for service costs of 5.2 percent and a discount rate for interest cost of 5.0 percent for the primary U.S. pension plan. The actual return for 2023 was 10.9 percent. For the 10 years ended December 31, 2023, actual asset returns averaged 5.3 percent for this plan. Additionally, with the exception of three years within this 10-year period, actual asset returns for this plan equaled or exceeded 7.0 percent during each year.
Total pension expense for 2023 was $557 million. An increase in the expected long-term return on plan assets or the discount rate would reduce pension plan expense, and vice versa. As an indication of the sensitivity of pension expense to the long-term rate of return assumption, a one percent increase in this assumption for the company’s primary U.S. pension plan, which accounted for about 55 percent of companywide pension expense, would have reduced total pension plan expense for 2023 by approximately $78 million. A one percent increase in the discount rates for this same plan would have reduced pension expense for 2023 by approximately $105 million.
The aggregate funded status recognized at December 31, 2023, was a net liability of approximately $1.5 billion. An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan. At December 31, 2023, the company used a discount rate of 5.0 percent to measure the obligations for the primary U.S. pension plan. As an indication of the sensitivity of pension liabilities to the discount rate assumption, a 0.25 percent increase in the discount rate applied to the company’s primary U.S. pension plan, which accounted for about 65 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $279 million, and would have changed the plan’s funded status from a deficit of $80 million to a surplus of $199 million.
For the company’s OPEB plans, expense for 2023 was $86 million, and the total liability, all unfunded at the end of 2023, was $2.0 billion. For the primary U.S. OPEB plan, the company used a discount rate for service cost of 5.3 percent and a discount rate for interest cost of 5.1 percent to measure expense in 2023, and a 5.0 percent discount rate to measure the benefit obligations at December 31, 2023. Discount rate changes, similar to those used in the pension sensitivity analysis, resulted in an immaterial impact on 2023 OPEB expense and OPEB liabilities at the end of 2023.
Differences between the various assumptions used to determine expense and the funded status of each plan and actual experience are included in actuarial gain/loss. Refer to page 93 in Note 23 Employee Benefit Plans for more information on the $3.7 billion of before-tax actuarial losses recorded by the company as of December 31, 2023. In addition, information related to company contributions is included on page 96 in Note 23 Employee Benefit Plans under the heading “Cash Contributions and Benefit Payments.” Business Combinations — Purchase-Price Allocation Accounting for business combinations requires the allocation of the company’s purchase price to the various assets and liabilities of the acquired business at their respective fair values. The company uses all available information to make these fair value determinations. Determining the fair value of assets acquired generally involves assumptions regarding the amounts and timing of future revenues and expenditures, as well as discount rates. For additional discussion of purchase price allocations, refer to Note 29 Acquisition of PDC Energy, Inc. Contingent Losses Management also makes judgments and estimates in recording liabilities for claims, litigation, tax matters, transferred liabilities from previously sold assets, and environmental remediation. Actual costs can frequently vary from estimates for a variety of reasons. For example, the costs for settlement of claims and litigation can vary from estimates based on differing interpretations of laws, opinions on culpability and assessments on the amount of damages. Similarly, liabilities for environmental remediation are subject to change because of changes in laws, regulations and their interpretation, the determination of additional information on the extent and nature of site contamination, and improvements in technology.
Under the accounting rules, a liability is generally recorded for these types of contingencies if management determines the loss to be both probable and estimable. The company generally reports these losses as “Operating expenses,” “Selling, general and administrative expenses” or “Other income (loss)” on the Consolidated Statement of Income. An exception to this handling is for income tax matters, for which benefits are recognized only if management determines the tax position is
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| Management's Discussion and Analysis of Financial Condition and Results of Operations | |
more likely than not (i.e., likelihood greater than 50 percent) to be allowed by the tax jurisdiction. For additional discussion of income tax uncertainties, refer to Note 24 Other Contingencies and Commitments under the heading “Income Taxes.” Refer also to the business segment discussions elsewhere in this section for the effect on earnings from losses associated with certain litigation, environmental remediation and tax matters for the three years ended December 31, 2023. An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in recording these liabilities is not practicable because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss. For further information, refer to “Changes in management’s estimates and assumptions may have a material impact on the company’s consolidated financial statements and financial or operational performance in any given period” in Item 1A. Risk Factors, on page 26. New Accounting Standards
Quarterly Results
Unaudited
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| 2023 | 2022 |
| Millions of dollars, except per-share amounts | 4th Q | | 3rd Q | | 2nd Q | | 1st Q | | 4th Q | | 3rd Q | | 2nd Q | | 1st Q |
| Revenues and Other Income | | | | | | | | | | | | | | | |
| Sales and other operating revenues | $ | 48,933 | | | $ | 51,922 | | | $ | 47,216 | | | $ | 48,842 | | | $ | 54,523 | | | $ | 63,508 | | | $ | 65,372 | | | $ | 52,314 | |
| Income from equity affiliates | 990 | | | 1,313 | | | 1,240 | | | 1,588 | | | 1,623 | | | 2,410 | | | 2,467 | | | 2,085 | |
| Other income (loss) | (2,743) | | | 845 | | | 440 | | | 363 | | | 327 | | | 726 | | | 923 | | | (26) | |
| Total Revenues and Other Income | 47,180 | | | 54,080 | | | 48,896 | | | 50,793 | | | 56,473 | | | 66,644 | | | 68,762 | | | 54,373 | |
| Costs and Other Deductions | | | | | | | | | | | | | | | |
| Purchased crude oil and products | 28,477 | | | 32,328 | | | 28,984 | | | 29,407 | | | 32,570 | | | 38,751 | | | 40,684 | | | 33,411 | |
| Operating expenses | 6,510 | | | 6,299 | | | 6,057 | | | 6,021 | | | 6,401 | | | 6,357 | | | 6,318 | | | 5,638 | |
| Selling, general and administrative expenses | 969 | | | 1,163 | | | 1,128 | | | 881 | | | 1,454 | | | 1,028 | | | 863 | | | 967 | |
| Exploration expenses | 254 | | | 301 | | | 169 | | | 190 | | | 453 | | 116 | | 196 | | 209 |
| Depreciation, depletion and amortization | 6,254 | | | 4,025 | | | 3,521 | | | 3,526 | | | 4,764 | | | 4,201 | | | 3,700 | | | 3,654 | |
| Taxes other than on income | 1,062 | | | 1,021 | | | 1,041 | | | 1,096 | | | 864 | | | 1,046 | | | 882 | | | 1,240 | |
| Interest and debt expense | 120 | | | 114 | | | 120 | | | 115 | | | 123 | | | 128 | | | 129 | | | 136 | |
| Other components of net periodic benefit costs | 44 | | | 91 | | | 39 | | | 38 | | | 36 | | | 208 | | | (13) | | | 64 | |
| Total Costs and Other Deductions | 43,690 | | | 45,342 | | | 41,059 | | | 41,274 | | | 46,665 | | | 51,835 | | | 52,759 | | | 45,319 | |
| Income (Loss) Before Income Tax Expense | 3,490 | | | 8,738 | | | 7,837 | | | 9,519 | | | 9,808 | | | 14,809 | | | 16,003 | | | 9,054 | |
| Income Tax Expense (Benefit) | 1,247 | | | 2,183 | | | 1,829 | | | 2,914 | | | 3,430 | | | 3,571 | | | 4,288 | | | 2,777 | |
| Net Income (Loss) | $ | 2,243 | | | $ | 6,555 | | | $ | 6,008 | | | $ | 6,605 | | | $ | 6,378 | | | $ | 11,238 | | | $ | 11,715 | | | $ | 6,277 | |
| Less: Net income (loss) attributable to noncontrolling interests | (16) | | | 29 | | | (2) | | | 31 | | | 25 | | | 7 | | | 93 | | | 18 | |
| Net Income (Loss) Attributable to Chevron Corporation | $ | 2,259 | | | $ | 6,526 | | | $ | 6,010 | | | $ | 6,574 | | | $ | 6,353 | | | $ | 11,231 | | | $ | 11,622 | | | $ | 6,259 | |
| Per Share of Common Stock | | | | | | | | | | | | | | | |
| Net Income (Loss) Attributable to Chevron Corporation | | | | | | | | | | | | | | | |
| – Basic | $ | 1.23 | | | $ | 3.48 | | | $ | 3.22 | | | $ | 3.48 | | | $ | 3.34 | | | $ | 5.81 | | | $ | 5.98 | | | $ | 3.23 | |
| – Diluted | $ | 1.22 | | | $ | 3.48 | | | $ | 3.20 | | | $ | 3.46 | | | $ | 3.33 | | | $ | 5.78 | | | $ | 5.95 | | | $ | 3.22 | |
| Dividends per share | $ | 1.51 | | | $ | 1.51 | | | $ | 1.51 | | | $ | 1.51 | | | $ | 1.42 | | | $ | 1.42 | | | $ | 1.42 | | | $ | 1.42 | |
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| Management’s Responsibility for Financial Statements | |
| | |
| To the Stockholders of Chevron Corporation Management of Chevron Corporation is responsible for preparing the accompanying consolidated financial statements and the related information appearing in this report. The statements were prepared in accordance with accounting principles generally accepted in the United States of America and fairly represent the transactions and financial position of the company. The financial statements include amounts that are based on management’s best estimates and judgments. As stated in its report included herein, the independent registered public accounting firm of PricewaterhouseCoopers LLP has audited the company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). The Board of Directors of Chevron has an Audit Committee composed of directors who are not officers or employees of the company. The Audit Committee meets regularly with members of management, the internal auditors and the independent registered public accounting firm to review accounting, internal control, auditing and financial reporting matters. Both the internal auditors and the independent registered public accounting firm have free and direct access to the Audit Committee without the presence of management. The company’s management has evaluated, with the participation of the Chief Executive Officer and Chief Financial Officer, the effectiveness of the company’s disclosure controls and procedures (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2023. Based on that evaluation, management concluded that the company’s disclosure controls are effective in ensuring that information required to be recorded, processed, summarized and reported are done within the time periods specified in the U.S. Securities and Exchange Commission’s rules and forms. | |
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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, 2023. The company excluded PDC Energy, Inc. (PDC) from our assessment of internal control over financial reporting as of December 31, 2023 because it was acquired by the company in a business combination during 2023. Total assets and total revenue of PDC, a wholly-owned subsidiary, represent five percent and one percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2023. The effectiveness of the company’s internal control over financial reporting as of December 31, 2023, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein. | |
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| /s/ MICHAEL K. WIRTH | | /s/ PIERRE R. BREBER | | /s/ ALANA K. KNOWLES | |
| | | | | | |
| Michael K. Wirth | | Pierre R. Breber | | Alana K. Knowles | |
| Chairman of the Board | | Vice President | | Vice President | |
| and Chief Executive Officer | | and Chief Financial Officer | | and Controller | |
| | | | | | |
| February 26, 2024 | | | | | |
| | | | | | |
| | | | | | | | |
| | |
| Report of Independent Registered Public Accounting Firm | |
| To the Board of Directors and Stockholders of Chevron Corporation | |
| Opinions on the Financial Statements and Internal Control over Financial Reporting | |
| We have audited the accompanying consolidated balance sheet of Chevron Corporation and its subsidiaries (the “Company”) as of December 31, 2023 and 2022, and the related consolidated statements of income, of comprehensive income, of equity and of cash flows for each of the three years in the period ended December 31, 2023, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). | |
| In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO. | |
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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. As described in Management’s Report on Internal Control over Financial Reporting, management has excluded PDC Energy, Inc. (PDC) from its assessment of internal control over financial reporting as of December 31, 2023 because it was acquired by the Company in a business combination during 2023. We have also excluded PDC from our audit of internal control over financial reporting. PDC is a wholly-owned subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent five percent and one percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2023. | |
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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 | |
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| transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. | |
| Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. | |
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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 $135.0 billion as of December 31, 2023, and depreciation, depletion and amortization expense was $15.8 billion for the year ended December 31, 2023. The Company follows the successful efforts method of accounting for crude oil and natural gas exploration and production activities. Depreciation and depletion of all capitalized costs of proved crude oil and natural gas producing properties, except mineral interests, are expensed using the unit-of-production method, generally by individual field, as the proved developed reserves are produced. Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of-production method by individual field as the related proved reserves are produced. As disclosed by management, variables impacting the Company’s estimated volumes of proved crude oil and natural gas reserves include field performance, available technology, commodity prices, and development, production and carbon costs. Reserves are estimated by Company asset teams composed of earth scientists and engineers. As part of the internal control process related to reserves estimation, the Company maintains a Reserves Advisory Committee (RAC) (the Company’s earth scientists, engineers and RAC are collectively referred to as “management’s specialists”). The principal considerations for our determination that performing procedures relating to the impact of proved developed crude oil and natural gas reserves on upstream property, plant, and equipment, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved developed crude oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained related to the data, methods and assumptions used by management and its specialists in developing the estimates of proved developed crude oil and natural gas reserves. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved developed crude oil and natural gas reserves. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved developed crude oil and natural gas reserves. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of data used by the specialists and an evaluation of the specialists’ findings related to estimated future production volumes by comparing the estimate to relevant historical and current period information, as applicable. | |
| /s/ PricewaterhouseCoopers LLP | |
| San Francisco, California | |
| February 26, 2024 | |
| We have served as the Company’s auditor since 1935. | |
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| Consolidated Statement of Income | |
| Millions of dollars, except per-share amounts | |
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| | Year ended December 31 | |
| | 2023 | | | 2022 | | 2021 | |
| Revenues and Other Income | | | | | | | |
| Sales and other operating revenues | $ | 196,913 | | | | $ | 235,717 | | | $ | 155,606 | | |
| Income (loss) from equity affiliates | 5,131 | | | | 8,585 | | | 5,657 | | |
| Other income (loss) | (1,095) | | | | 1,950 | | | 1,202 | | |
| Total Revenues and Other Income | 200,949 | | | | 246,252 | | | 162,465 | | |
| Costs and Other Deductions | | | | | | | |
| Purchased crude oil and products | 119,196 | | | | 145,416 | | | 92,249 | | |
| Operating expenses | 24,887 | | | | 24,714 | | | 20,726 | | |
| Selling, general and administrative expenses | 4,141 | | | | 4,312 | | | 4,014 | | |
| Exploration expenses | 914 | | | | 974 | | | 549 | | |
| Depreciation, depletion and amortization | 17,326 | | | | 16,319 | | | 17,925 | | |
| Taxes other than on income | 4,220 | | | | 4,032 | | | 3,963 | | |
| Interest and debt expense | 469 | | | | 516 | | | 712 | | |
| Other components of net periodic benefit costs | 212 | | | | 295 | | | 688 | | |
| Total Costs and Other Deductions | 171,365 | | | | 196,578 | | | 140,826 | | |
| Income (Loss) Before Income Tax Expense | 29,584 | | | | 49,674 | | | 21,639 | | |
| Income Tax Expense (Benefit) | 8,173 | | | | 14,066 | | | 5,950 | | |
| Net Income (Loss) | 21,411 | | | | 35,608 | | | 15,689 | | |
| Less: Net income (loss) attributable to noncontrolling interests | 42 | | | | 143 | | | 64 | | |
| Net Income (Loss) Attributable to Chevron Corporation | $ | 21,369 | | | | $ | 35,465 | | | $ | 15,625 | | |
| Per Share of Common Stock | | | | | | | |
| Net Income (Loss) Attributable to Chevron Corporation | | | | | | | |
| - Basic | $ | 11.41 | | | | $ | 18.36 | | | $ | 8.15 | | |
| - Diluted | $ | 11.36 | | | | $ | 18.28 | | | $ | 8.14 | | |
| See accompanying Notes to the Consolidated Financial Statements. | |
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| Consolidated Statement of Comprehensive Income | |
| Millions of dollars | |
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| | Year ended December 31 | |
| | 2023 | | | 2022 | | | 2021 | |
| Net Income (Loss) | $ | 21,411 | | | | $ | 35,608 | | | | $ | 15,689 | | |
| Currency translation adjustment | | | | | | | | |
| Unrealized net change arising during period | 11 | | | | (41) | | | | (55) | | |
| Unrealized holding gain (loss) on securities | | | | | | | | |
| Net gain (loss) arising during period | 1 | | | | (1) | | | | (1) | | |
| Derivatives | | | | | | | | |
| Net derivatives gain (loss) on hedge transactions | (11) | | | | 65 | | | | (6) | | |
| | | | | | | | | |
| Reclassification to net income | 33 | | | | (80) | | | | 6 | | |
| Income tax benefit (cost) on derivatives transactions | (5) | | | | 3 | | | | — | | |
| Total | 17 | | | | (12) | | | | — | | |
| Defined benefit plans | | | | | | | | |
| Actuarial gain (loss) | | | | | | | | |
| Amortization to net income of net actuarial loss and settlements | 244 | | | | 599 | | | | 1,069 | | |
| Actuarial gain (loss) arising during period | (550) | | | | 1,050 | | | | 1,244 | | |
| Prior service credits (cost) | | | | | | | | |
| Amortization to net income of net prior service costs and curtailments | (13) | | | | (19) | | | | (14) | | |
| Prior service (costs) credits arising during period | (29) | | | | (96) | | | | — | | |
| Defined benefit plans sponsored by equity affiliates - benefit (cost) | 6 | | | | 100 | | | | 127 | | |
| Income tax benefit (cost) on defined benefit plans | 151 | | | | (489) | | | | (647) | | |
| Total | (191) | | | | 1,145 | | | | 1,779 | | |
| Other Comprehensive Gain (Loss), Net of Tax | (162) | | | | 1,091 | | | | 1,723 | | |
| Comprehensive Income (Loss) | 21,249 | | | | 36,699 | | | | 17,412 | | |
| Comprehensive loss (income) attributable to noncontrolling interests | (42) | | | | (143) | | | | (64) | | |
| Comprehensive Income (Loss) Attributable to Chevron Corporation | $ | 21,207 | | | | $ | 36,556 | | | | $ | 17,348 | | |
| See accompanying Notes to the Consolidated Financial Statements. | | | | |
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| Consolidated Balance Sheet | |
| Millions of dollars, except per-share amounts | |
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| | At December 31 | |
| | 2023 | | 2022 | |
| Assets | | | | |
| Cash and cash equivalents | $ | 8,178 | | | $ | 17,678 | | |
| | | | | |
| Marketable securities | 45 | | | 223 | | |
| Accounts and notes receivable (less allowance: 2023 - $301; 2022 - $457) | 19,921 | | | 20,456 | | |
| Inventories: | | | | |
| Crude oil and products | 6,059 | | | 5,866 | | |
| Chemicals | 406 | | | 515 | | |
| Materials, supplies and other | 2,147 | | | 1,866 | | |
| Total inventories | 8,612 | | | 8,247 | | |
| Prepaid expenses and other current assets | 4,372 | | | 3,739 | | |
| Total Current Assets | 41,128 | | | 50,343 | | |
| Long-term receivables, net (less allowances: 2023 - $340; 2022 - $552) | 942 | | | 1,069 | | |
| Investments and advances | 46,812 | | | 45,238 | | |
| Properties, plant and equipment, at cost | 346,081 | | | 327,785 | | |
| Less: Accumulated depreciation, depletion and amortization | 192,462 | | | 184,194 | | |
| Properties, plant and equipment, net | 153,619 | | | 143,591 | | |
| Deferred charges and other assets | 13,734 | | | 12,310 | | |
| Goodwill | 4,722 | | | 4,722 | | |
| Assets held for sale | 675 | | | 436 | | |
| Total Assets | $ | 261,632 | | | $ | 257,709 | | |
| Liabilities and Equity | | | | |
| Short-term debt | $ | 529 | | | $ | 1,964 | | |
| Accounts payable | 20,423 | | | 18,955 | | |
| Accrued liabilities | 7,655 | | | 7,486 | | |
| Federal and other taxes on income | 1,863 | | | 4,381 | | |
| Other taxes payable | 1,788 | | | 1,422 | | |
| Total Current Liabilities | 32,258 | | | 34,208 | | |
| Long-term debt1 | 20,307 | | | 21,375 | | |
| | | | | |
| Deferred credits and other noncurrent obligations | 24,226 | | | 20,396 | | |
| Noncurrent deferred income taxes | 18,830 | | | 17,131 | | |
| Noncurrent employee benefit plans | 4,082 | | | 4,357 | | |
| Total Liabilities2 | $ | 99,703 | | | $ | 97,467 | | |
| Preferred stock (authorized 100,000,000 shares; $1.00 par value; none issued) | — | | | — | | |
| Common stock (authorized 6,000,000,000 shares; $0.75 par value; 2,442,676,580 shares issued at December 31, 2023 and 2022) | 1,832 | | | 1,832 | | |
| Capital in excess of par value | 21,365 | | | 18,660 | | |
| Retained earnings | 200,025 | | | 190,024 | | |
| Accumulated other comprehensive losses | (2,960) | | | (2,798) | | |
| Deferred compensation and benefit plan trust | (240) | | | (240) | | |
| Treasury stock, at cost (2023 - 577,028,776 shares; 2022 - 527,460,237 shares) | (59,065) | | | (48,196) | | |
| Total Chevron Corporation Stockholders’ Equity | 160,957 | | | 159,282 | | |
| Noncontrolling interests (includes redeemable noncontrolling interest of $166 and $142 at December 31, 2023 and 2022) | 972 | | | 960 | | |
| Total Equity | 161,929 | | | 160,242 | | |
| Total Liabilities and Equity | $ | 261,632 | | | $ | 257,709 | | |
| 1 Includes finance lease liabilities of $574 and $403 at December 31, 2023 and 2022, respectively. | | | | |
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| See accompanying Notes to the Consolidated Financial Statements. | | | | |
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| Consolidated Statement of Cash Flows | |
| Millions of dollars | |
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| | | | | | | |
| | Year ended December 31 | |
| | 2023 | | 2022 | | 2021 | |
| Operating Activities | | | | | | |
| Net Income (Loss) | $ | 21,411 | | | $ | 35,608 | | | $ | 15,689 | | |
| Adjustments | | | | | | |
| Depreciation, depletion and amortization | 17,326 | | | 16,319 | | | 17,925 | | |
| Dry hole expense | 436 | | | 486 | | | 118 | | |
| Distributions more (less) than income from equity affiliates | (885) | | | (4,730) | | | (1,998) | | |
| Net before-tax gains on asset retirements and sales | (138) | | | (550) | | | (1,021) | | |
| Net foreign currency effects | 578 | | | (412) | | | (7) | | |
| Deferred income tax provision | 298 | | | 2,124 | | | 700 | | |
| Net decrease (increase) in operating working capital | (3,185) | | | 2,125 | | | (1,361) | | |
| Decrease (increase) in long-term receivables | 150 | | | 153 | | | 21 | | |
| Net decrease (increase) in other deferred charges | (300) | | | (212) | | | (320) | | |
| Cash contributions to employee pension plans | (1,120) | | | (1,322) | | | (1,751) | | |
| Other | 1,038 | | | 13 | | | 1,192 | | |
| Net Cash Provided by Operating Activities | 35,609 | | | 49,602 | | | 29,187 | | |
| Investing Activities | | | | | | |
| Acquisition of businesses, net of cash received | 55 | | | (2,862) | | | — | | |
| Capital expenditures | (15,829) | | | (11,974) | | | (8,056) | | |
| Proceeds and deposits related to asset sales and returns of investment | 669 | | | 2,635 | | | 1,791 | | |
| | | | | | | |
| Net sales (purchases) of marketable securities | 175 | | | 117 | | | (1) | | |
| Net repayment (borrowing) of loans by equity affiliates | (302) | | | (24) | | | 401 | | |
| Net Cash Used for Investing Activities | (15,232) | | | (12,108) | | | (5,865) | | |
| Financing Activities | | | | | | |
| Net borrowings (repayments) of short-term obligations | 135 | | | 263 | | | (5,572) | | |
| Proceeds from issuances of long-term debt | 150 | | | — | | | — | | |
| Repayments of long-term debt and other financing obligations | (4,340) | | | (8,742) | | | (7,364) | | |
| Cash dividends - common stock | (11,336) | | | (10,968) | | | (10,179) | | |
| Net contributions from (distributions to) noncontrolling interests | (40) | | | (114) | | | (36) | | |
| Net sales (purchases) of treasury shares | (14,678) | | | (5,417) | | | 38 | | |
| Net Cash Provided by (Used for) Financing Activities | (30,109) | | | (24,978) | | | (23,113) | | |
| Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash | (114) | | | (190) | | | (151) | | |
| Net Change in Cash, Cash Equivalents and Restricted Cash | (9,846) | | | 12,326 | | | 58 | | |
| Cash, Cash Equivalents and Restricted Cash at January 1 | 19,121 | | | 6,795 | | | 6,737 | | |
| Cash, Cash Equivalents and Restricted Cash at December 31 | $ | 9,275 | | | $ | 19,121 | | | $ | 6,795 | | |
| See accompanying Notes to the Consolidated Financial Statements. | |
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| Consolidated Statement of Equity | |
| Amounts in millions of dollars | |
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| | | 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, 2020 | $ | 18,421 | | $ | 160,377 | | $ | (5,612) | | $ | (41,498) | | $ | 131,688 | | | $ | 1,038 | | | $ | 132,726 | |
| Treasury stock transactions | 315 | | — | | — | | — | | 315 | | | — | | | 315 | |
| NBLX acquisition | 138 | | (148) | | — | | 377 | | 367 | | | (321) | | | 46 | |
| Net income (loss) | — | | 15,625 | | — | | — | | 15,625 | | | 64 | | | 15,689 | |
| Cash dividends ($5.31 per share) | — | | (10,179) | | — | | — | | (10,179) | | | (53) | | | (10,232) | |
| Stock dividends | — | | (3) | | — | | — | | (3) | | | — | | | (3) | |
| Other comprehensive income | — | | — | | 1,723 | | — | | 1,723 | | | — | | | 1,723 | |
| Purchases of treasury shares | — | | — | | — | | (1,383) | | (1,383) | | | — | | | (1,383) | |
| Issuances of treasury shares | — | | — | | — | | 1,040 | | 1,040 | | | — | | | 1,040 | |
| Other changes, net | — | | (126) | | — | | — | | (126) | | | 145 | | | 19 | |
| Balance at December 31, 2021 | $ | 18,874 | | $ | 165,546 | | $ | (3,889) | | $ | (41,464) | | $ | 139,067 | | | $ | 873 | | | $ | 139,940 | |
| Treasury stock transactions | 63 | | — | | — | | — | | 63 | | | — | | | 63 | |
| | | | | | | | | |
| Net income (loss) | — | | 35,465 | | — | | — | | 35,465 | | | 143 | | | 35,608 | |
| Cash dividends ($5.68 per share) | — | | (10,968) | | — | | — | | (10,968) | | | (118) | | | (11,086) | |
| Stock dividends | — | | (3) | | — | | — | | (3) | | | — | | | (3) | |
| Other comprehensive income | — | | — | | 1,091 | | — | | 1,091 | | | — | | | 1,091 | |
| Purchases of treasury shares | — | | — | | — | | (11,255) | | (11,255) | | | — | | | (11,255) | |
| Issuances of treasury shares | 1,315 | | — | | — | | 4,523 | | 5,838 | | | — | | | 5,838 | |
| Other changes, net | — | | (16) | | — | | — | | (16) | | | 62 | | | 46 | |
| Balance at December 31, 2022 | $ | 20,252 | | $ | 190,024 | | $ | (2,798) | | $ | (48,196) | | $ | 159,282 | | | $ | 960 | | | $ | 160,242 | |
| Treasury stock transactions | 174 | | — | | — | | — | | 174 | | | — | | | 174 | |
| PDC Energy, Inc. acquisition | 2,550 | | — | | — | | 3,970 | | 6,520 | | | — | | | 6,520 | |
| Net income (loss) | — | | 21,369 | | — | | — | | 21,369 | | | 42 | | | 21,411 | |
| Cash dividends ($6.04 per share) | — | | (11,336) | | — | | — | | (11,336) | | | (54) | | | (11,390) | |
| Stock dividends | — | | (9) | | — | | — | | (9) | | | — | | | (9) | |
| Other comprehensive income | — | | — | | (162) | | — | | (162) | | | — | | | (162) | |
Purchases of treasury shares2 | — | | — | | — | | (15,085) | | (15,085) | | | — | | | (15,085) | |
| Issuances of treasury shares | 17 | | — | | — | | 246 | | 263�� | | | — | | | 263 | |
| Other changes, net | (36) | | (23) | | — | | — | | (59) | | | 24 | | | (35) | |
| Balance at December 31, 2023 | $ | 22,957 | | $ | 200,025 | | $ | (2,960) | | $ | (59,065) | | $ | 160,957 | | | $ | 972 | | | $ | 161,929 | |
| | | | | | | | | |
| | | Common Stock Share Activity | | | | |
| | Issued3 | | Treasury | | | Outstanding | | |
| Balance at December 31, 2020 | | 2,442,676,580 | | | (517,490,263) | | | | 1,925,186,317 | | | |
| Purchases | | — | | | (13,015,737) | | | | (13,015,737) | | | |
| Issuances | | — | | | 17,635,477 | | | | 17,635,477 | | | |
| Balance at December 31, 2021 | | 2,442,676,580 | | | (512,870,523) | | | | 1,929,806,057 | | | |
| Purchases | | — | | | (69,912,961) | | | | (69,912,961) | | | |
| Issuances | | — | | | 55,323,247 | | | | 55,323,247 | | | |
| Balance at December 31, 2022 | | 2,442,676,580 | | | (527,460,237) | | | | 1,915,216,343 | | | |
| Purchases | | — | | | (92,849,905) | | | | (92,849,905) | | | |
| Issuances | | — | | | 43,281,366 | | | | 43,281,366 | | | |
| Balance at December 31, 2023 | | 2,442,676,580 | | | (577,028,776) | | | | 1,865,647,804 | | | |
1 Beginning and ending balances for all periods include capital in excess of par, common stock issued at par for $1,832, and $(240) associated with Chevron’s Benefit Plan Trust. Changes reflect capital in excess of par. |
2 Includes excise tax on share repurchases. |
3 Beginning and ending total issued share balances include 14,168,000 shares associated with Chevron’s Benefit Plan Trust. |
| See accompanying Notes to the Consolidated Financial Statements. |
| | | | | | | | | |
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 1
Summary of Significant Accounting Policies
General The company’s Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America. These require the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Although the company uses its best estimates and judgments, actual results could differ from these estimates as circumstances change and additional information becomes known. Prior years’ data have been reclassified in certain cases to conform to the 2023 presentation basis.
Subsidiary and Affiliated Companies The Consolidated Financial Statements include the accounts of controlled subsidiary companies more than 50 percent-owned and any variable interest entities in which the company is the primary beneficiary. Undivided interests in oil and gas joint ventures and certain other assets are consolidated on a proportionate basis. Investments in and advances to affiliates in which the company has a substantial ownership interest of approximately 20 percent to 50 percent, or for which the company exercises significant influence but not control over policy decisions, are accounted for by the equity method.
Investments in affiliates are assessed for possible impairment when events indicate that the fair value of the investment may be below the company’s carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in net income. In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee’s financial performance, and the company’s ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. The new cost basis of investments in these equity investees is not changed for subsequent recoveries in fair value.
Differences between the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned to the extent practicable to specific assets and liabilities based on the company’s analysis of the various factors giving rise to the difference. When appropriate, the company’s share of the affiliate’s reported earnings is adjusted quarterly to reflect the difference between these allocated values and the affiliate’s historical book values.
Noncontrolling Interests Ownership interests in the company’s subsidiaries held by parties other than the parent are presented separately from the parent’s equity on the Consolidated Balance Sheet. The amount of consolidated net income attributable to the parent and the noncontrolling interests are both presented on the face of the Consolidated Statement of Income and Consolidated Statement of Equity. Included within noncontrolling interest is redeemable noncontrolling interest.
Fair Value Measurements The three levels of the fair value hierarchy of inputs the company uses to measure the fair value of an asset or a liability are as follows. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Level 3 inputs are inputs that are not observable in the market.
Derivatives The majority of the company’s activity in derivative commodity instruments is intended to manage the financial risk posed by physical transactions. For some of this derivative activity, the company may elect to apply fair value or cash flow hedge accounting with changes in fair value recorded as components of accumulated other comprehensive income (loss). For other similar derivative instruments, generally because of the short-term nature of the contracts or their limited use, the company does not apply hedge accounting, and changes in the fair value of those contracts are reflected in current income. For the company’s commodity trading activity, gains and losses from derivative instruments are reported in current income. The company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Interest rate swaps related to a portion of the company’s fixed-rate debt, if any, may be accounted for as fair value hedges. Interest rate swaps related to floating-rate debt, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. Where Chevron is a party to master netting arrangements, fair value receivable and payable amounts recognized for derivative instruments executed with the same counterparty are generally offset on the balance sheet.
Inventories Crude oil, products and chemicals inventories are generally stated at cost, using a last-in, first-out method. In the aggregate, these costs are below market. “Materials, supplies and other” inventories are primarily stated at cost or net realizable value.
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| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. All other exploratory wells and costs are expensed. Refer to Note 21 Accounting for Suspended Exploratory Wells for additional discussion of accounting for suspended exploratory well costs. Long-lived assets to be held and used, including proved crude oil and natural gas properties, are assessed for possible impairment by comparing their carrying values with their associated undiscounted, future net cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset (including changes to the commodity price forecast or carbon costs), significant change in the extent or manner of use of or a physical change in an asset, and a more likely than not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted, future net cash flows. For proved crude oil and natural gas properties, the company performs impairment reviews on a country, concession, PSC, development area or field basis, as appropriate. In downstream, impairment reviews are performed on the basis of a refinery, a plant, a marketing/lubricants area or distribution area, as appropriate. Impairment amounts are recorded as incremental “Depreciation, depletion and amortization” expense.
Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value. Refer to Note 9 Fair Value Measurements relating to fair value measurements. The fair value of a liability for an ARO is recorded as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. Refer also to Note 25 Asset Retirement Obligations relating to AROs. Depreciation and depletion of all capitalized costs of proved crude oil and natural gas producing properties, except mineral interests, are expensed using the unit-of-production method, generally by individual field, as the proved developed reserves are produced. Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of-production method by individual field as the related proved reserves are produced. Impairments of capitalized costs of unproved mineral interests are expensed.
The capitalized costs of all other plant and equipment are depreciated or amortized over their estimated useful lives. In general, the declining-balance method is used to depreciate plant and equipment in the United States; the straight-line method is generally used to depreciate international plant and equipment and to amortize finance lease right-of-use assets.
Gains or losses are not recognized for normal retirements of properties, plant and equipment subject to composite group amortization or depreciation. Gains or losses from abnormal retirements are recorded as expenses, and from sales as “Other income.”
Expenditures for maintenance (including those for planned major maintenance projects), repairs and minor renewals to maintain facilities in operating condition are generally expensed as incurred. Major replacements and renewals are capitalized.
Leases Leases are classified as operating or finance leases. Both operating and finance leases recognize lease liabilities and associated right-of-use assets. The company has elected the short-term lease exception and therefore only recognizes right-of-use assets and lease liabilities for leases with a term greater than one year. The company has elected the practical expedient to not separate non-lease components from lease components for most asset classes except for certain asset classes that have significant non-lease (i.e., service) components.
Where leases are used in joint ventures, the company recognizes 100 percent of the right-of-use assets and lease liabilities when the company is the sole signatory for the lease (in most cases, where the company is the operator of a joint venture). Lease costs reflect only the costs associated with the operator’s working interest share. The lease term includes the committed lease term identified in the contract, taking into account renewal and termination options that management is
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| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
reasonably certain to exercise. The company uses its incremental borrowing rate as a proxy for the discount rate based on the term of the lease unless the implicit rate is available.
Goodwill Goodwill resulting from a business combination is not subject to amortization. The company tests such goodwill at the reporting unit level for impairment annually at December 31, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount.
Environmental Expenditures Environmental expenditures that relate to ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized.
Liabilities related to future remediation costs are recorded when environmental assessments or cleanups or both are probable and the costs can be reasonably estimated. For crude oil, natural gas and mineral-producing properties, a liability for an ARO is made in accordance with accounting standards for asset retirement and environmental obligations. Refer to Note 25 Asset Retirement Obligations for a discussion of the company’s AROs. For abandonment and decommissioning obligations related to previously sold assets, refer to Note 24 Other Contingencies and Commitments. For U.S. federal Superfund sites and analogous sites under state laws, the company records a liability for its designated share of the probable and estimable costs, and probable amounts for other potentially responsible parties when mandated by the regulatory agencies because the other parties are not able to pay their respective shares. The gross amount of environmental liabilities is based on the company’s best estimate of future costs using currently available technology and applying current regulations and the company’s own internal environmental policies. Future amounts are not discounted. Recoveries or reimbursements are recorded as assets when receipt is reasonably assured.
Currency Translation The U.S. dollar is the functional currency for substantially all of the company’s consolidated operations and those of its equity affiliates. For those operations, all gains and losses from currency remeasurement are included in current period income. The cumulative translation effects for those few entities, both consolidated and affiliated, using functional currencies other than the U.S. dollar are included in “Currency translation adjustment” on the Consolidated Statement of Equity.
Revenue Recognition The company accounts for each delivery order of crude oil, NGLs, natural gas, petroleum and chemical products as a separate performance obligation. Revenue is recognized when the performance obligation is satisfied, which typically occurs at the point in time when control of the product transfers to the customer. Payment is generally due within 30 days of delivery. The company accounts for delivery transportation as a fulfillment cost, not a separate performance obligation, and recognizes these costs as an operating expense in the period when revenue for the related commodity is recognized.
Revenue is measured as the amount the company expects to receive in exchange for transferring commodities to the customer. The company’s commodity sales are typically based on prevailing market-based prices and may include discounts and allowances. Until market prices become known under terms of the company’s contracts, the transaction price included in revenue is based on the company’s estimate of the most likely outcome.
Discounts and allowances are estimated using a combination of historical and recent data trends. When deliveries contain multiple products, an observable standalone selling price is generally used to measure revenue for each product. The company includes estimates in the transaction price only to the extent that a significant reversal of revenue is not probable in subsequent periods.
Stock Options and Other Share-Based Compensation The company issues stock options and other share-based compensation to certain employees. For equity awards, such as stock options and certain restricted stock units, total compensation cost is based on the grant date fair value, and for liability awards, such as stock appreciation rights, total compensation cost is based on the settlement value. The company recognizes stock-based compensation expense for all awards over the service period required to earn the award, which is the shorter of the vesting period or the time period in which an employee becomes eligible to retain the award at retirement. The company’s Long-Term Incentive Plan (LTIP) awards include stock options and stock appreciation rights, which have graded vesting provisions by which one-third of each award vests on each of the first, second and third anniversaries of the date of grant. In addition, performance shares granted under the company’s LTIP will vest at the end of the three-year performance period. For awards granted under the company’s LTIP beginning in 2017, stock options and stock appreciation rights have graded vesting by which one-third of each award vests annually on each January 31 on or after the first anniversary of the grant date. Special restricted stock unit awards have cliff vesting by which the total award will vest on January 31 on or after the third anniversary of the grant date. Standard restricted stock unit awards have cliff vesting by which the total award will vest on January 31 on or after
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
the fifth anniversary of the grant date, subject to adjustment upon termination pursuant to the satisfaction of certain criteria. Commencing for grants issued in January 2023 and after, standard restricted stock units vest ratably on an annual basis over a three-year period. The company amortizes these awards on a straight-line basis.
Note 2
Changes in Accumulated Other Comprehensive Losses
The change in Accumulated Other Comprehensive Losses (AOCL) presented on the Consolidated Balance Sheet and the impact of significant amounts reclassified from AOCL on information presented in the Consolidated Statement of Income for the year ended December 31, 2023, are reflected in the table below.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Currency Translation Adjustments | | Unrealized Holding Gains (Losses) on Securities | | Derivatives | | Defined Benefit Plans | | Total |
| Balance at December 31, 2020 | $ | (107) | | | $ | (10) | | | $ | — | | | $ | (5,495) | | | $ | (5,612) | |
Components of Other Comprehensive Income (Loss)1: | | | | | | | | | |
| Before Reclassifications | (55) | | | (1) | | | (6) | | | 949 | | | 887 | |
Reclassifications2,3 | — | | | — | | | 6 | | | 830 | | | 836 | |
| Net Other Comprehensive Income (Loss) | (55) | | | (1) | | | — | | | 1,779 | | | 1,723 | |
| Balance at December 31, 2021 | $ | (162) | | | $ | (11) | | | $ | — | | | $ | (3,716) | | | $ | (3,889) | |
Components of Other Comprehensive Income (Loss)1: | | | | | | | | | |
| Before Reclassifications | (41) | | | (1) | | | 68 | | | 703 | | | 729 | |
Reclassifications2, 3 | — | | | — | | | (80) | | | 442 | | | 362 | |
| Net Other Comprehensive Income (Loss) | (41) | | | (1) | | | (12) | | | 1,145 | | | 1,091 | |
| | | | | | | | | |
| Balance at December 31, 2022 | $ | (203) | | | $ | (12) | | | $ | (12) | | | $ | (2,571) | | | $ | (2,798) | |
Components of Other Comprehensive Income (Loss)1: | | | | | | | | | |
| Before Reclassifications | 11 | | | 1 | | | (16) | | | (397) | | | (401) | |
Reclassifications2, 3 | — | | | — | | | 33 | | | 206 | | | 239 | |
| Net Other Comprehensive Income (Loss) | 11 | | | 1 | | | 17 | | | (191) | | | (162) | |
| | | | | | | | | |
| Balance at December 31, 2023 | $ | (192) | | | $ | (11) | | | $ | 5 | | | $ | (2,762) | | | $ | (2,960) | |
1 All amounts are net of tax.
2 Refer to Note 23 Employee Benefit Plans, for reclassified components, including amortization of actuarial gains or losses, amortization of prior service costs and settlement losses, totaling $231 that are included in employee benefit costs for the year ended December 31, 2023. Related income taxes for the same period, totaling $25, are reflected in Income Tax Expense on the Consolidated Statement of Income. All other reclassified amounts were insignificant.
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| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 3
Information Relating to the Consolidated Statement of Cash Flows
| | | | | | | | | | | | | | | | | | | | |
| Year ended December 31 |
| 2023 | | | 2022 | | 2021 |
| Distributions more (less) than income from equity affiliates includes the following: | | | | | | |
| Distributions from equity affiliates | $ | 4,246 | | | | $ | 3,855 | | | $ | 3,659 | |
| (Income) loss from equity affiliates | (5,131) | | | | (8,585) | | | (5,657) | |
| Distributions more (less) than income from equity affiliates | $ | (885) | | | | $ | (4,730) | | | $ | (1,998) | |
| Net decrease (increase) in operating working capital was composed of the following: | | | | | | |
| Decrease (increase) in accounts and notes receivable | $ | 1,187 | | | | $ | (2,317) | | | $ | (7,548) | |
| Decrease (increase) in inventories | (320) | | | | (930) | | | (530) | |
| Decrease (increase) in prepaid expenses and other current assets | (1,202) | | | | (226) | | | 19 | |
| Increase (decrease) in accounts payable and accrued liabilities | (49) | | | | 2,750 | | | 5,475 | |
| Increase (decrease) in income and other taxes payable | (2,801) | | | | 2,848 | | | 1,223 | |
| Net decrease (increase) in operating working capital | $ | (3,185) | | | | $ | 2,125 | | | $ | (1,361) | |
| Net cash provided by operating activities includes the following cash payments: | | | | | | |
| Interest on debt (net of capitalized interest) | $ | 465 | | | | $ | 525 | | | $ | 699 | |
| Income taxes | 10,416 | | | | 9,148 | | | 4,355 | |
| Proceeds and deposits related to asset sales and returns of investment consisted of the following gross amounts: | | | | | | |
| Proceeds and deposits related to asset sales | $ | 446 | | | | $ | 1,435 | | | $ | 1,352 | |
| Returns of investment from equity affiliates | 223 | | | | 1,200 | | | 439 | |
| Proceeds and deposits related to asset sales and returns of investment | $ | 669 | | | | $ | 2,635 | | | $ | 1,791 | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| Net sales (purchases) of marketable securities consisted of the following gross amounts: | | | | | | |
| Marketable securities purchased | $ | (289) | | | | $ | (7) | | | $ | (4) | |
| Marketable securities sold | 464 | | | | 124 | | | 3 | |
| Net sales (purchases) of marketable securities | $ | 175 | | | | $ | 117 | | | $ | (1) | |
| Net repayment (borrowing) of loans by equity affiliates: | | | | | | |
| Borrowing of loans by equity affiliates | $ | (368) | | | | $ | (108) | | | $ | — | |
| Repayment of loans by equity affiliates | 66 | | | | 84 | | | 401 | |
| Net repayment (borrowing) of loans by equity affiliates | $ | (302) | | | | $ | (24) | | | $ | 401 | |
| Net borrowings (repayments) of short-term obligations consisted of the following gross and net amounts: | | | | | | |
| Repayments of short-term obligations | $ | — | | | | $ | — | | | $ | (6,906) | |
| Proceeds from issuances of short-term debt obligations | — | | | | — | | | 4,448 | |
| Net borrowings (repayments) of short-term obligations with three months or less maturity | 135 | | | | 263 | | | (3,114) | |
| Net borrowings (repayments) of short-term obligations | $ | 135 | | | | $ | 263 | | | $ | (5,572) | |
| Net sales (purchases) of treasury shares consists of the following gross and net amounts: | | | | | | |
| Shares issued for share-based compensation plans | $ | 261 | | | | $ | 5,838 | | | $ | 1,421 | |
| Shares purchased under share repurchase and deferred compensation plans | (14,939) | | | | (11,255) | | | (1,383) | |
| Net sales (purchases) of treasury shares | $ | (14,678) | | | | $ | (5,417) | | | $ | 38 | |
| Net contributions from (distributions to) noncontrolling interests consisted of the following gross and net amounts: | | | | | | |
| Distributions to noncontrolling interests | $ | (54) | | | | $ | (118) | | | $ | (53) | |
| Contributions from noncontrolling interests | 14 | | | | 4 | | | 17 | |
| Net contributions from (distributions to) noncontrolling interests | $ | (40) | | | | $ | (114) | | | $ | (36) | |
| | | | | | |
| | | | | | |
The “Other” line in the Operating Activities section includes changes in postretirement benefits obligations and other long-term liabilities.
The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash. “Depreciation, depletion and amortization” and “Deferred income tax provision” collectively include approximately $1,765 in non-cash reductions to “Properties, plant and equipment” and “Investments and advances” in 2023 relating to impairments, mainly of upstream assets in California. “Other income (loss)” and “Deferred income tax provision” collectively include a $1,950 charge related to non-cash increases to “Deferred credits and other noncurrent obligations” related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S. Gulf of Mexico. The cash outlays for these abandonment and decommissioning obligations are expected to take place over the next decade.
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Refer also to Note 25 Asset Retirement Obligations for a discussion of revisions to the company’s AROs that also did not involve cash receipts or payments for the three years ending December 31, 2023. The components of “Capital expenditures” are presented in the following table:
| | | | | | | | | | | | | | | | | | | | |
| Year ended December 31 |
| 2023 | | | 2022 | | 2021 |
Additions to properties, plant and equipment * | $ | 14,788 | | | | $ | 10,349 | | | $ | 7,515 | |
| Additions to investments | 690 | | | | 1,147 | | | 460 | |
| Current-year dry hole expenditures | 326 | | | | 309 | | | 83 | |
| Payments for other assets and liabilities, net | 25 | | | | 169 | | | (2) | |
| Capital expenditures | $ | 15,829 | | | | $ | 11,974 | | | $ | 8,056 | |
* Excludes non-cash movements of $1,559 in 2023, $334 in 2022 and $316 in 2021.
The table below quantifies the beginning and ending balances of restricted cash and restricted cash equivalents in the Consolidated Balance Sheet:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year ended December 31 |
| | | | 2023 | | | 2022 | | 2021 |
| Cash and cash equivalents | | | | $ | 8,178 | | | | $ | 17,678 | | | $ | 5,640 | |
| Restricted cash included in “Prepaid expenses and other current assets” | | | | 275 | | | | 630 | | | 333 | |
| Restricted cash included in “Deferred charges and other assets” | | | | 822 | | | | 813 | | | 822 | |
| Total cash, cash equivalents and restricted cash | | | | $ | 9,275 | | | | $ | 19,121 | | | $ | 6,795 | |
Note 4
New Accounting Standards
Segment Reporting (Topic 280) Improvements to Reportable Segment Disclosures In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) 2023-07, which becomes effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The standard requires companies to disclose significant segment expenses. The company does not expect the standard to have a material effect on its consolidated financial statements and has begun evaluating disclosure presentation alternatives.
Income Taxes (Topic 740) Improvements to Income Tax Disclosures In December 2023, the FASB issued ASU 2023-09, which becomes effective for fiscal years beginning after December 15, 2024. The standard requires companies to disclose specific categories in the income tax rate reconciliation table and the amount of income taxes paid per major jurisdiction. The company does not expect the standard to have a material effect on its consolidated financial statements and has begun evaluating disclosure presentation alternatives.
Note 5
Lease Commitments
The company enters into leasing arrangements as a lessee; any lessor arrangements are not significant. Operating lease arrangements mainly involve land, bareboat charters, terminals, drill ships, drilling rigs, time chartered vessels, office buildings and warehouses, and exploration and production equipment. Finance leases primarily include facilities, vessels and office buildings.
Details of the right-of-use assets and lease liabilities for operating and finance leases, including the balance sheet presentation, are as follows:
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | | | | | | | | | | | | | | | | | | | | | | |
| At December 31, 2023 | | At December 31, 2022 |
| Operating
Leases | | Finance
Leases | | Operating
Leases | | Finance
Leases |
| | | | | | | |
| Deferred charges and other assets | $ | 5,422 | | | $ | — | | | $ | 4,262 | | | $ | — | |
| Properties, plant and equipment, net | — | | | 583 | | | — | | | 392 | |
| Right-of-use assets* | $ | 5,422 | | | $ | 583 | | | $ | 4,262 | | | $ | 392 | |
| Accrued Liabilities | $ | 1,538 | | | $ | — | | | $ | 1,111 | | | $ | — | |
| Short-term Debt | — | | | 60 | | | — | | | 45 | |
| Current lease liabilities | 1,538 | | | 60 | | | 1,111 | | | 45 | |
| Deferred credits and other noncurrent obligations | 3,696 | | | — | | | 2,920 | | | — | |
| Long-term Debt | — | | | 574 | | | — | | | 403 | |
| Noncurrent lease liabilities | 3,696 | | | 574 | | | 2,920 | | | 403 | |
| Total lease liabilities | $ | 5,234 | | | $ | 634 | | | $ | 4,031 | | | $ | 448 | |
| | | | | | | |
| Weighted-average remaining lease term (in years) | 6.7 | | 12.6 | | 7.0 | | 11.9 |
| Weighted-average discount rate | 3.3 | % | | 4.5 | % | | 1.9 | % | | 4.1 | % |
* Includes non-cash additions of $2,556 and $233 in 2023, and $1,807 and $3 in 2022 for right-of-use assets obtained in exchange for new and modified lease liabilities for operating and finance leases, respectively.
Total lease costs consist of both amounts recognized in the Consolidated Statement of Income during the period and amounts capitalized as part of the cost of another asset. Total lease costs incurred for operating and finance leases were as follows:
| | | | | | | | | | | | | | | | | |
| Year-ended December 31 |
| 2023 | | 2022 | | 2021 |
| Operating lease costs* | $ | 2,984 | | | $ | 2,359 | | | $ | 2,199 | |
| Finance lease costs | 52 | | | 57 | | 66 |
| Total lease costs | $ | 3,036 | | | $ | 2,416 | | | $ | 2,265 | |
* Includes variable and short-term lease costs.
Cash paid for amounts included in the measurement of lease liabilities was as follows:
| | | | | | | | | | | | | | | | | |
| Year-ended December 31 |
| 2023 | | 2022 | | 2021 |
| Operating cash flows from operating leases | $ | 2,271 | | | $ | 1,892 | | | $ | 1,670 | |
| Investing cash flows from operating leases | 713 | | | 467 | | | 398 | |
| Operating cash flows from finance leases | 15 | | | 18 | | | 21 | |
| Financing cash flows from finance leases | 42 | | | 44 | | | 193 | |
At December 31, 2023, the estimated future undiscounted cash flows for operating and finance leases were as follows:
| | | | | | | | | | | | | | |
| | At December 31, 2023 |
| | Operating Leases | | Finance
Leases |
| | | | |
| Year | 2024 | $ | 1,673 | | | $ | 84 | |
| 2025 | 1,153 | | | 79 | |
| 2026 | 734 | | | 76 | |
| 2027 | 544 | | | 68 | |
| 2028 | 396 | | | 66 | |
| Thereafter | 1,364 | | | 443 | |
| Total | $ | 5,864 | | | $ | 816 | |
| Less: Amounts representing interest | 630 | | | 182 | |
| Total lease liabilities | $ | 5,234 | | | $ | 634 | |
Additionally, the company has $232 in future undiscounted cash flows for operating leases not yet commenced. These leases are primarily for drill ships, drilling rigs and storage tanks. For those leasing arrangements where the underlying asset is not yet constructed, the lessor is primarily involved in the design and construction of the asset.
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 6
Summarized Financial Data – Chevron U.S.A. Inc.
Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron Corporation. CUSA and its subsidiaries manage and operate most of Chevron’s U.S. businesses. Assets include those related to the exploration and production of crude oil, natural gas liquids and natural gas and those associated with the refining, marketing, supply and distribution of products derived from petroleum, excluding most of the regulated pipeline operations of Chevron. CUSA also holds the company’s investment in the Chevron Phillips Chemical Company LLC joint venture, which is accounted for using the equity method. The summarized financial information for CUSA and its consolidated subsidiaries is as follows:
| | | | | | | | | | | | | | | | | | | | |
| Year ended December 31 |
| 2023 | | | 2022 | | 2021 |
| Sales and other operating revenues | $ | 152,347 | | | | $ | 183,032 | | | $ | 120,380 | |
| Total costs and other deductions | 144,482 | | | | 166,955 | | | 114,641 | |
| Net income (loss) attributable to CUSA | 4,598 | | | | 13,315 | | | 6,904 | |
| | | | | | | | | | | | | | |
| At December 31 |
| 2023 | | | 2022 |
| Current assets | $ | 19,489 | | | | $ | 18,704 | |
| Other assets | 54,460 | | | | 50,153 | |
| Current liabilities | 20,624 | | | | 22,452 | |
| Other liabilities | 22,227 | | | | 19,274 | |
| Total CUSA net equity | $ | 31,098 | | | | $ | 27,131 | |
| Memo: Total debt | $ | 9,740 | | | | $ | 10,800 | |
Note 7
Summarized Financial Data – Tengizchevroil LLP
Chevron has a 50 percent equity ownership interest in Tengizchevroil LLP (TCO). Refer to Note 15 Investments and Advances for a discussion of TCO operations. Summarized financial information for 100 percent of TCO is presented in the table below: | | | | | | | | | | | | | | | | | | | | |
| Year ended December 31 |
| 2023 | | | 2022 | | 2021 |
| Sales and other operating revenues | $ | 19,578 | | | | $ | 23,795 | | | $ | 15,927 | |
| Costs and other deductions | 10,193 | | | | 11,596 | | | 8,186 | |
| Net income attributable to TCO | 6,569 | | | | 8,566 | | | 5,418 | |
| | | | | | | | | | | | | | |
| At December 31 |
| 2023 | | | 2022 |
| Current assets | $ | 3,919 | | | | $ | 6,522 | |
| Other assets | 57,454 | | | | 54,506 | |
| Current liabilities | 2,372 | | | | 3,567 | |
| Other liabilities | 12,782 | | | | 12,312 | |
| Total TCO net equity | $ | 46,219 | | | | $ | 45,149 | |
Note 8
Summarized Financial Data – Chevron Phillips Chemical Company LLC
Chevron has a 50 percent equity ownership interest in Chevron Phillips Chemical Company LLC (CPChem). Refer to Note 15 Investments and Advances for a discussion of CPChem operations. Summarized financial information for 100 percent of CPChem is presented in the table below: | | | | | | | | | | | | | | | | | |
| Year ended December 31 |
| 2023 | | 2022 | | 2021 |
| Sales and other operating revenues | $ | 11,560 | | | $ | 14,180 | | | $ | 14,104 | |
| Costs and other deductions | 10,561 | | | 12,870 | | | 10,862 | |
| Net income attributable to CPChem | 1,173 | | | 1,662 | | | 3,684 | |
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | | | | | | | | | | |
| At December 31 |
| 2023 | | 2022 |
| Current assets | $ | 3,284 | | | $ | 3,472 | |
| Other assets | 16,425 | | | 15,184 | |
| Current liabilities | 1,757 | | | 2,146 | |
| Other liabilities | 3,269 | | | 2,941 | |
| Total CPChem net equity | $ | 14,683 | | | $ | 13,569 | |
Note 9
Fair Value Measurements
The tables below show the fair value hierarchy for assets and liabilities measured at fair value on a recurring and nonrecurring basis at December 31, 2023 and 2022.
Marketable Securities The company calculates fair value for its marketable securities based on quoted market prices for identical assets. The fair values reflect the cash that would have been received if the instruments were sold at December 31, 2023.
Derivatives The company records most of its derivative instruments – other than any commodity derivative contracts that are accounted for as normal purchase and normal sale – on the Consolidated Balance Sheet at fair value, with the offsetting amount to the Consolidated Statement of Income. The company designates certain derivative instruments as cash flow hedges that, if applicable, are reflected in the table below. Derivatives classified as Level 1 include futures, swaps and options contracts valued using quoted prices from active markets such as the New York Mercantile Exchange. Derivatives classified as Level 2 include swaps, options and forward contracts, the fair values of which are obtained from third-party broker quotes, industry pricing services and exchanges. The company obtains multiple sources of pricing information for the Level 2 instruments. Since this pricing information is generated from observable market data, it has historically been very consistent. The company does not materially adjust this information.
Properties, Plant and Equipment In 2023, the company impaired a portion of its U.S. upstream assets, primarily in California, due to continuing regulatory challenges in the state that have resulted in lower anticipated future investment levels in its business plans. The company did not have any individually material impairments of long-lived assets measured at fair value on a nonrecurring basis to report in 2022.
Investments and Advances The company did not have any material impairments of investments and advances measured at fair value on a nonrecurring basis to report in 2023 or 2022.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| At December 31, 2023 | At December 31, 2022 | | | | | | | |
| Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | | | | | | | |
| Marketable securities | $ | 45 | | $ | 45 | | $ | — | | $ | — | | $ | 223 | | $ | 223 | | $ | — | | $ | — | | | | | | | | |
| Derivatives - not designated | 152 | | 24 | | 128 | | — | | 184 | | 111 | | 73 | | — | | | | | | | | |
| Derivatives - designated | 7 | | 7 | | — | | — | | — | | — | | — | | — | | | | | | | | |
| Total assets at fair value | $ | 204 | | $ | 76 | | $ | 128 | | $ | — | | $ | 407 | | $ | 334 | | $ | 73 | | $ | — | | | | | | | | |
| Derivatives - not designated | 262 | | 160 | | 102 | | — | | 43 | | 33 | | 10 | | — | | | | | | | | |
| Derivatives - designated | — | | — | | — | | — | | 15 | | 15 | | — | | — | | | | | | | | |
| | | | | | | | | | | | | | | |
| Total liabilities at fair value | $ | 262 | | $ | 160 | | $ | 102 | | $ | — | | $ | 58 | | $ | 48 | | $ | 10 | | $ | — | | | | | | | | |
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| At December 31 | At December 31 |
| | | | | Before-Tax Loss | | | | | Before-Tax Loss |
| Total | Level 1 | Level 2 | Level 3 | Year 2023 | Total | Level 1 | Level 2 | Level 3 | Year 2022 |
| Properties, plant and equipment, net (held and used) | $ | 484 | | $ | — | | $ | — | | $ | 484 | | $ | 2,175 | | $ | 54 | | $ | — | | $ | — | | $ | 54 | | $ | 518 | |
| Properties, plant and equipment, net (held for sale) | — | | — | | — | | — | | 5 | | — | | — | | — | | — | | 432 | |
| Investments and advances | 207 | | 5 | | 165 | | 37 | | 352 | | 33 | | 2 | | — | | 31 | | 9 | |
| Total nonrecurring assets at fair value | $ | 691 | | $ | 5 | | $ | 165 | | $ | 521 | | $ | 2,532 | | $ | 87 | | $ | 2 | | $ | — | | $ | 85 | | $ | 959 | |
At year-end 2023, the company had assets measured at fair value Level 3 using unobservable inputs of $521. The carrying value of these assets were written down to fair value based on estimates derived from discounted cash flow models. Cash
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
flows were determined using estimates of future production, an outlook of future price based on published prices and a discount rate believed to be consistent with those used by principal market participants.
Assets and Liabilities Not Required to Be Measured at Fair Value The company holds cash equivalents in U.S. and non-U.S. portfolios. The instruments classified as cash equivalents are primarily bank time deposits with maturities of 90 days or less and money market funds. “Cash and cash equivalents” had carrying/fair values of $8,178 and $17,678 at December 31, 2023, and December 31, 2022, respectively. The fair values of cash and cash equivalents are classified as Level 1 and reflect the cash that would have been received if the instruments were settled at December 31, 2023.
“Cash and cash equivalents” do not include investments with a carrying/fair value of $1,097 and $1,443 at December 31, 2023, and December 31, 2022, respectively. At December 31, 2023, these investments are classified as Level 1 and include restricted funds related to certain upstream decommissioning activities, a financing program and tax payments.
Long-term debt, excluding finance lease liabilities, of $14,612 and $16,258 at December 31, 2023, and December 31, 2022, respectively, had estimated fair values of $13,709 and $14,959, respectively. Long-term debt primarily includes corporate issued bonds. The fair value of corporate bonds is $13,321 and classified as Level 1. The fair value of other long-term debt classified as Level 2 is $388.
The carrying values of other short-term financial assets and liabilities on the Consolidated Balance Sheet approximate their fair values. Fair value remeasurements of other financial instruments at December 31, 2023 and 2022, were not material.
Note 10
Financial and Derivative Instruments
Derivative Commodity Instruments The company’s derivative commodity instruments principally include crude oil, natural gas, liquefied natural gas and refined product futures, swaps, options, and forward contracts. The company applies cash flow hedge accounting to certain commodity transactions, where appropriate, to manage the market price risk associated with forecasted sales of crude oil. The company’s derivatives are not material to the company’s financial position, results of operations or liquidity. The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodity derivative activities.
The company uses derivative commodity instruments traded on the New York Mercantile Exchange and on electronic platforms of the Inter-Continental Exchange and Chicago Mercantile Exchange. In addition, the company enters into swap contracts and option contracts principally with major financial institutions and other oil and gas companies in the “over-the-counter” markets, which are governed by International Swaps and Derivatives Association agreements and other master netting arrangements. Depending on the nature of the derivative transactions, bilateral collateral arrangements may also be required.
Derivative instruments measured at fair value at December 31, 2023, 2022 and 2021, and their classification on the Consolidated Balance Sheet and Consolidated Statement of Income are as follows:
Consolidated Balance Sheet: Fair Value of Derivatives
| | | | | | | | | | | | | | | | | |
| | | | | At December 31 |
| Type of Contract | Balance Sheet Classification | 2023 | | | 2022 |
| Commodity | Accounts and notes receivable | $ | 151 | | | | $ | 175 | |
| Commodity | Long-term receivables, net | 8 | | | | 9 | |
| Total assets at fair value | $ | 159 | | | | $ | 184 | |
| Commodity | Accounts payable | $ | 216 | | | | $ | 46 | |
| Commodity | Deferred credits and other noncurrent obligations | 46 | | | | 12 | |
| Total liabilities at fair value | $ | 262 | | | | $ | 58 | |
Consolidated Statement of Income: The Effect of Derivatives
| | | | | | | | | | | | | | | | | | | | | | | |
| | Gain/(Loss) |
| Type of Derivative | Statement of | Year ended December 31 |
| Contract | Income Classification | 2023 | | | 2022 | | 2021 |
| Commodity | Sales and other operating revenues | $ | (304) | | | | $ | (651) | | | $ | (685) | |
| Commodity | Purchased crude oil and products | (154) | | | | (226) | | | (64) | |
| Commodity | Other income (loss) | (47) | | | | 10 | | | (46) | |
| | $ | (505) | | | | $ | (867) | | | $ | (795) | |
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
The amount reclassified from AOCL to “Sales and other operating revenues” from designated hedges was a decrease of $33 in 2023, compared with an increase of $80 in the prior year. At December 31, 2023, before-tax deferred gains in AOCL related to outstanding crude oil price hedging contracts were $7, all of which is expected to be reclassified into earnings during the next 12 months as the hedged crude oil sales are recognized in earnings.
The table below represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated Balance Sheet at December 31, 2023 and 2022.
Consolidated Balance Sheet: The Effect of Netting Derivative Assets and Liabilities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Gross Amounts Recognized | | Gross Amounts Offset | | Net Amounts Presented | | Gross Amounts Not Offset | | Net Amounts |
| At December 31, 2023 | | | | | |
| Derivative Assets - not designated | | $ | 2,394 | | | $ | 2,242 | | | $ | 152 | | | $ | 4 | | | $ | 148 | |
| Derivative Assets - designated | | $ | 8 | | | $ | 1 | | | $ | 7 | | | $ | — | | | $ | 7 | |
| Derivative Liabilities - not designated | | $ | 2,504 | | | $ | 2,242 | | | $ | 262 | | | $ | 15 | | | $ | 247 | |
| Derivative Liabilities - designated | | $ | 1 | | | $ | 1 | | | $ | — | | | $ | — | | | $ | — | |
| At December 31, 2022 | | | | | | | | | | |
| Derivative Assets - not designated | | $ | 2,591 | | | $ | 2,407 | | | $ | 184 | | | $ | 5 | | | $ | 179 | |
| Derivative Assets - designated | | $ | 8 | | | $ | 8 | | | $ | — | | | $ | — | | | $ | — | |
| Derivative Liabilities - not designated | | $ | 2,450 | | | $ | 2,407 | | | $ | 43 | | | $ | — | | | $ | 43 | |
| Derivative Liabilities - designated | | $ | 23 | | | $ | 8 | | | $ | 15 | | | $ | — | | | $ | 15 | |
| | | | | | | | | | |
Derivative assets and liabilities are classified on the Consolidated Balance Sheet as “Accounts and notes receivable,” “Long-term receivables,” “Accounts payable,” and “Deferred credits and other noncurrent obligations.” Amounts not offset on the Consolidated Balance Sheet represent positions that do not meet all the conditions for “a right of offset.”
Concentrations of Credit Risk The company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, marketable securities, derivative financial instruments and trade receivables. The company’s short-term investments are placed with a wide array of financial institutions with high credit ratings. Company investment policies limit the company’s exposure both to credit risk and to concentrations of credit risk. Similar policies on diversification and creditworthiness are applied to the company’s counterparties in derivative instruments. For a discussion of credit risk on trade receivables, see Note 28 Financial Instruments - Credit Losses. Note 11
Assets Held for Sale
At December 31, 2023, the company classified $675 of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. These assets are associated with upstream operations that are anticipated to be sold in the next 12 months. The revenues and earnings contributions of these assets in 2023 were not material.
Note 12
Equity
Retained earnings at December 31, 2023 and 2022, included $34,359 and $33,570, respectively, for the company’s share of undistributed earnings of equity affiliates.
At December 31, 2023, about 101 million shares of Chevron’s common stock remained available for issuance from the 104 million shares that were reserved for issuance under the 2022 Chevron Long-Term Incentive Plan. In addition, 578,044 shares remain available for issuance from the 1,600,000 shares of the company’s common stock that were reserved for awards under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan.
Note 13
Earnings Per Share
Basic earnings per share (EPS) is based upon “Net Income (Loss) Attributable to Chevron Corporation” (“earnings”) and includes the effects of deferrals of salary and other compensation awards that are invested in Chevron stock units by certain officers and employees of the company. Diluted EPS includes the effects of these items as well as the dilutive effects of outstanding stock options awarded under the company’s stock option programs (refer to Note 22 Stock Options and Other Share-Based Compensation). The table below sets forth the computation of basic and diluted EPS:
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | | | | | | | | | | | | | | | | | | | |
| Year ended December 31 |
| 2023 | | | 2022 | | 2021 |
| Basic EPS Calculation | | | | | | |
Earnings available to common stockholders - Basic* | $ | 21,369 | | | | $ | 35,465 | | | $ | 15,625 | |
| Weighted-average number of common shares outstanding | 1,873 | | | | 1,931 | | | 1,916 | |
| Add: Deferred awards held as stock units | — | | | | — | | | — | |
| Total weighted-average number of common shares outstanding | 1,873 | | | | 1,931 | | | 1,916 | |
| Earnings per share of common stock - Basic | $ | 11.41 | | | | $ | 18.36 | | | $ | 8.15 | |
| Diluted EPS Calculation | | | | | | |
Earnings available to common stockholders - Diluted* | $ | 21,369 | | | | $ | 35,465 | | | $ | 15,625 | |
| Weighted-average number of common shares outstanding | 1,873 | | | | 1,931 | | | 1,916 | |
| Add: Deferred awards held as stock units | — | | | | — | | | — | |
| Add: Dilutive effect of employee stock-based awards | 7 | | | | 9 | | | 4 | |
| Total weighted-average number of common shares outstanding | 1,880 | | | | 1,940 | | | 1,920 | |
| Earnings per share of common stock - Diluted | $ | 11.36 | | | | $ | 18.28 | | | $ | 8.14 | |
* There was no effect of dividend equivalents paid on stock units or dilutive impact of employee stock-based awards on earnings. |
|
Note 14
Operating Segments and Geographic Data
Although each subsidiary of Chevron is responsible for its own affairs, Chevron Corporation manages its investments in these subsidiaries and their affiliates. The investments are grouped into two business segments, Upstream and Downstream, representing the company’s “reportable segments” and “operating segments.” Upstream operations consist primarily of exploring for, developing, producing and transporting crude oil and natural gas; liquefaction, transportation and regasification associated with liquefied natural gas (LNG); transporting crude oil by major international oil export pipelines; processing, transporting, storage and marketing of natural gas; carbon capture and storage; and a gas-to-liquids plant. Downstream operations consist primarily of refining of crude oil into petroleum products; marketing of crude oil, refined products, and lubricants; manufacturing and marketing of renewable fuels; transporting of crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant additives. All Other activities of the company include worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology activities.
The company’s segments are managed by “segment managers” who report to the “chief operating decision maker” (CODM). The segments represent components of the company that engage in activities (a) from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the segments and assesses their performance; and (c) for which discrete financial information is available.
The company’s primary country of operation is the United States of America, its country of domicile. Other components of the company’s operations are reported as “International” (outside the United States).
Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Non-billable costs remain at the corporate level in “All Other.” Earnings by major operating area are presented in the following table:
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | | | | | | | | | | | | | | | | | | | |
| Year ended December 31 |
| 2023 | | | 2022 | | 2021 |
| Upstream | | | | | | |
| United States | $ | 4,148 | | | | $ | 12,621 | | | $ | 7,319 | |
| International | 13,290 | | | | 17,663 | | | 8,499 | |
| Total Upstream | 17,438 | | | | 30,284 | | | 15,818 | |
| Downstream | | | | | | |
| United States | 3,904 | | | | 5,394 | | | 2,389 | |
| International | 2,233 | | | | 2,761 | | | 525 | |
| Total Downstream | 6,137 | | | | 8,155 | | | 2,914 | |
| Total Segment Earnings | 23,575 | | | | 38,439 | | | 18,732 | |
| All Other | | | | | | |
| Interest expense | (432) | | | | (476) | | | (662) | |
| Interest income | 491 | | | | 261 | | | 36 | |
| Other | (2,265) | | | | (2,759) | | | (2,481) | |
| Net Income (Loss) Attributable to Chevron Corporation | $ | 21,369 | | | | $ | 35,465 | | | $ | 15,625 | |
Segment Assets Segment assets do not include intercompany investments or receivables. Assets at year-end 2023 and 2022 are as follows:
| | | | | | | | | | | | | | |
| At December 31 |
| 2023 | | | 2022 |
| Upstream | | | | |
| United States | $ | 58,750 | | | | $ | 44,246 | |
| International | 131,685 | | | | 134,489 | |
| Goodwill | 4,370 | | | | 4,370 | |
| Total Upstream | 194,805 | | | | 183,105 | |
| Downstream | | | | |
| United States | 33,066 | | | | 31,676 | |
| International | 21,070 | | | | 21,193 | |
| Goodwill | 352 | | | | 352 | |
| Total Downstream | 54,488 | | | | 53,221 | |
| Total Segment Assets | 249,293 | | | | 236,326 | |
| All Other | | | | |
| United States | 10,292 | | | | 17,861 | |
| International | 2,047 | | | | 3,522 | |
| Total All Other | 12,339 | | | | 21,383 | |
| Total Assets – United States | 102,108 | | | | 93,783 | |
| Total Assets – International | 154,802 | | | | 159,204 | |
| Goodwill | 4,722 | | | | 4,722 | |
| Total Assets | $ | 261,632 | | | | $ | 257,709 | |
Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2023, 2022 and 2021, are presented in the table on the next page. Products are transferred between operating segments at internal product values that approximate market prices.
Revenues for the upstream segment are derived primarily from the production and sale of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the manufacture and sale of fuel and lubricant additives and the transportation and trading of refined products and crude oil. “All Other” activities include revenues from insurance operations, real estate activities and technology companies.
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | | | | | | | | | | | | | | | | | | | |
| Year ended December 31* |
| 2023 | | | 2022 | | 2021 |
| Upstream | | | | | | |
| United States | $ | 40,115 | | | | $ | 50,822 | | | $ | 29,219 | |
| International | 43,805 | | | | 56,156 | | | 40,921 | |
| Subtotal | 83,920 | | | | 106,978 | | | 70,140 | |
| Intersegment Elimination — United States | (26,307) | | | | (29,870) | | | (15,154) | |
| Intersegment Elimination — International | (11,871) | | | | (13,815) | | | (10,994) | |
| Total Upstream | 45,742 | | | | 63,293 | | | 43,992 | |
| Downstream | | | | | | |
| United States | 83,567 | | | | 91,824 | | | 57,209 | |
| International | 78,058 | | | | 87,741 | | | 58,098 | |
| Subtotal | 161,625 | | | | 179,565 | | | 115,307 | |
| Intersegment Elimination — United States | (8,793) | | | | (5,529) | | | (2,296) | |
| Intersegment Elimination — International | (1,794) | | | | (1,728) | | | (1,521) | |
| Total Downstream | 151,038 | | | | 172,308 | | | 111,490 | |
| All Other | | | | | | |
| United States | 595 | | | | 515 | | | 506 | |
| International | 2 | | | | 3 | | | 2 | |
| Subtotal | 597 | | | | 518 | | | 508 | |
| Intersegment Elimination — United States | (462) | | | | (400) | | | (382) | |
| Intersegment Elimination — International | (2) | | | | (2) | | | (2) | |
| Total All Other | 133 | | | | 116 | | | 124 | |
| Sales and Other Operating Revenues | | | | | | |
| United States | 124,277 | | | | 143,161 | | | 86,934 | |
| International | 121,865 | | | | 143,900 | | | 99,021 | |
| Subtotal | 246,142 | | | | 287,061 | | | 185,955 | |
| Intersegment Elimination — United States | (35,562) | | | | (35,799) | | | (17,832) | |
| Intersegment Elimination — International | (13,667) | | | | (15,545) | | | (12,517) | |
| Total Sales and Other Operating Revenues | $ | 196,913 | | | | $ | 235,717 | | | $ | 155,606 | |
*Other than the United States, no other country accounted for 10 percent or more of the company’s Sales and Other Operating Revenues.
Segment Income Taxes Segment income tax expense for the years 2023, 2022 and 2021 is as follows:
| | | | | | | | | | | | | | | | | | | | |
| Year ended December 31 |
| 2023 | | | 2022 | | 2021 |
| Upstream | | | | | | |
| United States | $ | 1,141 | | | | $ | 3,678 | | | $ | 1,934 | |
| International | 5,733 | | | | 9,055 | | | 4,192 | |
| Total Upstream | 6,874 | | | | 12,733 | | | 6,126 | |
| Downstream | | | | | | |
| United States | 1,109 | | | | 1,515 | | | 547 | |
| International | 519 | | | | 280 | | | 203 | |
| Total Downstream | 1,628 | | | | 1,795 | | | 750 | |
| All Other | (329) | | | | (462) | | | (926) | |
| Total Income Tax Expense (Benefit) | $ | 8,173 | | | | $ | 14,066 | | | $ | 5,950 | |
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 15
Investments and Advances
Equity in earnings, together with investments in and advances to companies accounted for using the equity method and other investments accounted for at or below cost, is shown in the following table. For certain equity affiliates, Chevron pays its share of some income taxes directly. For such affiliates, the equity in earnings does not include these taxes, which are reported on the Consolidated Statement of Income as “Income tax expense.”
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Investments and Advances | | Equity in Earnings |
| At December 31 | | Year ended December 31 |
| 2023 | | 2022 | | 2023 | | 2022 | | 2021 |
| Upstream | | | | | | | | | |
| Tengizchevroil | $ | 26,954 | | | $ | 26,534 | | | $ | 3,375 | | | $ | 4,386 | | | $ | 2,831 | |
| | | | | | | | | |
| | | | | | | | | |
| Caspian Pipeline Consortium | 797 | | | 761 | | | 158 | | | 128 | | | 155 | |
| Angola LNG Limited | 1,762 | | | 1,963 | | | 513 | | | 1,857 | | | 336 | |
| | | | | | | | | |
| Other | 2,106 | | | 1,938 | | | (161) | | | 255 | | | 187 | |
| Total Upstream | 31,619 | | | 31,196 | | | 3,885 | | | 6,626 | | | 3,509 | |
| Downstream | | | | | | | | | |
| Chevron Phillips Chemical Company LLC | 7,765 | | | 6,843 | | | 608 | | | 867 | | | 1,842 | |
| GS Caltex Corporation | 4,309 | | | 4,288 | | | 437 | | | 874 | | | 85 | |
| Other | 2,426 | | | 2,288 | | | 210 | | | 224 | | | 220 | |
| Total Downstream | 14,500 | | | 13,419 | | | 1,255 | | | 1,965 | | | 2,147 | |
| All Other | | | | | | | | | |
| Other | (6) | | | (5) | | | (9) | | | (6) | | | 1 | |
| Total equity method | $ | 46,113 | | | $ | 44,610 | | | $ | 5,131 | | | $ | 8,585 | | | $ | 5,657 | |
| Other non-equity method investments | 699 | | | 628 | | | | | | | |
| Total investments and advances | $ | 46,812 | | | $ | 45,238 | | | | | | | |
| Total United States | $ | 10,985 | | | $ | 9,855 | | | $ | 340 | | | $ | 975 | | | $ | 1,889 | |
| Total International | $ | 35,827 | | | $ | 35,383 | | | $ | 4,791 | | | $ | 7,610 | | | $ | 3,768 | |
Descriptions of major equity affiliates and non-equity investments, including significant differences between the company’s carrying value of its investments and its underlying equity in the net assets of the affiliates, are as follows:
Tengizchevroil Chevron has a 50 percent equity ownership interest in Tengizchevroil (TCO), which operates the Tengiz and Korolev crude oil fields in Kazakhstan. At December 31, 2023, the company’s carrying value of its investment in TCO was about $80 higher than the amount of underlying equity in TCO’s net assets. This difference results from Chevron acquiring a portion of its interest in TCO at a value greater than the underlying book value for that portion of TCO’s net assets. Included in the investment is a loan to TCO to fund the development of the FGP/WPMP with a principal balance of $4,500.
Caspian Pipeline Consortium Chevron has a 15 percent interest in the Caspian Pipeline Consortium, which provides the critical export route for crude oil from both TCO and Karachaganak.
Angola LNG Limited Chevron has a 36.4 percent interest in Angola LNG Limited, which processes and liquefies natural gas produced in Angola for delivery to international markets.
Chevron Phillips Chemical Company LLC Chevron owns 50 percent of Chevron Phillips Chemical Company LLC. Included in the investment balance is a loan with a principal balance of $387 to fund a portion of the Golden Triangle Polymers Project in Orange, Texas, in which Chevron Phillips Chemical Company LLC owns 51 percent.
GS Caltex Corporation Chevron owns 50 percent of GS Caltex Corporation, a joint venture with GS Energy in South Korea. The joint venture imports, produces and markets petroleum products, petrochemicals and lubricants.
Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $13,623, $16,286 and $10,796 with affiliated companies for 2023, 2022 and 2021, respectively. “Purchased crude oil and products” includes $7,404, $10,171 and $5,778 with affiliated companies for 2023, 2022 and 2021, respectively.
“Accounts and notes receivable” on the Consolidated Balance Sheet includes $1,480 and $907 due from affiliated companies at December 31, 2023 and 2022, respectively. “Accounts payable” includes $591 and $709 due to affiliated companies at December 31, 2023 and 2022, respectively.
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
The following table provides summarized financial information on a 100 percent basis for all equity affiliates as well as Chevron’s total share, which includes Chevron’s net loans to affiliates of $4,494, $4,278 and $4,704 at December 31, 2023, 2022 and 2021, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Affiliates | | | Chevron Share |
| Year ended December 31 | 2023 | | 2022 | | 2021 | | | 2023 | | 2022 | | 2021 |
| Total revenues | $ | 49,306 | | | $ | 100,184 | | | $ | 71,241 | | | | $ | 23,217 | | | $ | 48,323 | | | $ | 34,359 | |
| Income before income tax expense* | 15,304 | | | 23,811 | | | 15,175 | | | | 7,209 | | | 10,876 | | | 6,984 | |
| Net income attributable to affiliates | 11,618 | | | 19,077 | | | 12,598 | | | | 5,485 | | | 8,595 | | | 5,670 | |
| At December 31 | | | | | | | | | | | | |
| Current assets | $ | 22,772 | | | $ | 26,632 | | | $ | 21,871 | | | | $ | 10,110 | | | $ | 11,671 | | | $ | 9,267 | |
| Noncurrent assets | 105,965 | | | 101,557 | | | 100,235 | | | | 48,753 | | | 46,428 | | | 44,360 | |
| Current liabilities | 14,085 | | | 16,319 | | | 17,275 | | | | 6,698 | | | 7,708 | | | 7,492 | |
| Noncurrent liabilities | 23,797 | | | 22,943 | | | 24,219 | | | | 6,342 | | | 5,980 | | | 5,982 | |
| Total affiliates’ net equity | $ | 90,855 | | | $ | 88,927 | | | $ | 80,612 | | | | $ | 45,823 | | | $ | 44,411 | | | $ | 40,153 | |
* Chevron’s net income attributable to affiliates is recorded in the company’s before-tax consolidated earnings in accordance with U.S. Generally Accepted Accounting Principles. The total income tax expense recorded by the company’s equity affiliates in 2023 was $3,686, with Chevron’s share being $1,724.
Note 16
Litigation
Ecuador
In 2003, Chevron was sued in Ecuador for environmental harm allegedly caused by an oil consortium formerly operated by a Texaco subsidiary. The Ecuadorian trial court entered judgment against Chevron, and Ecuador’s highest Constitutional Court affirmed the judgment for approximately $9.5 billion. In 2017, Chevron obtained a final court ruling in the United States determining that the Ecuadorian judgment had been procured through fraud, bribery, and corruption, and prohibiting the Ecuadorian plaintiffs and their cohorts from seeking to enforce the Ecuadorian judgment in the United States or profiting from their illegal acts. The Ecuadorian plaintiffs sought to have the Ecuadorian judgment recognized and enforced in Canada, Brazil, and Argentina, but all of those actions were dismissed in Chevron’s favor.
In 2009, Chevron filed an arbitration claim against Ecuador before an arbitral tribunal administered by the Permanent Court of Arbitration in The Hague, under the United States-Ecuador Bilateral Investment Treaty. In 2018, the tribunal ruled in Chevron’s favor, finding that the Ecuadorian judgment was procured through fraud, bribery, and corruption and was based on environmental claims that Ecuador had already settled and released. The tribunal ruled that the Ecuadorian judgment “violates international public policy” and “should not be recognized or enforced by the courts of other States,” and ordered Ecuador to remove the judgment’s status of enforceability and to compensate Chevron for its injuries in an amount to be established separately by the tribunal. Ecuador’s requests to have a Dutch court set aside the tribunal’s award were denied, and the Dutch Supreme Court affirmed such denial in a final ruling in favor of Chevron in November 2023.
Management continues to believe that the Ecuadorian judgment is illegitimate and unenforceable and will vigorously defend against any further attempts to have it recognized or enforced.
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Climate Change
Governmental and other entities in various jurisdictions across the United States have brought legal proceedings against fossil fuel producing companies, including Chevron entities, purporting to seek legal and equitable relief to address alleged impacts of climate change. Chevron entities are or were among the codefendants in 29 separate lawsuits filed by various U.S. cities and counties, four U.S. states, the District of Columbia, two Native American tribes, and a trade group in both federal and state courts.1 One of the city lawsuits was dismissed on the merits and two suits, including one of the county lawsuits and the case brought by the trade association, were voluntarily dismissed by the plaintiffs. The lawsuits have asserted various causes of action, including public nuisance, private nuisance, failure to warn, fraud, conspiracy to commit fraud, design defect, product defect, trespass, negligence, impairment of public trust, equitable relief for pollution, impairment and destruction of natural resources, unjust enrichment, violations of consumer protection statutes, violations of unfair competition statutes, violations of a federal antitrust statute, and violations of federal and state RICO statutes, based upon, among other things, the company’s production of oil and gas products and alleged misrepresentations or omissions relating to climate change risks associated with those products. Further such proceedings are likely to be brought by other parties. While defendants have sought to remove cases filed in state court to federal court, most of those cases have been remanded to state court and the U.S. Supreme Court has denied petitions for writ of certiorari on jurisdictional questions to date. The unprecedented legal theories set forth in these proceedings include claims for damages (both compensatory and punitive), injunctive and other forms of equitable relief, including without limitation abatement, contribution to abatement funds, disgorgement of profits and equitable relief for pollution, impairment and destruction of natural resources, civil penalties and liability for fees and costs of suits. Due to the unprecedented nature of the suits, the company is unable to estimate any range of possible liability, but given the uncertainty of litigation there can be no assurance that the cases will not have a material adverse effect on the company’s results of operations and financial condition. Management believes that these proceedings are legally and factually meritless and detract from constructive efforts to address the important policy issues presented by climate change and will vigorously defend against such proceedings.
1 The cases are: Bayamon v. Exxon Mobil Corp., et al., No. 22-cv-1550 (D.P.R.); City of Annapolis v. BP P.L.C., et al., No. C-02-CV-21-000250 (Md. Cir. Ct.); County of Anne Arundel v. BP P.L.C., et al., No. C-02-CV-21-000565 (Md. Cir. Ct.); Mayor and City Council of Baltimore v. BP P.L.C., et al., No. 24-C-18-004219 (Md. Cir. Ct.); People ex rel. Bonta v. Exxon Mobil Corp., et al., No. CGC-23-609134 (Cal. Super. Ct.); City of Charleston v. Brabham Oil Co., et al., No. 20-CP-10-3975 (S.C. Ct. of Common Pleas); District of Columbia v. Exxon Mobil Corp., et al., No. 2020-CA-002892-B (D.C. Super. Ct.); Delaware ex rel. Jennings v. BP America Inc., et al., No. N20C-09-097 (Del.Super. Ct.); City of Hoboken v. Exxon Mobil Corp., et al., No. HUD-L-003179-20 (N.J. Super. Ct.); City and County of Honolulu, et al. v. Sunoco LP, et al., No. 1CCV-20-0000380 (Haw. Cir. Ct.); City of Imperial Beach v. Chevron Corp., et al., No. C17-01227 (Cal. Super. Ct.); King County v. BP P.L.C., et al., No. 18-2-11859-0 (Wash. Super. Ct.) (voluntarily dismissed); Makah Indian Tribe v. Exxon Mobil Corp., et al., No. 23-25216-1-SEA (Wash. Super. Ct.); County of Marin v. Chevron Corp., et al., No. 17-cv-02586 (Cal. Super. Ct.); County of Maui v. Sunoco LP, et al., No. 2CCV-20-0000283 (Haw. Cir. Ct.); County of Multnomah v. Exxon Mobil Corp., et al., No. 23-cv-25164 (Or. Cir. Ct.); Municipality of San Juan, Puerto Rico v. Exxon Mobil Corp., et al., No. 23-cv-01608 (D.P.R.); City of Oakland v. BP p.l.c., et al., No. RG17875889 (Cal. Super. Ct.); Platkin, et al. v. Exxon Mobil Corp., et al., No. MER-L-001797-22 (N.J. Super. Ct.); City of New York v. Chevron Corp., et al., No. 18-cv-00182 (S.D.N.Y.) (dismissed on the merits); Pacific Coast Federation of Fishermen’s Associations v. Chevron Corp., et al., No. CGC-18-571285 (Cal. Super. Ct.) (voluntarily dismissed); State of Rhode Island v. Chevron Corp., et al., No. PC-2018-4716 (R.I. Super. Ct.); City of Richmond v. Chevron Corp., et al., No. C18-00055 (Cal. Super. Ct.); City of San Francisco v. BP P.L.C., et al., No. CGC-17-561370 (Cal. Super. Ct.); County of San Mateo v. Chevron Corp., et al., No. 17-CIV-03222 (Cal. Super. Ct.); City of Santa Cruz v. Chevron Corp., et al., No. 17-cv-03243 (Cal. Super. Ct.); County of Santa Cruz v. Chevron Corp., et al., No. 17-cv-03242 (Cal. Super. Ct.); Shoalwater Bay Indian Tribe v. Exxon Mobil Corp., et al., No. 23-2-25215-2-SEA (Wash. Super. Ct.); City of Chicago v. BP p.l.c., et al., No. 2024-CH-01024 (Ill. Cir. Ct.).
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Louisiana
Seven coastal parishes and the State of Louisiana have filed lawsuits in Louisiana against numerous oil and gas companies seeking damages for coastal erosion in or near oil fields located within Louisiana’s coastal zone under Louisiana’s State and Local Coastal Resources Management Act (SLCRMA). Chevron entities are defendants in 39 of these cases.2 The lawsuits allege that the defendants’ historical operations were conducted without necessary permits or failed to comply with permits obtained and seek damages and other relief, including the costs of restoring coastal wetlands allegedly impacted by oil field operations. Further such proceedings may be filed by other parties. The Supreme Court denied a petition for writ of certiorari on jurisdictional questions impacting certain of these cases, and those cases have been or will be remanded to Louisiana state court. Federal jurisdictional questions are still being decided for the remaining cases in the United States Court of Appeals for the Fifth Circuit. A case has been set for trial in the United States District Court for the Eastern District of Louisiana and is scheduled to begin in October 2024. Due to the unprecedented nature of the suits, the company is unable to estimate any range of possible liability, but given the uncertainty of litigation there can be no assurance that the cases will not have a material adverse effect on the company’s results of operations and financial condition. Management believes that the claims lack legal and factual merit and will continue to vigorously defend against such proceedings.
2 The cases are: Jefferson Parish v. Atlantic Richfield Company, et al., No. 732-768 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Chevron U.S.A. Holdings, Inc., et al., No. 732-769 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Destin Operating Company, Inc., et al., No. 732-770 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Canlan Oil Company, et al., No. 732-771 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Anadarko E&P Onshore LLC, et al., No. 732-772 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. ExxonMobil Corporation, et al., No. 732-774 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Equitable Petroleum Corporation, et al., No. 732-775 (24th Jud. Dist. Ct., Jefferson Par.); Plaquemines Parish v. ConocoPhillips Co., et al., No. 60-982 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. HHE Energy Co., et al., No. 60-983 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Exchange Oil & Gas Corp., et al., No. 60-984 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. LLOG Exploration & Production Co., et al., No. 60-985 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Equitable Petroleum Corporation, et al., No. 60-986 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. June Energy, et al., No. 60-987 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Linder Oil Company, et al., No. 60-988 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Riverwood Production Company, et al., No. 60-989 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Helis Oil & Gas Company, et al., No. 60-990 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Northcoast Oil Company, et al., No. 60-992 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Goodrich Petroleum Company, L.L.C., et al., No. 60-994 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Devon Energy Production Company, L.P., et al., No. 60-995 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Rozel Operating Co., et al., No. 60-996 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Palm Energy Offshore, L.L.C., et al., No. 60-997 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Great Southern Oil & Gas Company, Inc., et al., No. 60-998 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Hilcorp Energy Company, et al., No. 60-999 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Apache Oil Corporation, et al., No. 61-000 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Campbell Energy Corporation, et al., No. 61-001 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. TotalPetrochemicals & Refining USA, Inc., et al., No. 61-002 (25th Jud. Dist. Ct., Plaquemines Par.); Cameron Parish v. Alpine Exploration Companies, Inc., et al., No. 10-19580 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Anadarko E&P Onshore, LLC, et al., No. 10-19578 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Apache Corporation (of Delaware), et al., No. 10-19579 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Auster Oil & Gas, Inc., et al., No. 10-19582 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Ballard Exploration Company, Inc., et al., No. 10-19574 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Bay Coquille, Inc., et al., No. 10-19581 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. BEPCO, LP, et al., No. 10-19572 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. BP America Production Company, et al., No. 10-19576 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Brammer Engineering, Inc., et al., No. 10-19573 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Burlington Resources, et al., No. 10-19575 (38th Jud. Dist. Ct., Cameron Par.); Stutes v. Gulfport Energy Corporation, et al., No. 102,146 (15th Jud. Dist. Ct., Vermilion Par.); St. Bernard Parish v. Atlantic Richfield, et al., No. 16-1228 (34th Jud. Dist. Ct. St., Bernard Par.); City of New Orleans v. Apache Louisiana Mins, LLC, et al., No. 19-cv-08290, (E.D. La.).
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 17
Taxes
| | | | | | | | | | | | | | | | | | | | |
| Income Taxes | Year ended December 31 |
| 2023 | | | 2022 | | 2021 |
| Income tax expense (benefit) | | | | | | |
| U.S. federal | | | | | | |
| Current | $ | 895 | | | | $ | 1,723 | | | $ | 174 | |
| Deferred | 666 | | | | 2,240 | | | 1,004 | |
| State and local | | | | | | |
| Current | 211 | | | | 482 | | | 222 | |
| Deferred | 1 | | | | 39 | | | 202 | |
| Total United States | 1,773 | | | | 4,484 | | | 1,602 | |
| International | | | | | | |
| Current | 6,745 | | | | 9,738 | | | 4,854 | |
| Deferred | (345) | | | | (156) | | | (506) | |
| Total International | 6,400 | | | | 9,582 | | | 4,348 | |
| Total income tax expense (benefit) | $ | 8,173 | | | | $ | 14,066 | | | $ | 5,950 | |
The reconciliation between the U.S. statutory federal income tax rate and the company’s effective income tax rate is detailed in the following table:
| | | | | | | | | | | | | | | | | | | | |
| |
| Year ended December 31 |
| 2023 | | | 2022 | | 2021 |
| Income (loss) before income taxes | | | | | | |
| United States | $ | 8,565 | | | | $ | 21,005 | | | $ | 9,674 | |
| International | 21,019 | | | | 28,669 | | | 11,965 | |
| Total income (loss) before income taxes | 29,584 | | | | 49,674 | | | 21,639 | |
| Theoretical tax (at U.S. statutory rate of 21%) | 6,213 | | | | 10,432 | | | 4,544 | |
| | | | | | |
| Equity affiliate accounting effect | (1,072) | | | | (1,678) | | | (890) | |
| Effect of income taxes from international operations | 3,001 | | | | 5,041 | | | 2,692 | |
| State and local taxes on income, net of U.S. federal income tax benefit | 252 | | | | 508 | | | 216 | |
Prior year tax adjustments, claims and settlements 1 | (32) | | | | (90) | | | 362 | |
| Tax credits | (20) | | | | (6) | | | (173) | |
Other U.S. 1, 2 | (169) | | | | (141) | | | (801) | |
| Total income tax expense (benefit) | $ | 8,173 | | | | $ | 14,066 | | | $ | 5,950 | |
| | | | | | |
Effective income tax rate 3 | 27.6 | % | | | 28.3 | % | | 27.5 | % |
1 Includes one-time tax costs (benefits) associated with changes in uncertain tax positions.
2 Includes one-time tax costs (benefits) associated with changes in valuation allowances (2023 - $(84); 2022 - $(36); 2021 - $(624)).
3 The company’s effective tax rate is reflective of equity income reported on an after-tax basis as part of the “Total Income (Loss) Before Income Tax Expense,” in accordance with U.S. Generally Accepted Accounting Principles. Chevron’s share of its equity affiliates’ total income tax expense in 2023 was $1,724.
The 2023 decrease in income tax expense of $5,893 is a result of the year-over-year decrease in total income before income tax expense, which is primarily due to lower upstream realizations and downstream margins. The company’s effective tax rate changed from 28.3 percent in 2022 to 27.6 percent in 2023. The change in effective tax rate is mainly due to mix effects resulting from the absolute level of earnings or losses and whether they arose in higher or lower tax rate jurisdictions.
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
The company records its deferred taxes on a tax-jurisdiction basis. The reported deferred tax balances are composed of the following:
| | | | | | | | | | | | | | |
| | | | At December 31 |
| 2023 | | | 2022 |
| Deferred tax liabilities | | | | |
| Properties, plant and equipment | $ | 20,303 | | | | $ | 18,295 | |
| Investments and other | 4,263 | | | | 4,492 | |
| Total deferred tax liabilities | 24,566 | | | | 22,787 | |
| Deferred tax assets | | | | |
| Foreign tax credits | (13,560) | | | | (12,599) | |
| Asset retirement obligations/environmental reserves | (4,543) | | | | (4,518) | |
| Employee benefits | (1,785) | | | | (2,087) | |
| Deferred credits | (268) | | | | (446) | |
| Tax loss carryforwards | (3,492) | | | | (3,887) | |
| Other accrued liabilities | (1,416) | | | | (746) | |
| Inventory | (126) | | | | (219) | |
| Operating leases | (1,479) | | | | (1,134) | |
| Miscellaneous | (3,652) | | | | (4,057) | |
| Total deferred tax assets | (30,321) | | | | (29,693) | |
| Deferred tax assets valuation allowance | 20,416 | | | | 19,532 | |
| Total deferred taxes, net | $ | 14,661 | | | | $ | 12,626 | |
Deferred tax liabilities increased by $1,779 from year-end 2022, driven by an increase to properties, plant and equipment. Deferred tax assets increased by $628 from year-end 2022. This increase was primarily related to increases in foreign tax credits and other accrued liabilities, partially offset by decreases in tax loss carryforwards and employee benefits.
The overall valuation allowance relates to deferred tax assets for U.S. foreign tax credit carryforwards, tax loss carryforwards and temporary differences. The valuation allowance reduces the deferred tax assets to amounts that are, in management’s assessment, more likely than not to be realized. At the end of 2023, the company had gross tax loss carryforwards of approximately $9,600 and tax credit carryforwards of approximately $260, primarily related to various international tax jurisdictions. Whereas some of these tax loss carryforwards do not have an expiration date, others expire at various times from 2024 through 2042. U.S. foreign tax credit carryforwards of $13,560 will expire between 2024 and 2033.
At December 31, 2023 and 2022, deferred taxes were classified on the Consolidated Balance Sheet as follows:
| | | | | | | | | | | | | | |
| At December 31 |
| 2023 | | | 2022 |
| Deferred charges and other assets | $ | (4,169) | | | | $ | (4,505) | |
| Noncurrent deferred income taxes | 18,830 | | | | 17,131 | |
| Total deferred income taxes, net | $ | 14,661 | | | | $ | 12,626 | |
Income taxes, including U.S. state and foreign withholding taxes, are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely, or where no taxable temporary differences exist that are attributable to unremitted earnings from an investment in a foreign entity. The indefinite reinvestment assertion continues to apply for the purpose of determining deferred tax liabilities for U.S. state and foreign withholding tax purposes. It is not practicable to estimate the amount of state and foreign withholding taxes that might be payable on the possible remittance of earnings that are intended to be reinvested indefinitely. The company does not anticipate incurring significant additional taxes on remittances of earnings that are not indefinitely reinvested.
Uncertain Income Tax Positions The company recognizes a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that the position is more likely than not (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in the accounting standards for income taxes refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods.
The following table indicates the changes to the company’s unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021. The term “unrecognized tax benefits” in the accounting standards for income taxes refers to the
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
differences between a tax position taken or expected to be taken in a tax return and the benefit measured and recognized in the financial statements. Interest and penalties are not included.
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | | 2022 | | 2021 |
| Balance at January 1 | $ | 5,323 | | | | $ | 5,288 | | | $ | 5,018 | |
| Foreign currency effects | (27) | | | | (2) | | | (1) | |
| Additions based on tax positions taken in current year | 248 | | | | 30 | | | 194 | |
| Additions for tax positions taken in prior years | 265 | | | | 234 | | | 218 | |
| Reductions based on tax positions taken in current year | (104) | | | | — | | | — | |
| Reductions for tax positions taken in prior years | (251) | | | | (117) | | | (36) | |
| Settlements with taxing authorities in current year | (2) | | | | (110) | | | (18) | |
| Reductions as a result of a lapse of the applicable statute of limitations | — | | | | — | | | (87) | |
| Balance at December 31 | $ | 5,452 | | | | $ | 5,323 | | | $ | 5,288 | |
Approximately 79 percent of the $5,452 of unrecognized tax benefits at December 31, 2023, would have an impact on the effective tax rate if subsequently recognized. Certain of these unrecognized tax benefits relate to tax carryforwards that may require a full valuation allowance at the time of any such recognition.
The company and its subsidiaries are subject to income taxation and audits throughout the world. With certain exceptions, income tax examinations are completed through 2016 for the United States and 2007 for other major jurisdictions.
The company engages in ongoing discussions with tax authorities regarding the resolution of tax matters in the various jurisdictions. Both the outcome of these tax matters and the timing of resolution and/or closure of the tax audits are highly uncertain. Given the number of years that still remain subject to examination and the number of matters being examined in the various tax jurisdictions, the company is unable to estimate the range of possible adjustments to the balance of unrecognized tax benefits.
On the Consolidated Statement of Income, the company reports interest and penalties related to liabilities for uncertain tax positions as “Income Tax Expense (Benefit).” As of December 31, 2023, accrued expense of $229 for anticipated interest and penalties was included on the Consolidated Balance Sheet, compared with accrued benefit of $112 as of year-end 2022. Income tax expense (benefit) associated with interest and penalties was $124, $152 and $19 in 2023, 2022 and 2021, respectively.
| | | | | | | | | | | | | | | | | | | | |
| Taxes Other Than on Income | | | | | | |
| Year ended December 31 |
| 2023 | | | 2022 | | 2021 |
| United States | | | | | | |
| Import duties and other levies | $ | (9) | | | | $ | 10 | | | $ | 7 | |
| Property and other miscellaneous taxes | 818 | | | | 609 | | | 552 | |
| Payroll taxes | 286 | | | | 248 | | | 302 | |
| Taxes on production | 801 | | | | 989 | | | 628 | |
| Total United States | 1,896 | | | | 1,856 | | | 1,489 | |
| International | | | | | | |
| Import duties and other levies | 72 | | | | 63 | | | 49 | |
| Property and other miscellaneous taxes | 2,004 | | | | 1,789 | | | 2,174 | |
| Payroll taxes | 121 | | | | 122 | | | 113 | |
| Taxes on production | 127 | | | | 202 | | | 138 | |
| Total International | 2,324 | | | | 2,176 | | | 2,474 | |
| Total taxes other than on income | $ | 4,220 | | | | $ | 4,032 | | | $ | 3,963 | |
|
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 18
Properties, Plant and Equipment1
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| At December 31 | | Year ended December 31 |
| Gross Investment at Cost | | Net Investment | | Additions at Cost2 | | Depreciation Expense3 |
| 2023 | 2022 | 2021 | | 2023 | 2022 | 2021 | | 2023 | 2022 | 2021 | | 2023 | 2022 | 2021 |
| Upstream | | | | | | | | | | | | | | | |
| United States | $ | 117,955 | | $ | 96,590 | | $ | 93,393 | | | $ | 50,390 | | $ | 37,031 | | $ | 36,027 | | | $ | 20,408 | | $ | 6,461 | | $ | 4,520 | | | $ | 7,666 | | $ | 5,012 | | $ | 5,675 | |
| International | 183,996 | | 188,556 | | 202,757 | | | 84,561 | | 88,549 | | 94,770 | | | 4,130 | | 2,599 | | 2,349 | | | 8,109 | | 9,830 | | 10,824 | |
| Total Upstream | 301,951 | | 285,146 | | 296,150 | | | 134,951 | | 125,580 | | 130,797 | | | 24,538 | | 9,060 | | 6,869 | | | 15,775 | | 14,842 | | 16,499 | |
| Downstream | | | | | | | | | | | | | | | |
| United States | 31,192 | | 29,802 | | 26,888 | | | 13,521 | | 12,827 | | 10,766 | | | 1,623 | | 2,742 | | 543 | | | 931 | | 913 | | 833 | |
| International | 8,401 | | 8,281 | | 8,134 | | | 3,122 | | 3,226 | | 3,300 | | | 237 | | 246 | | 234 | | | 301 | | 311 | | 296 | |
| Total Downstream | 39,593 | | 38,083 | | 35,022 | | | 16,643 | | 16,053 | | 14,066 | | | 1,860 | | 2,988 | | 777 | | | 1,232 | | 1,224 | | 1,129 | |
| All Other | | | | | | | | | | | | | | | |
| United States | 4,390 | | 4,402 | | 4,729 | | | 1,991 | | 1,931 | | 2,078 | | | 311 | | 230 | | 143 | | | 313 | | 247 | | 290 | |
| International | 147 | | 154 | | 144 | | | 34 | | 27 | | 20 | | | 15 | | 12 | | 7 | | | 6 | | 6 | | 7 | |
| Total All Other | 4,537 | | 4,556 | | 4,873 | | | 2,025 | | 1,958 | | 2,098 | | | 326 | | 242 | | 150 | | | 319 | | 253 | | 297 | |
| Total United States | 153,537 | | 130,794 | | 125,010 | | | 65,902 | | 51,789 | | 48,871 | | | 22,342 | | 9,433 | | 5,206 | | | 8,910 | | 6,172 | | 6,798 | |
| Total International | 192,544 | | 196,991 | | 211,035 | | | 87,717 | | 91,802 | | 98,090 | | | 4,382 | | 2,857 | | 2,590 | | | 8,416 | | 10,147 | | 11,127 | |
| Total | $ | 346,081 | | $ | 327,785 | | $ | 336,045 | | | $ | 153,619 | | $ | 143,591 | | $ | 146,961 | | | $ | 26,724 | | $ | 12,290 | | $ | 7,796 | | | $ | 17,326 | | $ | 16,319 | | $ | 17,925 | |
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 2023. Australia had PP&E of $41,409, $44,012 and $46,687 in 2023, 2022 and 2021, respectively. Gross Investment at Cost and Additions at Cost for 2023 each include $10,487 associated with the PDC acquisition.
2Net of dry hole expense related to prior years’ expenditures of $110, $177 and $35 in 2023, 2022 and 2021, respectively.
3Depreciation expense includes accretion expense of $593, $560 and $616 in 2023, 2022 and 2021, respectively, and impairments and write-offs of $2,180, $950 and $414 in 2023, 2022 and 2021, respectively.
Note 19
Short-Term Debt
| | | | | | | | | | | | | | |
| At December 31 |
| 2023 | | | 2022 |
| Commercial paper | $ | — | | | | $ | — | |
| Notes payable to banks and others with originating terms of one year or less | 469 | | | | 328 | |
Current maturities of long-term debt* | 1,667 | | | | 2,699 | |
| Current maturities of long-term finance leases | 60 | | | | 45 | |
| Redeemable long-term obligations | 2,876 | | | | 2,942 | |
| | | | |
| Subtotal | 5,072 | | | | 6,014 | |
| Reclassified to long-term debt | (4,543) | | | | (4,050) | |
| Total short-term debt | $ | 529 | | | | $ | 1,964 | |
* Inclusive of unamortized premiums of $17 at December 31, 2023 and $5 at December 31, 2022. | | | | |
| | | | |
Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date.
The company may periodically enter into interest rate swaps on a portion of its short-term debt. At December 31, 2023, the company had no interest rate swaps on short-term debt.
At December 31, 2023, the company had $8,050 in 364-day committed credit facilities with various major banks that enable the refinancing of short-term obligations on a long-term basis. The credit facilities allow the company to convert any amounts outstanding into a term loan for a period of up to one year. This supports commercial paper borrowing and can also be used for general corporate purposes. The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facility would be unsecured indebtedness at interest rates based on the Secured Overnight Financing Rate (SOFR), or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under this facility at December 31, 2023.
The company classified $4,543 and $4,050 of short-term debt as long-term at December 31, 2023 and 2022, respectively. Settlement of these obligations is not expected to require the use of working capital within one year, and the company has both the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 20
Long-Term Debt
Total long-term debt including finance lease liabilities at December 31, 2023, was $20,307. The company’s long-term debt outstanding at year-end 2023 and 2022 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | At December 31 |
| | | | | 2023 | | | 2022 |
| Weighted Average Interest Rate (%)1 | | Range of Interest Rates (%)2 | | Principal | | | Principal |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Notes due 2024 | 3.291 | | 2.895 - 3.900 | | $ | 1,650 | | | | $ | 1,650 | |
| | | | | | | | |
| | | | | | | | |
| Notes due 2025 | 1.724 | | 0.687 - 3.326 | | 4,000 | | | | 4,000 | |
| Notes due 2026 | | | 2.954 | | 2,250 | | | | 2,250 | |
| Notes due 2027 | 2.379 | | 1.018 - 8.000 | | 2,000 | | | | 2,000 | |
| Notes due 2028 | | | 3.850 | | 600 | | | | 600 | |
| Notes due 2029 | | | 3.250 | | 500 | | | | 500 | |
| Notes due 2030 | | | 2.236 | | 1,500 | | | | 1,500 | |
| Debentures due 2031 | | | 8.625 | | 102 | | | | 102 | |
| Debentures due 2032 | 8.416 | | 8.000 - 8.625 | | 183 | | | | 183 | |
| Notes due 2040 | | | 2.978 | | 293 | | | | 293 | |
| Notes due 2041 | | | 6.000 | | 397 | | | | 397 | |
| Notes due 2043 | | | 5.250 | | 330 | | | | 330 | |
| Notes due 2044 | | | 5.050 | | 222 | | | | 222 | |
| Notes due 2047 | | | 4.950 | | 187 | | | | 187 | |
| Notes due 2049 | | | 4.200 | | 237 | | | | 237 | |
| Notes due 2050 | 2.763 | | 2.343 - 3.078 | | 1,750 | | | | 1,750 | |
| Debentures due 2097 | | | 7.250 | | 60 | | | | 60 | |
| Bank loans due 2023 | | | - | | — | | | | 91 | |
| | | | | | | | |
| Medium-term notes, maturing from 2023 to 2038 | 6.599 | | 5.331 - 7.840 | | 20 | | | | 23 | |
| Notes due 2023 | | | | | — | | | | 2,600 | |
| Total including debt due within one year | | | | | 16,281 | | | | 18,975 | |
| Debt due within one year | | | | | (1,650) | | | | (2,694) | |
| | | | | | | | |
| | | | | | | | |
| Fair market value adjustment for debt acquired in the Noble acquisition | | 578 | | | | 664 | |
| Reclassified from short-term debt | | | | | 4,543 | | | | 4,050 | |
| Unamortized discounts and debt issuance costs | | | | | (19) | | | | (23) | |
Finance lease liabilities3 | | | | | 574 | | | | 403 | |
| Total long-term debt | | | | | $ | 20,307 | | | | $ | 21,375 | |
1 Weighted-average interest rate at December 31, 2023. | | | | | | | | |
2 Range of interest rates at December 31, 2023. | | | | | | | | |
| | | | | | | |
Long-term debt excluding finance lease liabilities with a principal balance of $16,281 matures as follows: 2024 – $1,650; 2025 – $4,000; 2026 – $2,250; 2027 – $2,000; 2028 – $600; and after 2028 – $5,781.
During the third quarter of 2023, the company assumed $1.5 billion of debt in conjunction with the PDC acquisition, including balances outstanding under the revolving credit facility, PDC’s 6.125% notes due 2024 (2024 notes) and PDC’s 5.75% notes due 2026 (2026 notes). The outstanding balances under the revolving credit facility and the 2024 notes were repaid during third quarter 2023. The company also irrevocably deposited sufficient U.S. Treasury securities with U.S. Bank Trust Company, N.A., as trustee, to fund the redemption of the 2026 notes, resulting in the indenture being satisfied and discharged.
Note 21
Accounting for Suspended Exploratory Wells
The company continues to capitalize exploratory well costs after the completion of drilling when the well has found a sufficient quantity of reserves to justify completion as a producing well, and the business unit is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met or if the company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense.
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended December 31, 2023:
| | | | | | | | | | | |
| 2023 | 2022 | 2021 |
| Beginning balance at January 1 | $ | 1,627 | | $ | 2,109 | | $ | 2,512 | |
| Additions to capitalized exploratory well costs pending the determination of proved reserves | 88 | | 72 | | 56 | |
| Reclassifications to wells, facilities and equipment based on the determination of proved reserves | — | | (481) | | (425) | |
| Capitalized exploratory well costs charged to expense | (67) | | (73) | | (34) | |
| | | |
| Ending balance at December 31 | $ | 1,648 | | $ | 1,627 | | $ | 2,109 | |
The following table provides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:
| | | | | | | | | | | |
| At December 31 |
| 2023 | 2022 | 2021 |
| Exploratory well costs capitalized for a period of one year or less | $ | 78 | | $ | 73 | | $ | 65 | |
| Exploratory well costs capitalized for a period greater than one year | 1,570 | | 1,554 | | 2,044 | |
| Balance at December 31 | $ | 1,648 | | $ | 1,627 | | $ | 2,109 | |
Number of projects with exploratory well costs that have been capitalized for a period greater than one year* | 13 | | 12 | | 15 | |
*Certain projects have multiple wells or fields or both.
Of the $1,570 of exploratory well costs capitalized for more than one year at December 31, 2023, $844 is related to seven projects that had drilling activities underway or firmly planned for the near future. The $726 balance is related to six projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not underway or firmly planned for the near future. Additional drilling was not deemed necessary because the presence of hydrocarbons had already been established, and other activities were in process to enable a future decision on project development.
The projects for the $726 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability: (a) $311 (four projects) – undergoing front-end engineering and design with final investment decision expected within four years; (b) $415 (two projects) – development alternatives under review. While progress was being made on all 13 projects, the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations associated with the projects. Approximately three-quarters of these decisions are expected to occur in the next five years.
The $1,570 of suspended well costs capitalized for a period greater than one year as of December 31, 2023, represents 71 exploratory wells in 13 projects. The tables below contain the aging of these costs on a well and project basis:
| | | | | | | | | | | | | | |
| Aging based on drilling completion date of individual wells: | Amount | | | Number of wells |
| 2000-2009 | $ | 263 | | | | 14 | |
| 2010-2014 | 1,121 | | | | 49 | |
| 2015-2022 | 186 | | | | 8 | |
| Total | $ | 1,570 | | | | 71 | |
| | | | |
| Aging based on drilling completion date of last suspended well in project: | Amount | | | Number of projects |
| 2008-2012 | $ | 292 | | | | 2 | |
| 2013-2016 | 1,082 | | | | 6 | |
| 2017-2023 | 196 | | | | 5 | |
| Total | $ | 1,570 | | | | 13 | |
Note 22
Stock Options and Other Share-Based Compensation
Compensation expense for stock options for 2023, 2022 and 2021 was $85 ($65 after tax), $60 ($46 after tax) and $60 ($47 after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance shares and restricted stock units resulted in a net benefit of $(100) ($(76) after tax) for 2023, primarily as a result of reductions in the fair value of outstanding liability-classified performance shares that are remeasured each reporting period. Compensation expense for stock appreciation rights, restricted stock, performance shares and restricted stock units was $1,013 ($770 after tax) and $701 ($554 after tax) for 2022 and 2021, respectively. No significant stock-based compensation cost was capitalized at December 31, 2023, or December 31, 2022.
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Cash received in payment for option exercises under all share-based payment arrangements for 2023, 2022 and 2021 was $263, $5,835 and $1,274, respectively. Actual tax benefits realized for the tax deductions from option exercises were $20, $216 and $(15) for 2023, 2022 and 2021, respectively.
Cash paid to settle performance shares, restricted stock units and stock appreciation rights was $566, $556 and $163 for 2023, 2022 and 2021, respectively.
On May 25, 2022, stockholders approved the Chevron 2022 Long-Term Incentive Plan (2022 LTIP). Awards under the 2022 LTIP may take the form of, but are not limited to, stock options, restricted stock, restricted stock units, stock appreciation rights, performance shares and non-stock grants. From May 2022 through May 2032, no more than 104 million shares may be issued under the 2022 LTIP. For awards issued on or after May 25, 2022, no more than 48 million of those shares may be issued in the form of full value awards such as share-settled restricted stock, share-settled restricted stock units and other share-settled awards that do not require full payment in cash or property for shares underlying such awards by the award recipient. For the major types of awards issued before January 1, 2017, the contractual terms vary between three years for the performance shares and restricted stock units, and 10 years for the stock options and stock appreciation rights. For awards issued after January 1, 2017, contractual terms vary between three years for the performance shares and special restricted stock units, five years for standard restricted stock units and 10 years for the stock options and stock appreciation rights. Commencing for grants issued in January 2023 and after, standard restricted stock units vest ratably on an annual basis over a three-year period. Forfeitures of performance shares, restricted stock units, and stock appreciation rights are recognized as they occur. Forfeitures of stock options are estimated using historical forfeiture data dating back to 1990.
Fair Value and Assumptions The fair market values of stock options and stock appreciation rights granted in 2023, 2022 and 2021 were measured on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions:
| | | | | | | | | | | | | | | | | | | | | | | |
| Year ended December 31 |
| 2023 | | | 2022 | | 2021 | |
Expected term in years1 | 6.4 | | | 6.9 | | 6.8 | |
Volatility2 | 32.5 | | % | | 31.3 | | % | 31.1 | | % |
| Risk-free interest rate based on zero coupon U.S. treasury note | 3.43 | | % | | 1.79 | | % | 0.71 | | % |
| Dividend yield | 3.5 | | % | | 5.0 | | % | 6.0 | | % |
| Weighted-average fair value per option granted | $ | 45.82 | | | | $ | 23.56 | | | $ | 12.22 | | |
1 Expected term is based on historical exercise and post-vesting cancellation data.
2 Volatility rate is based on historical stock prices over an appropriate period, generally equal to the expected term.
A summary of option activity during 2023 is presented below:
| | | | | | | | | | | | | | | | | | | | | | | |
| Shares (Thousands) | Weighted-Average
Exercise Price | | Averaged Remaining Contractual Term (Years) | Aggregate Intrinsic Value |
| Outstanding at January 1, 2023 | 25,265 | | | $ | 114.61 | | | | | |
| Granted | 2,122 | | | $ | 179.08 | | | | | |
| Exercised | (2,538) | | | $ | 104.30 | | | | | |
| Forfeited | (474) | | | $ | 246.61 | | | | | |
| Outstanding at December 31, 2023 | 24,375 | | | $ | 118.72 | | | 5.14 | | $ | 934 | |
| Exercisable at December 31, 2023 | 18,438 | | | $ | 113.38 | | | 4.11 | | $ | 791 | |
The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2023, 2022 and 2021 was $167, $2,369 and $152, respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.
As of December 31, 2023, there was $181 of total unrecognized before-tax compensation cost related to nonvested share-based compensation arrangements granted under the plan. That cost is expected to be recognized over a weighted-average period of 1.9 years.
At January 1, 2023, the number of LTIP performance shares outstanding was equivalent to 4,753,266 shares. During 2023, 1,291,262 performance shares were granted, 1,521,636 shares vested with cash proceeds distributed to recipients and 103,582 shares were forfeited. At December 31, 2023, there were 4,419,310 performance shares outstanding that are payable in cash. The fair value of the liability recorded for these instruments was $360 and was measured largely using the Monte Carlo simulation method.
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
At January 1, 2023, the number of restricted stock units outstanding was equivalent to 4,287,826 shares. During 2023, 1,739,120 restricted stock units were granted, 866,494 units vested with cash proceeds distributed to recipients and 100,210 units were forfeited. At December 31, 2023, there were 5,060,242 restricted stock units outstanding, of which 3,905,243 are payable in cash and 1,154,999 are payable in shares. The fair value of the liability recorded for the vested portion of these instruments payable in cash was $457, valued at the stock price as of December 31, 2023. In addition, outstanding stock appreciation rights that were granted under the LTIP totaled 652,493 equivalent shares as of December 31, 2023. The fair value of the liability recorded for the vested portion of these instruments was $32.
Note 23
Employee Benefit Plans
The company has defined benefit pension plans for many employees. The company typically prefunds defined benefit plans as required by local regulations or in certain situations where prefunding provides economic advantages. In the United States, all qualified plans are subject to the Employee Retirement Income Security Act (ERISA) minimum funding standard. The company does not typically fund U.S. nonqualified pension plans that are not subject to funding requirements under laws and regulations because contributions to these pension plans may be less economic and investment returns may be less attractive than the company’s other investment alternatives.
The company also sponsors other postretirement benefit (OPEB) plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees. The plans are unfunded, and the company and retirees share the costs. For the company’s main U.S. medical plan, the increase to the pre-Medicare company contribution for retiree medical coverage is limited to no more than 4 percent each year. Certain life insurance benefits are paid by the company.
The company recognizes the overfunded or underfunded status of each of its defined benefit pension and OPEB plans as an asset or liability on the Consolidated Balance Sheet.
The funded status of the company’s pension and OPEB plans for 2023 and 2022 follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | |
| 2023 | | | 2022 | | Other Benefits |
| U.S. | | Int’l. | | | U.S. | | Int’l. | | 2023 | | | 2022 |
| Change in Benefit Obligation | | | | | | | | | | | | | |
| Benefit obligation at January 1 | $ | 9,713 | | | $ | 3,354 | | | | $ | 12,966 | | | $ | 5,351 | | | $ | 1,938 | | | | $ | 2,489 | |
| Service cost | 342 | | | 58 | | | | 432 | | | 83 | | | 33 | | | | 43 | |
| Interest cost | 448 | | | 193 | | | | 318 | | | 137 | | | 97 | | | | 60 | |
| Plan participants’ contributions | — | | | 3 | | | | — | | | 3 | | | 63 | | | | 62 | |
| Plan amendments | — | | | 28 | | | | 40 | | | 38 | | | — | | | | 18 | |
| Actuarial (gain) loss | 603 | | | 17 | | | | (2,753) | | | (1,559) | | | 103 | | | | (509) | |
| Foreign currency exchange rate changes | — | | | 180 | | | | — | | | (423) | | | 5 | | | | (5) | |
| Benefits paid | (714) | | | (218) | | | | (1,290) | | | (276) | | | (222) | | | | (220) | |
| Divestitures/Acquisitions | — | | | (14) | | | | — | | | — | | | — | | | | — | |
| Curtailment | — | | | 2 | | | | — | | | — | | | — | | | | — | |
| Special termination costs | — | | | 2 | | | | — | | | — | | | — | | | | — | |
| Benefit obligation at December 31 | 10,392 | | | 3,605 | | | | 9,713 | | | 3,354 | | | 2,017 | | | | 1,938 | |
| Change in Plan Assets | | | | | | | | | | | | | |
| Fair value of plan assets at January 1 | 7,942 | | | 3,286 | | | | 9,919 | | | 4,950 | | | — | | | | — | |
| Actual return on plan assets | 889 | | | 46 | | | | (1,851) | | | (1,096) | | | — | | | | — | |
| Foreign currency exchange rate changes | — | | | 181 | | | | — | | | (453) | | | — | | | | — | |
| Employer contributions | 1,020 | | | 100 | | | | 1,164 | | | 158 | | | 159 | | | | 158 | |
| Plan participants’ contributions | — | | | 3 | | | | — | | | 3 | | | 63 | | | | 62 | |
| Benefits paid | (714) | | | (218) | | | | (1,290) | | | (276) | | | (222) | | | | (220) | |
| | | | | | | | | | | | | |
| Fair value of plan assets at December 31 | 9,137 | | | 3,398 | | | | 7,942 | | | 3,286 | | | — | | | | — | |
| Funded status at December 31 | $ | (1,255) | | | $ | (207) | | | | $ | (1,771) | | | $ | (68) | | | $ | (2,017) | | | | $ | (1,938) | |
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Amounts recognized on the Consolidated Balance Sheet for the company’s pension and OPEB plans at December 31, 2023 and 2022, include:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | |
| 2023 | | | 2022 | | Other Benefits |
| U.S. | | Int’l. | | | U.S. | | Int’l. | | 2023 | | | 2022 |
| Deferred charges and other assets | $ | 31 | | | $ | 703 | | | | $ | 26 | | | $ | 759 | | | $ | — | | | | $ | — | |
| Accrued liabilities | (145) | | | (73) | | | | (210) | | | (62) | | | (154) | | | | (152) | |
| Noncurrent employee benefit plans | (1,141) | | | (837) | | | | (1,587) | | | (765) | | | (1,863) | | | | (1,786) | |
| Net amount recognized at December 31 | $ | (1,255) | | | $ | (207) | | | | $ | (1,771) | | | $ | (68) | | | $ | (2,017) | | | | $ | (1,938) | |
For the year ended December 31, 2023, the increase in benefit obligations was primarily due to actuarial losses caused by lower discount rates used to value the obligations. For the year ended December 31, 2022, the decrease in benefit obligations was primarily due to actuarial gains caused by higher discount rates used to value the obligations and benefit payments paid to retirees in 2022.
Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $3,792 and $3,446 at the end of 2023 and 2022, respectively. These amounts consisted of:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | |
| 2023 | | | 2022 | | Other Benefits |
| U.S. | | Int’l. | | | U.S. | | Int’l. | | 2023 | | | 2022 |
| Net actuarial loss | $ | 3,161 | | | $ | 823 | | | | $ | 3,147 | | | $ | 659 | | | $ | (266) | | | | $ | (392) | |
| Prior service (credit) costs | 37 | | | 126 | | | | 40 | | | 107 | | | (89) | | | | (115) | |
| Total recognized at December 31 | $ | 3,198 | | | $ | 949 | | | | $ | 3,187 | | | $ | 766 | | | $ | (355) | | | | $ | (507) | |
The accumulated benefit obligations for all U.S. and international pension plans were $9,284 and $3,378, respectively, at December 31, 2023, and $8,595 and $3,084, respectively, at December 31, 2022.
Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2023 and 2022, was:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits |
| 2023 | | | 2022 |
| U.S. | | Int’l. | | | U.S. | | Int’l. |
| Projected benefit obligations | $ | 1,203 | | | $ | 913 | | | | $ | 1,322 | | | $ | 828 | |
| Accumulated benefit obligations | 1,108 | | | 773 | | | | 1,135 | | | 671 | |
| Fair value of plan assets | — | | | 4 | | | | — | | | 3 | |
The components of net periodic benefit cost and amounts recognized in the Consolidated Statement of Comprehensive Income for 2023, 2022 and 2021 are shown in the table below:
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | | | | | | |
| 2023 | | | 2022 | 2021 | | Other Benefits |
| U.S. | Int’l. | | | U.S. | Int’l. | U.S. | Int’l. | | 2023 | | | 2022 | | 2021 |
| Net Periodic Benefit Cost | | | | | | | | | | | | | | | |
| Service cost | $ | 342 | | $ | 58 | | | | $ | 432 | | $ | 83 | | $ | 450 | | $ | 123 | | | $ | 33 | | | | $ | 43 | | | $ | 43 | |
| Interest cost | 448 | | 193 | | | | 318 | | 137 | | 235 | | 137 | | | 97 | | | | 60 | | | 53 | |
| Expected return on plan assets | (557) | | (204) | | | | (624) | | (176) | | (596) | | (171) | | | — | | | | — | | | — | |
| Amortization of prior service costs (credits) | 4 | | 8 | | | | 2 | | 6 | | 2 | | 8 | | | (25) | | | | (27) | | | (27) | |
| Recognized actuarial losses | 199 | | 8 | | | | 218 | | 15 | | 309 | | 46 | | | (19) | | | | 13 | | | 16 | |
| Settlement losses | 56 | | — | | | | 363 | | (6) | | 672 | | 7 | | | — | | | | — | | | — | |
| Curtailment losses (gains) | — | | 2 | | | | — | | (5) | | — | | (1) | | | — | | | | — | | | — | |
| Special termination benefits | — | | 2 | | | | — | | — | | — | | — | | | — | | | | — | | | — | |
| Acquisition/Divestiture losses (gains) | — | | (2) | | | | — | | — | | — | | — | | | — | | | | — | | | — | |
| Total net periodic benefit cost | 492 | | 65 | | | | 709 | | 54 | | 1,072 | | 149 | | | 86 | | | | 89 | | | 85 | |
| Changes Recognized in Comprehensive Income | | | | | | | | | | | | | | | |
| Net actuarial (gain) loss during period | 270 | | 172 | | | | (279) | | (257) | | (725) | | (408) | | | 108 | | | | (514) | | | (111) | |
| Amortization of actuarial loss | (255) | | (8) | | | | (581) | | (5) | | (981) | | (73) | | | 19 | | | | (13) | | | (15) | |
| Prior service (credits) costs during period | — | | 28 | | | | 40 | | 38 | | — | | — | | | 1 | | | | 18 | | | — | |
| Amortization of prior service (costs) credits | (4) | | (8) | | | | (2) | | (6) | | (2) | | (11) | | | 25 | | | | 27 | | | 27 | |
Total changes recognized in other
comprehensive income | 11 | | 184 | | | | (822) | | (230) | | (1,708) | | (492) | | | 153 | | | | (482) | | | (99) | |
| Recognized in Net Periodic Benefit Cost and Other Comprehensive Income | $ | 503 | | $ | 249 | | | | $ | (113) | | $ | (176) | | $ | (636) | | $ | (343) | | | $ | 239 | | | | $ | (393) | | | $ | (14) | |
Assumptions The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | | | | | | |
| 2023 | | | 2022 | | 2021 | | | | | Other Benefits |
| U.S. | Int’l. | | | U.S. | Int’l. | | U.S. | Int’l. | | 2023 | | | 2022 | | 2021 |
| Assumptions used to determine benefit obligations: | | | | | | | | | | | | | | | | |
| Discount rate | 5.0 | % | 5.5 | % | | | 5.2 | % | 5.8 | % | | 2.8 | % | 2.8 | % | | 5.1 | % | | | 5.3 | % | | 2.9 | % |
| Rate of compensation increase | 4.5 | % | 3.9 | % | | | 4.5 | % | 4.2 | % | | 4.5 | % | 4.1 | % | | N/A | | | N/A | | N/A |
| Assumptions used to determine net periodic benefit cost: | | | | | | | | | | | | | | | | |
| Discount rate for service cost | 5.2 | % | 5.8 | % | | | 3.6 | % | 2.8 | % | | 3.0 | % | 2.4 | % | | 5.4 | % | | | 3.1 | % | | 3.0 | % |
| Discount rate for interest cost | 5.0 | % | 5.8 | % | | | 2.8 | % | 2.8 | % | | 1.9 | % | 2.4 | % | | 5.2 | % | | | 2.4 | % | | 2.1 | % |
| Expected return on plan assets | 7.0 | % | 6.1 | % | | | 6.6 | % | 3.9 | % | | 6.5 | % | 3.5 | % | | N/A | | | N/A | | N/A |
| Rate of compensation increase | 4.5 | % | 4.2 | % | | | 4.5 | % | 4.1 | % | | 4.5 | % | 4.0 | % | | N/A | | | N/A | | N/A |
Expected Return on Plan Assets The company’s estimated long-term rates of return on pension assets are driven primarily by actual historical asset-class returns, an assessment of expected future performance, advice from external actuarial firms and the incorporation of specific asset-class risk factors. Asset allocations are periodically updated using pension plan asset/liability studies, and the company’s estimated long-term rates of return are consistent with these studies. For 2023, the company used an expected long-term rate of return of 7.0 percent for U.S. pension plan assets, which account for 71 percent of the company’s pension plan assets at the beginning of the year.
The market-related value of assets of the main U.S. pension plan used in the determination of pension expense was based on the market values in the three months preceding the year-end measurement date. Management considers the three-month time period long enough to minimize the effects of distortions from day-to-day market volatility and still be contemporaneous to the end of the year. For other plans, market value of assets as of year-end is used in calculating the pension expense.
Discount Rate The discount rate assumptions used to determine the U.S. and international pension and OPEB plan obligations and expense reflect the rate at which benefits could be effectively settled, and are equal to the equivalent single rate resulting from yield curve analysis. This analysis considered the projected benefit payments specific to the company’s plans and the yields on high-quality bonds. The projected cash flows were discounted to the valuation date using the yield curve for the main U.S. pension and OPEB plans. The effective discount rates derived from this analysis were 5.0 percent, 5.2 percent, and 2.8 percent for 2023, 2022, and 2021, respectively, for both the main U.S. pension and OPEB plans.
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2023, for the main U.S. OPEB plan, the assumed health care cost-trend rates start with 8.4 percent in 2024 and gradually decline to 4.5 percent for 2033 and beyond. For this measurement at December 31, 2022, the assumed health care cost-trend rates started with 6.6 percent in 2023 and gradually declined to 4.5 percent for 2032 and beyond.
Plan Assets and Investment Strategy
The fair value measurements of the company’s pension plans for 2023 and 2022 are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| U.S. | | | Int’l. |
| Total | | Level 1 | | Level 2 | | Level 3 | | NAV | | | Total | | Level 1 | | Level 2 | | Level 3 | | NAV |
| At December 31, 2022 | | | | | | | | | | | | | | | | | | | | |
| Equities | | | | | | | | | | | | | | | | | | | | |
U.S.1 | $ | 1,358 | | | $ | 1,358 | | | $ | — | | | $ | — | | | $ | — | | | | $ | 164 | | | $ | 164 | | | $ | — | | | $ | — | | | $ | — | |
| International | 946 | | | 946 | | | — | | | — | | | — | | | | 120 | | | 120 | | | — | | | — | | | — | |
Collective Trusts/Mutual Funds2 | 1,695 | | | 4 | | | — | | | — | | | 1,691 | | | | 87 | | | 6 | | | — | | | — | | | 81 | |
| Fixed Income | | | | | | | | | | | | | | | | | | | | |
| Government | 110 | | | — | | | 110 | | | — | | | — | | | | 185 | | | 127 | | | 58 | | | — | | | — | |
| Corporate | 680 | | | — | | | 680 | | | — | | | — | | | | 343 | | | 15 | | | 328 | | | — | | | — | |
| Bank Loans | 45 | | | — | | | 45 | | | — | | | — | | | | — | | | — | | | — | | | — | | | — | |
| Mortgage/Asset Backed | 1 | | | — | | | 1 | | | — | | | — | | | | 4 | | | — | | | 4 | | | — | | | — | |
| | | | | | | | | | | | | | | | | | | | |
Collective Trusts/Mutual Funds2 | 1,616 | | | — | | | — | | | — | | | 1,616 | | | | 1,750 | | | — | | | — | | | — | | | 1,750 | |
Mixed Funds3 | — | | | — | | | — | | | — | | | — | | | | 87 | | | 14 | | | 73 | | | — | | | — | |
Real Estate4 | 1,184 | | | — | | | — | | | — | | | 1,184 | | | | 198 | | | — | | | — | | | 38 | | | 160 | |
| Alternative Investments | — | | | — | | | — | | | — | | | — | | | | — | | | — | | | — | | | — | | | — | |
| Cash and Cash Equivalents | 200 | | | 25 | | | — | | | — | | | 175 | | | | 80 | | | 69 | | | 2 | | | — | | | 9 | |
Other5 | 107 | | | 37 | | | 15 | | | 54 | | | 1 | | | | 268 | | | — | | | 18 | | | 85 | | | 165 | |
| Total at December 31, 2022 | $ | 7,942 | | | $ | 2,370 | | | $ | 851 | | | $ | 54 | | | $ | 4,667 | | | | $ | 3,286 | | | $ | 515 | | | $ | 483 | | | $ | 123 | | | $ | 2,165 | |
| At December 31, 2023 | | | | | | | | | | | | | | | | | | | | |
| Equities | | | | | | | | | | | | | | | | | | | | |
U.S.1 | $ | 1,691 | | | $ | 1,689 | | | $ | 1 | | | $ | 1 | | | $ | — | | | | $ | 188 | | | $ | 188 | | | $ | — | | | $ | — | | | $ | — | |
| International | 1,128 | | | 1,128 | | | — | | | — | | | — | | | | 124 | | | 124 | | | — | | | — | | | — | |
Collective Trusts/Mutual Funds2 | 1,269 | | | 4 | | | — | | | — | | | 1,265 | | | | 95 | | | 6 | | | — | | | — | | | 89 | |
| Fixed Income | | | | | | | | | | | | | | | | | | | | |
| Government | 82 | | | — | | | 82 | | | — | | | — | | | | 172 | | | 101 | | | 71 | | | — | | | — | |
| Corporate | 964 | | | — | | | 964 | | | — | | | — | | | | 431 | | | 4 | | | 427 | | | — | | | — | |
| Bank Loans | 5 | | | — | | | 5 | | | — | | | — | | | | — | | | — | | | — | | | — | | | — | |
| Mortgage/Asset Backed | 1 | | | — | | | 1 | | | — | | | — | | | | 5 | | | — | | | 5 | | | — | | | — | |
| | | | | | | | | | | | | | | | | | | | |
Collective Trusts/Mutual Funds2 | 2,293 | | | — | | | — | | | — | | | 2,293 | | | | 1,819 | | | — | | | — | | | — | | | 1,819 | |
Mixed Funds3 | — | | | — | | | — | | | — | | | — | | | | 85 | | | 8 | | | 77 | | | — | | | — | |
Real Estate4 | 1,087 | | | — | | | — | | | — | | | 1,087 | | | | 147 | | | — | | | 24 | | | — | | | 123 | |
| Alternative Investments | — | | | — | | | — | | | — | | | — | | | | 9 | | | — | | | 9 | | | — | | | — | |
| Cash and Cash Equivalents | 548 | | | 12 | | | — | | | — | | | 536 | | | | 81 | | | 74 | | | 1 | | | — | | | 6 | |
Other5 | 69 | | | (2) | | | 14 | | | 56 | | | 1 | | | | 242 | | | — | | | 11 | | | 81 | | | 150 | |
| Total at December 31, 2023 | $ | 9,137 | | | $ | 2,831 | | | $ | 1,067 | | | $ | 57 | | | $ | 5,182 | | | | $ | 3,398 | | | $ | 505 | | | $ | 625 | | | $ | 81 | | | $ | 2,187 | |
1There were no investments in the company’s common stock at December 31, 2023 or December 31, 2022.
2Collective Trusts/Mutual Funds for U.S. plans are entirely index funds; for International plans, they are mostly unit trust and index funds.
3Mixed funds are composed of funds that invest in both equity and fixed-income instruments in order to diversify and lower risk.
4The 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.
5The “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 | |
The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Equity | | | | | | | | | |
| U.S. | | International | | | Real Estate | | | Other | | | Total |
| Total at December 31, 2021 | $ | — | | | $ | 1 | | | | $ | 42 | | | | $ | 161 | | | | $ | 204 | |
| Actual Return on Plan Assets: | | | | | | | | | | | | |
| Assets held at the reporting date | — | | | (1) | | | | — | | | | (18) | | | | (19) | |
| Assets sold during the period | — | | | — | | | | (4) | | | | — | | | | (4) | |
| Purchases, Sales and Settlements | — | | | — | | | | — | | | | (4) | | | | (4) | |
| Transfers in and/or out of Level 3 | — | | | — | | | | — | | | | — | | | | — | |
| Total at December 31, 2022 | $ | — | | | $ | — | | | | $ | 38 | | | | $ | 139 | | | | $ | 177 | |
| Actual Return on Plan Assets: | | | | | | | | | | | | |
| Assets held at the reporting date | 1 | | | — | | | | 5 | | | | — | | | | 6 | |
| Assets sold during the period | — | | | — | | | | — | | | | (2) | | | | (2) | |
| Purchases, Sales and Settlements | — | | | — | | | | — | | | | — | | | | — | |
| Transfers in and/or out of Level 3 | — | | | — | | | | (43) | | | | — | | | | (43) | |
| Total at December 31, 2023 | $ | 1 | | | $ | — | | | | $ | — | | | | $ | 137 | | | | $ | 138 | |
The primary investment objectives of the pension plans are to achieve the highest rate of total return within prudent levels of risk and liquidity, to diversify and mitigate potential downside risk associated with the investments, and to provide adequate liquidity for benefit payments and portfolio management.
The company’s U.S. and U.K. pension plans comprise 95 percent of the total pension assets. Both the U.S. and U.K. plans have an Investment Committee that regularly meets during the year to review the asset holdings and their returns. To assess the plans’ investment performance, long-term asset allocation policy benchmarks have been established.
For the primary U.S. pension plan, the company’s Investment Committee has established the following approved asset allocation ranges: Equities 35–65 percent, Fixed Income 25–45 percent, Real Estate 5–25 percent, Alternative Investments 0–5 percent and Cash 0–15 percent. For the U.K. pension plan, the U.K. Board of Trustees has established the following asset allocation guidelines: Equities 5–15 percent, Fixed Income 63–93 percent, Real Estate 5–15 percent, and Cash 0–7 percent. The other significant international pension plans also have established maximum and minimum asset allocation ranges that vary by plan. Actual asset allocation within approved ranges is based on a variety of factors, including market conditions and liquidity constraints. To mitigate concentration and other risks, assets are invested across multiple asset classes with active investment managers and passive index funds.
The company does not prefund its OPEB obligations.
Cash Contributions and Benefit Payments In 2023, the company contributed $1,020 and $100 to its U.S. and international pension plans, respectively. In 2024, the company expects contributions to be approximately $750 to its U.S. plans and $100 to its international pension plans. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments, tax law changes and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.
The company anticipates paying OPEB benefits of approximately $150 in 2024; $159 was paid in 2023.
The following benefit payments, which include estimated future service, are expected to be paid by the company in the next 10 years:
| | | | | | | | | | | | | | | | | |
| Pension Benefits | | Other |
| U.S. | | Int’l. | | Benefits |
| 2024 | $ | 886 | | | $ | 216 | | | $ | 154 | |
| 2025 | 912 | | | 210 | | | 151 | |
| 2026 | 904 | | | 222 | | | 149 | |
| 2027 | 901 | | | 228 | | | 147 | |
| 2028 | 877 | | | 240 | | | 146 | |
| 2029-2033 | 4,248 | | | 1,266 | | | 716 | |
Employee Savings Investment Plan Eligible employees of Chevron and certain of its subsidiaries participate in the Chevron Employee Savings Investment Plan (ESIP). Compensation expense for the ESIP totaled $320, $283 and $252 in 2023, 2022 and 2021, respectively.
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Benefit Plan Trusts Prior to its acquisition by Chevron, Texaco established a benefit plan trust for funding obligations under some of its benefit plans. At year-end 2023, the trust contained 14.2 million shares of Chevron treasury stock. The trust will sell the shares or use the dividends from the shares to pay benefits only to the extent that the company does not pay such benefits. The company intends to continue to pay its obligations under the benefit plans. The trustee will vote the shares held in the trust as instructed by the trust’s beneficiaries. The shares held in the trust are not considered outstanding for earnings-per-share purposes until distributed or sold by the trust in payment of benefit obligations.
Employee Incentive Plans The Chevron Incentive Plan is an annual cash bonus plan for eligible employees that links awards to corporate and individual performance in the prior year. Charges to expense for cash bonuses were $809, $1,169 and $1,165 in 2023, 2022 and 2021, respectively. Chevron also has the LTIP for officers and other regular salaried employees of the company and its subsidiaries who hold positions of significant responsibility. Awards under the LTIP consist of stock options and other share-based compensation that are described in Note 22 Stock Options and Other Share-Based Compensation. Note 24
Other Contingencies and Commitments
Income Taxes The company calculates its income tax expense and liabilities quarterly. These liabilities generally are subject to audit and are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been calculated. Refer to Note 17 Taxes for a discussion of the periods for which tax returns have been audited for the company’s major tax jurisdictions and a discussion for all tax jurisdictions of the differences between the amount of tax benefits recognized in the financial statements and the amount taken or expected to be taken in a tax return. Settlement of open tax years, as well as other tax issues in countries where the company conducts its businesses, are not expected to have a material effect on the consolidated financial position or liquidity of the company and, in the opinion of management, adequate provisions have been made for all years under examination or subject to future examination.
Guarantees The company has one guarantee to an equity affiliate totaling $135. This guarantee is associated with certain payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 4-year remaining term of this guarantee, the maximum guarantee amount will be reduced as certain fees are paid by the affiliate. There are numerous cross-indemnity agreements with the affiliate and the other partners to permit recovery of amounts paid under the guarantee. Chevron has recorded no liability for this guarantee.
Indemnifications The company often includes standard indemnification provisions in its arrangements with its partners, suppliers and vendors in the ordinary course of business, the terms of which range in duration and sometimes are not limited. The company may be obligated to indemnify such parties for losses or claims suffered or incurred in connection with its service or other claims made against such parties.
Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain contingent liabilities with respect to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which may relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate amounts of required payments under throughput and take-or-pay agreements are: 2024 – $909; 2025 – $1,086; 2026 – $1,141; 2027 – $1,193; 2028 – $1,183; after 2028 – $7,553. The aggregate amount of required payments for other unconditional purchase obligations are: 2024 – $589; 2025 – $451; 2026 – $484; 2027 – $604; 2028 – $273; after 2028 – $1,078. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were $1,420 in 2023, $1,866 in 2022 and $861 in 2021.
Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances by the company or other parties. Such contingencies may exist for various operating, closed and divested sites, including, but not limited to, U.S. federal Superfund sites and analogous sites under state laws, refineries, chemical plants, marketing facilities, crude oil fields, and mining sites.
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Although the company has provided for known environmental obligations that are probable and reasonably estimable, it is likely that the company will continue to incur additional liabilities. The amount of additional future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. These future costs may be material to results of operations in the period in which they are recognized, but the company does not expect these costs will have a material effect on its consolidated financial position or liquidity.
Chevron’s environmental reserve as of December 31, 2023, was $936. Included in this balance was $232 related to remediation activities at sites for which the company had been identified as a potentially responsible party under the provisions of the U.S. federal Superfund law which provide for joint and several liability for all responsible parties. Any future actions by regulatory agencies to require Chevron to assume other potentially responsible parties’ costs at designated hazardous waste sites are not expected to have a material effect on the company’s results of operations, consolidated financial position or liquidity.
Of the remaining year-end 2023 environmental reserves balance of $704, $389 is related to the company’s U.S. downstream operations, $55 to its international downstream operations, and $260 to its upstream operations. Liabilities at all sites were primarily associated with the company’s plans and activities to remediate soil or groundwater contamination or both.
The company manages environmental liabilities under specific sets of regulatory requirements, which in the United States include the Resource Conservation and Recovery Act and various state and local regulations. No single remediation site at year-end 2023 had a recorded liability that was material to the company’s results of operations, consolidated financial position or liquidity.
Other Contingencies Chevron receives claims from and submits claims to customers; trading partners; joint venture partners; U.S. federal, state and local regulatory bodies; governments; contractors; insurers; suppliers; and individuals. The amounts of these claims, individually and in the aggregate, may be significant and take lengthy periods to resolve, and may result in gains or losses in future periods.
The company and its affiliates also continue to review and analyze their operations and may close, retire, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve competitiveness and profitability. These activities, individually or together, may result in significant gains or losses in future periods.
In addition, some assets are sold along with their related liabilities and in certain instances, such transferred obligations have reverted and may in the future revert to the company and result in losses that could be significant. In fourth quarter 2023, the company recognized an after-tax loss of $1,950 related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S. Gulf of Mexico, as companies that purchased these assets have filed for protection under Chapter 11 of the U.S. Bankruptcy Code, and we believe it is now probable and estimable that a portion of these obligations will revert to the company.
Note 25
Asset Retirement Obligations
The company records the fair value of a liability for an asset retirement obligation (ARO) both as an asset and a liability when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. The legal obligation to perform the asset retirement activity is unconditional, even though uncertainty may exist about the timing and/or method of settlement that may be beyond the company’s control. This uncertainty about the timing and/or method of settlement is factored into the measurement of the liability when sufficient information exists to reasonably estimate fair value. Recognition of the ARO includes: (1) the present value of a liability and offsetting asset, (2) the subsequent accretion of that liability and depreciation of the asset, and (3) the periodic review of the ARO liability estimates and discount rates.
AROs are primarily recorded for the company’s crude oil and natural gas producing assets. No significant AROs associated with any legal obligations to retire downstream long-lived assets have been recognized, as indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the associated ARO. The company performs periodic
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
reviews of its downstream long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation.
The following table indicates the changes to the company’s before-tax asset retirement obligations in 2023, 2022 and 2021:
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | | 2022 | | 2021 |
| Balance at January 1 | $ | 12,701 | | | | $ | 12,808 | | | $ | 13,616 | |
| | | | | | |
| Liabilities assumed in the PDC acquisition | 220 | | | | — | | | — | |
| Liabilities incurred | 183 | | | | 9 | | | 31 | |
| Liabilities settled | (1,565) | | | | (1,281) | | | (1,887) | |
| Accretion expense | 593 | | | | 560 | | | 616 | |
| Revisions in estimated cash flows | 1,701 | | | | 605 | | | 432 | |
| Balance at December 31 | $ | 13,833 | | | | $ | 12,701 | | | $ | 12,808 | |
In the table above, the amount associated with “Revisions in estimated cash flows” primarily reflects increased cost estimates and scope changes to decommission wells, equipment and facilities. The long-term portion of the $13,833 balance at the end of 2023 was $12,122.
Note 26
Revenue
Revenue from contracts with customers is presented in “Sales and other operating revenues” along with some activity that is accounted for outside the scope of Accounting Standard Codification (ASC) 606, which is not material to this line, on the Consolidated Statement of Income. Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another (including buy/sell arrangements) are combined and recorded on a net basis and reported in “Purchased crude oil and products” on the Consolidated Statement of Income. Refer to Note 14 Operating Segments and Geographic Data for additional information on the company’s segmentation of revenue. Receivables related to revenue from contracts with customers are included in “Accounts and notes receivable” on the Consolidated Balance Sheet, net of the allowance for doubtful accounts. The net balance of these receivables was $13,641 and $14,219 at December 31, 2023 and 2022, respectively. Other items included in “Accounts and notes receivable” represent amounts due from partners for their share of joint venture operating and project costs and amounts due from others, primarily related to derivatives, leases, buy/sell arrangements and product exchanges, which are accounted for outside the scope of ASC 606.
Contract assets and related costs are reflected in “Prepaid expenses and other current assets” and contract liabilities are reflected in “Accrued liabilities” and “Deferred credits and other noncurrent obligations” on the Consolidated Balance Sheet. Amounts for these items are not material to the company’s financial position.
Note 27
Other Financial Information
Earnings in 2023 included after-tax gains of approximately $143 relating to the sale of certain properties. Of this amount, approximately $33 and $110 related to downstream and upstream, respectively. Earnings in 2022 included after-tax gains of approximately $390 relating to the sale of certain properties, of which approximately $90 and $300 related to downstream and upstream assets, respectively. Earnings in 2021 included after-tax gains of approximately $785 relating to the sale of certain properties, of which approximately $30 and $755 related to downstream and upstream assets, respectively.
Earnings in 2023 included after-tax charges of approximately $1,950 for abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S. Gulf of Mexico and $1,765 for upstream impairments, mainly in California, and several tax items with a net benefit of $655. Earnings in 2022 included after-tax charges of approximately $1,075 for impairments and other asset write-offs related to upstream, $600 for an early contract termination in upstream, and $271 for pension settlement costs. Earnings in 2021 included after-tax charges of approximately $519 for pension settlement costs, $260 for early retirement of debt, $120 relating to upstream remediation and $110 relating to downstream legal reserves.
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
| | | | | | | | | | | | | | | | | | | | |
| Other financial information is as follows: | | | | | | |
| Year ended December 31 |
| 2023 | | | 2022 | | 2021 |
| Total financing interest and debt costs | $ | 617 | | | | $ | 630 | | | $ | 775 | |
| Less: Capitalized interest | 148 | | | | 114 | | | 63 | |
| Interest and debt expense | $ | 469 | | | | $ | 516 | | | $ | 712 | |
| Research and development expenses | $ | 320 | | | | $ | 268 | | | $ | 268 | |
| Excess of replacement cost over the carrying value of inventories (LIFO method) | $ | 6,455 | | | | $ | 9,061 | | | $ | 5,588 | |
| LIFO profits (losses) on inventory drawdowns included in earnings | $ | 14 | | | | $ | 122 | | | $ | 35 | |
Foreign currency effects* | $ | (224) | | | | $ | 669 | | | $ | 306 | |
* Includes $(11), $253 and $180 in 2023, 2022 and 2021, respectively, for the company’s share of equity affiliates’ foreign currency effects.
The company has $4,722 in goodwill on the Consolidated Balance Sheet, of which $4,370 is in the upstream segment primarily related to the 2005 acquisition of Unocal and $352 is in the downstream segment. The company tested this goodwill for impairment during 2023, and no impairment was required.
Note 28
Financial Instruments - Credit Losses
Chevron’s expected credit loss allowance balance was $641 and $1,009 at December 31, 2023 and December 31, 2022, respectively, with a majority of the allowance relating to non-trade receivable balances.
The majority of the company’s receivable balance is concentrated in trade receivables, with a balance of $17,640 at December 31, 2023, which reflects the company’s diversified sources of revenues and is dispersed across the company’s broad worldwide customer base. As a result, the company believes the concentration of credit risk is limited. The company routinely assesses the financial strength of its customers. When the financial strength of a customer is not considered sufficient, alternative risk mitigation measures may be deployed, including requiring prepayments, letters of credit or other acceptable forms of collateral. Once credit is extended and a receivable balance exists, the company applies a quantitative calculation to current trade receivable balances that reflects credit risk predictive analysis, including probability of default and loss given default, which takes into consideration current and forward-looking market data as well as the company’s historical loss data. This statistical approach becomes the basis of the company’s expected credit loss allowance for current trade receivables with payment terms that are typically short-term in nature, with most due in less than 90 days.
Chevron’s non-trade receivable balance was $3,864 at December 31, 2023, which includes receivables from certain governments in their capacity as joint venture partners. Joint venture partner balances that are paid as per contract terms or not yet due are subject to the statistical analysis described above while past due balances are subject to additional qualitative management quarterly review. This management review includes review of reasonable and supportable repayment forecasts. Non-trade receivables also include employee and tax receivables that are deemed immaterial and low risk. Loans to equity affiliates and non-equity investees are also considered non-trade and associated allowances of $219 and $560 at December 31, 2023 and December 31, 2022, respectively, are included within “Investments and advances” on the Consolidated Balance Sheet.
| | | | | | | | |
| Notes to the Consolidated Financial Statements | |
| Millions of dollars, except per-share amounts | |
Note 29
Acquisition of PDC Energy, Inc.
On August 7, 2023, the company acquired PDC Energy, Inc. (PDC), an independent exploration and production company with operations in the Denver-Julesburg Basin in Colorado and the Delaware Basin in west Texas.
The aggregate purchase price of PDC was $6,520, with approximately 41 million shares of Chevron common stock issued as consideration in the transaction. The shares represented approximately two percent of the shares of Chevron common stock outstanding immediately after the transaction closed on August 7, 2023.
The acquisition was accounted for as a business combination under ASC 805, which requires assets acquired and liabilities assumed to be measured at their acquisition date fair value. Provisional fair value measurements were made for acquired assets and liabilities, and adjustments to those measurements may be made in subsequent periods, up to one year from the date of acquisition, as information necessary to complete the analysis is obtained. Oil and gas properties were valued using a discounted cash flow approach that incorporated internally generated price assumptions and production profiles together with appropriate operating cost and development cost assumptions. Debt assumed in the acquisition was valued based on observable market prices for PDC’s debt. As a result of measuring the assets acquired and the liabilities assumed at fair value, there was no goodwill or bargain purchase recognized.
The following table summarizes the provisional fair values assigned to assets acquired and liabilities assumed:
| | | | | | | | | | | |
| | | At August 7, 2023 |
| Current assets | | | $ | 630 | |
| Properties, plant and equipment | | | 10,487 | |
| Other assets | | | 118 | |
| Total assets acquired | | | 11,235 | |
| Current liabilities | | | 1,376 | |
| Long-term debt | | | 1,473 | |
| Deferred income tax | | | 1,397 | |
| Other liabilities | | | 469 | |
| Total liabilities assumed | | | 4,715 | |
| Purchase Price | | | $ | 6,520 | |
Pro forma financial information is not disclosed as the acquisition was deemed not to have a material impact on the company’s results of operations.
Note 30
Agreement to Acquire Hess Corporation
On October 23, 2023, Chevron Corporation announced it had entered into a definitive agreement with Hess Corporation (Hess) to acquire all of its outstanding shares in an all-stock transaction, valued at approximately $53,000, pursuant to which Hess stockholders will receive 1.0250 shares of Chevron common stock for each Hess share. The transaction was unanimously approved by the Boards of Directors of both companies and is anticipated to close around the middle of 2024. The acquisition is subject to Hess stockholder approval. It is also subject to regulatory approvals and other closing conditions. See Item 1A. Risk Factors for a discussion of risks related to the Hess acquisition.
| | | | | | | | |
| 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, 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 | |
| Year Ended December 31, 2021 | | | | | | | | | | |
| Exploration | | | | | | | | | | |
| Wells | $ | 184 | | $ | 31 | | $ | 5 | | $ | 36 | | $ | — | | $ | — | | $ | 256 | | | $ | — | | $ | — | |
| Geological and geophysical | 67 | | 58 | | 40 | | — | | 22 | | — | | 187 | | | — | | — | |
| Other | 80 | | 80 | | 39 | | 14 | | 25 | | 1 | | 239 | | | — | | — | |
| Total exploration | 331 | | 169 | | 84 | | 50 | | 47 | | 1 | | 682 | | | — | | — | |
Property acquisitions2 | | | | | | | | | | |
| Proved - Other | 98 | | — | | 15 | | 53 | | — | | — | | 166 | | | — | | — | |
| Unproved - Other | 13 | | 16 | | — | | — | | — | | — | | 29 | | | — | | — | |
| Total property acquisitions | 111 | | 16 | | 15 | | 53 | | — | | — | | 195 | | | — | | — | |
Development3 | 4,360 | | 640 | | 383 | | 545 | | 526 | | 44 | | 6,498 | | | 2,442 | | 27 | |
Total Costs Incurred4 | $ | 4,802 | | $ | 825 | | $ | 482 | | $ | 648 | | $ | 573 | | $ | 45 | | $ | 7,375 | | | $ | 2,442 | | $ | 27 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| 1 | Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. Includes capitalized amounts related to asset retirement obligations. See Note 25 Asset Retirement Obligations. |
| 2 | Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired in nonmonetary transactions. |
| 3 | Includes $208, $186 and $298 of costs incurred on major capital projects prior to assignment of proved reserves for consolidated companies in 2023, 2022, and 2021, respectively. |
| 4 | Reconciliation of consolidated companies total cost incurred to Upstream Capex - $ billions: |
| | 2023 | | 2022 | | 2021 | |
| Total cost incurred by Consolidated Companies | $ | 24.6 | | | $ | 9.8 | | | $ | 7.4 | | |
| PDC Energy, Inc. (PDC) acquisition | (10.5) | | | — | | | — | | |
| Expensed exploration costs | (0.5) | | | (0.5) | | | (0.4) | | (Geological and geophysical and other exploration costs) |
| Non-oil and gas activities | 1.4 | | | 0.6 | | | 0.2 | | (Primarily LNG and transportation activities) |
| ARO reduction/(build) | (1.3) | | | (0.3) | | | (0.4) | | |
| Upstream Capex | $ | 13.7 | | | $ | 9.6 | | | $ | 6.8 | | Reference page 48 Upstream Capex |
| | | | | | | | |
| 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, 2023 | | | | | | | | | | |
| Unproved properties | $ | 2,541 | | $ | 1,666 | | $ | 265 | | $ | 536 | | $ | 1,882 | | $ | — | | $ | 6,890 | | | $ | 108 | | $ | — | |
Proved properties and
related producing assets | 100,680 | | 23,867 | | 47,635 | | 30,387 | | 23,842 | | 2,228 | | 228,639 | | | 23,139 | | 1,609 | |
| Support equipment | 2,121 | | 191 | | 1,555 | | 688 | | 19,118 | | — | | 23,673 | | | 673 | | — | |
| Deferred exploratory wells | — | | 73 | | 205 | | 178 | | 1,119 | | 74 | | 1,649 | | | — | | — | |
| Other uncompleted projects | 10,872 | | 734 | | 1,271 | | 1,121 | | 1,469 | | 52 | | 15,519 | | | 15,438 | | 130 | |
| Gross Capitalized Costs | 116,214 | | 26,531 | | 50,931 | | 32,910 | | 47,430 | | 2,354 | | 276,370 | | | 39,358 | | 1,739 | |
| Unproved properties valuation | 168 | | 1,214 | | 183 | | 533 | | 5 | | — | | 2,103 | | | 77 | | — | |
| Proved producing properties – Depreciation and depletion | 65,055 | | 14,009 | | 39,921 | | 18,941 | | 12,082 | | 834 | | 150,842 | | | 10,279 | | 866 | |
| Support equipment depreciation | 1,295 | | 155 | | 1,202 | | 529 | | 5,478 | | — | | 8,659 | | | 478 | | — | |
| Accumulated provisions | 66,518 | | 15,378 | | 41,306 | | 20,003 | | 17,565 | | 834 | | 161,604 | | | 10,834 | | 866 | |
| Net Capitalized Costs | $ | 49,696 | | $ | 11,153 | | $ | 9,625 | | $ | 12,907 | | $ | 29,865 | | $ | 1,520 | | $ | 114,766 | | | $ | 28,524 | | $ | 873 | |
| At December 31, 2022 | | | | | | | | | | |
| Unproved properties | $ | 2,541 | | $ | 2,176 | | $ | 265 | | $ | 970 | | $ | 1,987 | | $ | — | | $ | 7,939 | | | $ | 108 | | $ | — | |
Proved properties and
related producing assets | 83,525 | | 22,867 | | 46,950 | | 31,179 | | 22,926 | | 2,186 | | 209,633 | | | 15,793 | | 1,552 | |
| Support equipment | 2,146 | | 194 | | 1,543 | | 696 | | 19,107 | | — | | 23,686 | | | 646 | | — | |
| Deferred exploratory wells | 43 | | 56 | | 116 | | 40 | | 1,119 | | 74 | | 1,448 | | | — | | — | |
| Other uncompleted projects | 8,213 | | 610 | | 1,095 | | 914 | | 1,869 | | 30 | | 12,731 | | | 20,590 | | 54 | |
| Gross Capitalized Costs | 96,468 | | 25,903 | | 49,969 | | 33,799 | | 47,008 | | 2,290 | | 255,437 | | | 37,137 | | 1,606 | |
| Unproved properties valuation | 178 | | 1,589 | | 146 | | 969 | | 110 | | — | | 2,992 | | | 74 | | — | |
| Proved producing properties – Depreciation and depletion | 58,253 | | 12,974 | | 38,543 | | 19,051 | | 10,689 | | 720 | | 140,230 | | | 9,441 | | 654 | |
| Support equipment depreciation | 1,302 | | 155 | | 1,166 | | 500 | | 4,644 | | — | | 7,767 | | | 424 | | — | |
| Accumulated provisions | 59,733 | | 14,718 | | 39,855 | | 20,520 | | 15,443 | | 720 | | 150,989 | | | 9,939 | | 654 | |
| Net Capitalized Costs | $ | 36,735 | | $ | 11,185 | | $ | 10,114 | | $ | 13,279 | | $ | 31,565 | | $ | 1,570 | | $ | 104,448 | | | $ | 27,198 | | $ | 952 | |
| At December 31, 2021 | | | | | | | | | | |
| Unproved properties | $ | 3,302 | | $ | 2,382 | | $ | 191 | | $ | 982 | | $ | 1,987 | | $ | — | | $ | 8,844 | | | $ | 108 | | $ | — | |
Proved properties and
related producing assets | 80,821 | | 22,031 | | 47,030 | | 46,379 | | 22,235 | | 2,156 | | 220,652 | | | 14,635 | | 1,558 | |
| Support equipment | 2,134 | | 198 | | 1,096 | | 906 | | 18,918 | | — | | 23,252 | | | 582 | | — | |
| Deferred exploratory wells | 328 | | 121 | | 196 | | 246 | | 1,144 | | 74 | | 2,109 | | | — | | — | |
| Other uncompleted projects | 6,581 | | 431 | | 1,096 | | 903 | | 1,586 | | 24 | | 10,621 | | | 19,382 | | 31 | |
| Gross Capitalized Costs | 93,166 | | 25,163 | | 49,609 | | 49,416 | | 45,870 | | 2,254 | | 265,478 | | | 34,707 | | 1,589 | |
| Unproved properties valuation | 289 | | 1,536 | | 131 | | 855 | | 110 | | — | | 2,921 | | | 70 | | — | |
| Proved producing properties – Depreciation and depletion | 55,064 | | 11,745 | | 37,657 | | 33,300 | | 8,920 | | 602 | | 147,288 | | | 8,461 | | 514 | |
| Support equipment depreciation | 1,681 | | 155 | | 778 | | 623 | | 3,724 | | — | | 6,961 | | | 362 | | — | |
| Accumulated provisions | 57,034 | | 13,436 | | 38,566 | | 34,778 | | 12,754 | | 602 | | 157,170 | | | 8,893 | | 514 | |
| Net Capitalized Costs | $ | 36,132 | | $ | 11,727 | | $ | 11,043 | | $ | 14,638 | | $ | 33,116 | | $ | 1,652 | | $ | 108,308 | | | $ | 25,814 | | $ | 1,075 | |
| | | | | | | | |
| 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 2023, 2022 and 2021 are shown in the following table. Net income (loss) from exploration and production activities as reported on page 79 reflects income taxes computed on an effective rate basis.
Income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense are excluded from the results reported in Table III and from the upstream net income amounts on page 79.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated Companies | | Affiliated Companies |
| | Other | | | | | | | | |
| Millions of dollars | U.S. | Americas | Africa | Asia | Australia | Europe | Total | | TCO | Other |
| Year Ended December 31, 2023 | | | | | | | | | | |
| Revenues from net production | | | | | | | | | | |
| Sales | $ | 6,658 | | $ | 724 | | $ | 515 | | $ | 3,309 | | $ | 6,780 | | $ | 368 | | $ | 18,354 | | | $ | 6,831 | | $ | 891 | |
| Transfers | 15,948 | | 3,243 | | 5,979 | | 2,151 | | 4,753 | | — | | 32,074 | | | — | | — | |
| Total | 22,606 | | 3,967 | | 6,494 | | 5,460 | | 11,533 | | 368 | | 50,428 | | | 6,831 | | 891 | |
| Production expenses excluding taxes | (5,459) | | (1,000) | | (1,619) | | (1,103) | | (556) | | (64) | | (9,801) | | | (602) | | (44) | |
| Taxes other than on income | (1,222) | | (69) | | (142) | | (27) | | (256) | | (4) | | (1,720) | | | (675) | | — | |
| Proved producing properties: | | | | | | | | | | |
| Depreciation and depletion | (7,133) | | (1,042) | | (1,414) | | (1,114) | | (2,561) | | (115) | | (13,379) | | | (895) | | (173) | |
Accretion 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 | |
| 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 | |
1The 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.
3Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses. 2023 also includes a loss related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S. Gulf of Mexico.
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
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, 2021 | | | | | | | | | | |
| Revenues from net production | | | | | | | | | | |
| Sales | $ | 6,708 | | $ | 888 | | $ | 1,283 | | $ | 5,127 | | $ | 3,725 | | $ | 371 | | $ | 18,102 | | | $ | 5,564 | | $ | 868 | |
| Transfers | 12,653 | | 3,029 | | 5,232 | | 3,019 | | 3,858 | | — | | 27,791 | | | — | | — | |
| Total | 19,361 | | 3,917 | | 6,515 | | 8,146 | | 7,583 | | 371 | | 45,893 | | | 5,564 | | 868 | |
| Production expenses excluding taxes | (4,325) | | (974) | | (1,414) | | (2,156) | | (548) | | (67) | | (9,484) | | | (487) | | (20) | |
| Taxes other than on income | (928) | | (73) | | (88) | | (15) | | (260) | | (4) | | (1,368) | | | (359) | | — | |
| Proved producing properties: | | | | | | | | | | |
| Depreciation and depletion | (5,184) | | (1,470) | | (1,797) | | (3,324) | | (2,409) | | (105) | | (14,289) | | | (947) | | (215) | |
Accretion expense2 | (197) | | (22) | | (144) | | (113) | | (75) | | (13) | | (564) | | | (7) | | (3) | |
| Exploration expenses | (221) | | (132) | | (83) | | (20) | | (47) | | (35) | | (538) | | | — | | — | |
| Unproved properties valuation | (43) | | (95) | | (5) | | — | | — | | — | | (143) | | | — | | — | |
Other income (loss)3 | 990 | | (33) | | (72) | | (124) | | 26 | | 2 | | 789 | | | 98 | | (332) | |
| Results before income taxes | 9,453 | | 1,118 | | 2,912 | | 2,394 | | 4,270 | | 149 | | 20,296 | | | 3,862 | | 298 | |
| Income tax (expense) benefit | (2,108) | | (318) | | (1,239) | | (1,326) | | (1,314) | | (38) | | (6,343) | | | (1,161) | | 29 | |
| Results of Producing Operations | $ | 7,345 | | $ | 800 | | $ | 1,673 | | $ | 1,068 | | $ | 2,956 | | $ | 111 | | $ | 13,953 | | | $ | 2,701 | | $ | 327 | |
1The 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.
3Includes 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, 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 |
| Year Ended December 31, 2021 | | | | | | | | | | |
| Average sales prices | | | | | | | | | | |
| Crude, per barrel | $ | 65.16 | | $ | 62.84 | | $ | 72.38 | | $ | 63.71 | | $ | 71.40 | | $ | 69.20 | | $ | 66.14 | | | $ | 58.31 | | $ | — | |
| Natural gas liquids, per barrel | 28.54 | | 26.33 | | 39.40 | | — | | 30.00 | | — | | 29.10 | | | 27.13 | | 66.00 | |
| Natural gas, per thousand cubic feet | 3.02 | | 3.39 | | 2.66 | | 4.10 | | 8.22 | | 12.50 | | 5.08 | | | 0.47 | | 9.71 | |
Average production costs, per barrel2 | 10.45 | | 13.91 | | 12.40 | | 10.52 | | 3.65 | | 13.40 | | 9.90 | | | 4.09 | | 1.25 | |
1The 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.
2Natural 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
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 |
| Liquids in Millions of Barrels | | | | | | | | | | | | | |
| Natural Gas in Billions of Cubic Feet | Crude Oil
Condensate | SyntheticOil | NGL | Natural
Gas | | Crude Oil
Condensate | SyntheticOil | NGL | Natural
Gas | | Crude Oil
Condensate | SyntheticOil | NGL | Natural
Gas |
| Proved Developed | | | | | | | | | | | | | | |
| Consolidated Companies | | | | | | | | | | | | | | |
| U.S. | 1,221 | | — | | 611 | | 4,543 | | | 1,198 | | — | | 450 | | 3,288 | | | 1,177 | | — | | 421 | | 3,136 | |
| Other Americas | 195 | | 598 | | 7 | | 298 | | | 174 | | 574 | | 7 | | 305 | | | 181 | | 471 | | 7 | | 259 | |
| Africa | 367 | | — | | 70 | | 1,632 | | | 392 | | — | | 72 | | 1,734 | | | 428 | | — | | 77 | | 1,884 | |
| Asia | 240 | | — | | — | | 6,974 | | | 235 | | — | | — | | 6,578 | | | 270 | | — | | — | | 7,007 | |
| Australia | 85 | | — | | 2 | | 6,951 | | | 99 | | — | | 3 | | 7,898 | | | 102 | | — | | 3 | | 8,057 | |
| Europe | 25 | | — | | — | | 9 | | | 26 | | — | | — | | 9 | | | 24 | | — | | — | | 8 | |
| Total Consolidated | 2,133 | | 598 | | 690 | | 20,407 | | | 2,124 | | 574 | | 532 | | 19,812 | | | 2,182 | | 471 | | 508 | | 20,351 | |
| Affiliated Companies | | | | | | | | | | | | | | |
| TCO | 478 | | — | | 67 | | 1,062 | | | 515 | | — | | 52 | | 895 | | | 555 | | — | | 52 | | 1,059 | |
| Other | 3 | | — | | 13 | | 323 | | | 3 | | — | | 13 | | 349 | | | 3 | | — | | 13 | | 310 | |
| Total Consolidated and Affiliated Companies | 2,614 | | 598 | | 770 | | 21,792 | | | 2,642 | | 574 | | 597 | | 21,056 | | | 2,740 | | 471 | | 573 | | 21,720 | |
| Proved Undeveloped | | | | | | | | | | | | | | |
| Consolidated Companies | | | | | | | | | | | | | | |
| U.S. | 721 | | — | | 413 | | 3,139 | | | 875 | | — | | 435 | | 3,543 | | | 887 | | — | | 391 | | 2,749 | |
| Other Americas | 129 | | — | | 8 | | 276 | | | 121 | | — | | 10 | | 240 | | | 107 | | — | | 8 | | 196 | |
| Africa | 78 | | — | | 27 | | 625 | | | 62 | | — | | 25 | | 756 | | | 52 | | — | | 28 | | 912 | |
| Asia | 61 | | — | | — | | 1,419 | | | 58 | | — | | — | | 1,959 | | | 52 | | — | | — | | 466 | |
| Australia | 22 | | — | | — | | 2,444 | | | 22 | | — | | — | | 2,444 | | | 32 | | — | | — | | 3,627 | |
| Europe | 28 | | — | | — | | 8 | | | 32 | | — | | — | | 11 | | | 38 | | — | | — | | 13 | |
| Total Consolidated | 1,039 | | — | | 448 | | 7,911 | | | 1,170 | | — | | 470 | | 8,953 | | | 1,168 | | — | | 427 | | 7,963 | |
| Affiliated Companies | | | | | | | | | | | | | | |
| TCO | 526 | | — | | 11 | | 233 | | | 611 | | — | | 21 | | 368 | | | 695 | | — | | 32 | | 642 | |
| Other | — | | — | | — | | 445 | | | — | | — | | — | | 487 | | | 1 | | — | | 6 | | 583 | |
| Total Consolidated and Affiliated Companies | 1,565 | | — | | 459 | | 8,589 | | | 1,781 | | — | | 491 | | 9,808 | | | 1,864 | | — | | 465 | | 9,188 | |
| Total Proved Reserves | 4,179 | | 598 | | 1,229 | | 30,381 | | | 4,423 | | 574 | | 1,088 | | 30,864 | | | 4,604 | | 471 | | 1,038 | | 30,908 | |
* Reserve quantities include natural gas projected to be consumed in operations of 2,655, 2,737 and 2,505 billions of cubic feet and equivalent synthetic oil projected to be consumed in operations of 27, 28 and 17 millions of barrels as of December 31, 2023, 2022 and 2021, respectively.
Reserves Governance The company has adopted a comprehensive reserves and resources classification system modeled after a system developed and approved by a number of organizations, including the Society of Petroleum Engineers, the World Petroleum Congress and the American Association of Petroleum Geologists. The company classifies discovered recoverable hydrocarbons into six categories based on their status at the time of reporting – three deemed commercial and three potentially recoverable. Within the commercial classification are proved reserves and two categories of unproved reserves: probable and possible. The potentially recoverable categories are also referred to as contingent resources. For reserves estimates to be classified as proved, they must meet all SEC and company standards.
Proved oil and gas reserves are the estimated quantities that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in the future from known reservoirs under existing economic conditions, operating methods and government regulations. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.
Proved reserves are classified as either developed or undeveloped. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are the quantities expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
Proved reserves are estimated by company asset teams composed of earth scientists and engineers. As part of the internal control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired by the Manager of Global Reserves, an organization that is separate from the business units that estimate reserves. The Manager of Global Reserves has more than 30 years of experience working in the oil and gas industry and holds both undergraduate and graduate degrees in geoscience. His experience includes various technical and management roles in providing reserve and resource estimates in support of major capital and exploration projects, and more than 10 years of overseeing oil and gas reserves processes. He has been named a Distinguished Lecturer by the American Association of Petroleum Geologists and is an active member of the American Association of Petroleum Geologists, the SEPM Society of Sedimentary Geologists and the Society of Petroleum Engineers.
All RAC members are degreed professionals, each with more than 10 years of experience in various aspects of reserves estimation relating to reservoir engineering, petroleum engineering, earth science or finance. The members are knowledgeable in SEC guidelines for proved reserves classification and receive annual training on the preparation of reserves estimates.
The RAC has the following primary responsibilities: establish the policies and processes used within the business units to estimate reserves; provide independent reviews and oversight of the business units’ recommended reserves estimates and changes; confirm that proved reserves are recognized in accordance with SEC guidelines; determine that reserve quantities are calculated using consistent and appropriate standards, procedures and technology; and maintain the Chevron Corporation Reserves Manual, which provides standardized procedures used corporatewide for classifying and reporting hydrocarbon reserves.
During the year, the RAC is represented in meetings with each of the company’s business units to review and discuss reserve changes recommended by the various asset teams. Major changes are also reviewed with the company’s senior leadership team including the Chief Executive Officer and the Chief Financial Officer. The company’s annual reserves activity is also reviewed with the Board Audit Committee and the Board of Directors. If major changes to reserves were to occur between the annual reviews, those matters would also be discussed with the Board.
RAC sub-teams also conduct in-depth reviews during the year of many of the fields that have large proved reserves quantities. These reviews include an examination of the proved reserve records and documentation of their compliance with the Chevron Corporation Reserves Manual.
Technologies Used in Establishing Proved Reserves Additions In 2023, additions to Chevron’s proved reserves were based on a wide range of geologic and engineering technologies. Information generated from wells, such as well logs, wire line sampling, production and pressure testing, fluid analysis, and core analysis, was integrated with seismic data, regional geologic studies, and information from analogous reservoirs to provide “reasonably certain” proved reserves estimates. Both proprietary and commercially available analytic tools, including reservoir simulation, geologic modeling and seismic processing, have been used in the interpretation of the subsurface data. These technologies have been utilized extensively by the company in the past, and the company believes that they provide a high degree of confidence in establishing reliable and consistent reserves estimates.
Proved Undeveloped Reserves
Noteworthy changes in proved undeveloped reserves are shown in the table below and discussed below.
| | | | | |
Proved Undeveloped Reserves (Millions of BOE) | 2023 |
| Quantity at January 1 | 3,907 | |
| Revisions | (481) | |
| Improved recovery | — | |
| Extension and discoveries | 314 | |
| Purchases | 312 | |
| Sales | — | |
| Transfers to proved developed | (596) | |
| Quantity at December 31 | 3,456 | |
In 2023, revisions include a net decrease of 407 million BOE in the United States. Revisions in Midland and Delaware basins yielded a decrease of 275 million BOE mainly due to a decrease of 186 million BOE from portfolio optimization and a reduction of 74 million BOE from reservoir performance. Reduced development activities contributed to a net decrease of 114 million BOE in east Texas and California. In Kazakhstan, primarily at TCO, performance-driven reservoir model changes led to a net decrease of 107 million BOE to proved undeveloped reserves with a largely offsetting increase
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
to proved developed reserves in existing wells. These reductions were partially offset by an increase of 49 million BOE in Israel mainly due to the final investment decision on a new gas pipeline project.
In 2023, extensions and discoveries of 258 million BOE in the United States were primarily due to planned development of new locations in shale and tight assets in the Midland and Delaware basins of 173 million BOE and the DJ basin of 49 million BOE, and deepwater assets in the Gulf of Mexico of 36 million BOE. In Other Americas, 57 million BOE of extensions and discoveries were mainly from shale and tight assets in Argentina.
In 2023, purchases of 301 million BOE in the United States are primarily from the acquisition of PDC.
The difference in 2023 extensions and discoveries of 127 million BOE, between the net quantities of proved reserves of 441 million BOE as reflected on pages 110 to 112 and net quantities of proved undeveloped reserves of 314 million BOE, is primarily due to proved extensions and discoveries that were not recognized as proved undeveloped reserves in the prior year and were recognized directly as proved developed reserves in 2023.
Transfers to proved developed reserves in 2023 include 395 million BOE in the United States, primarily from 268 million BOE in the Midland and Delaware basins, 83 million BOE in the DJ basin, and 44 million BOE in the Gulf of Mexico. Other significant transfers to proved developed are 114 million BOE in Israel and a combined 87 million BOE in Bangladesh, Argentina, Canada, Kazakhstan, and other international locations. These transfers are the consequence of development expenditures on completing wells and facilities.
During 2023, investments totaling approximately $9.1 billion in oil and gas producing activities and about $0.1 billion in non-oil and gas producing activities were expended to advance the development of proved undeveloped reserves. The United States accounted for about $5.0 billion primarily related to various development activities in the Midland and Delaware basins and the Gulf of Mexico. In Asia, expenditures during the year totaled approximately $2.5 billion, primarily related to development projects for TCO in Kazakhstan. An additional $0.3 billion were spent on development activities in Australia. In Africa, about $0.7 billion was expended on various offshore development and natural gas projects in Nigeria, Angola and Republic of Congo. Development activities in other international locations were primarily responsible for about $0.6 billion of expenditures.
Reserves that remain proved undeveloped for five or more years are a result of several factors that affect optimal project development and execution. These factors may include the complex nature of the development project in adverse and remote locations, physical limitations of infrastructure or plant capacities that dictate project timing, compression projects that are pending reservoir pressure declines, and contractual limitations that dictate production levels.
At year-end 2023, the company held approximately 1 billion BOE of proved undeveloped reserves that have remained undeveloped for five years or more. The majority of these reserves are in locations where the company has a proven track record of developing major projects. In Australia, approximately 235 million BOE remain undeveloped for five years or more related to the Gorgon and Wheatstone Projects. Further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with operating constraints, reservoir depletion and infrastructure optimization. In Africa, approximately 137 million BOE have remained undeveloped for five years or more, primarily due to facility constraints at various fields and infrastructure associated with the Escravos gas projects in Nigeria. Affiliates account for about 650 million BOE of proved undeveloped reserves with about 575 million BOE that have remained undeveloped for five years or more. Approximately 511 million BOE are related to TCO in Kazakhstan and about 64 million BOE are related to Angola LNG. At TCO and Angola LNG, further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with reservoir depletion and facility constraints.
Annually, the company assesses whether any changes have occurred in facts or circumstances, such as changes to development plans, regulations, or government policies, that would warrant a revision to reserve estimates. In 2023, lower commodity prices negatively impacted the economic limits of oil and gas properties, resulting in a proved reserve decrease of approximately 135 million BOE, and positively impacted proved reserves due to entitlement effects, resulting in a proved reserves increase of approximately 89 million BOE. The year-end reserves quantities have been updated for these circumstances and significant changes have been discussed in the appropriate reserves sections. Over the past three years, the ratio of proved undeveloped reserves to total proved reserves has ranged between 31 percent and 35 percent.
Proved Reserve Quantities For the three years ended December 31, 2023, the pattern of net reserve changes shown in the following tables is not necessarily indicative of future trends. Apart from acquisitions, the company’s ability to add proved reserves can be affected by events and circumstances that are outside the company’s control, such as delays in government
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
permitting, partner approvals of development plans, changes in oil and gas prices, OPEC constraints, geopolitical uncertainties, civil unrest, events of war or military conflicts.
At December 31, 2023, proved reserves for the company were 11 billion BOE. The company’s estimated net proved reserves of liquids, including crude oil, condensate and synthetic oil for the years 2021, 2022 and 2023, are shown in the table on page 110. The company’s estimated net proved reserves of natural gas liquids (NGLs) are shown on page 111, and the company’s estimated net proved reserves of natural gas are shown on page 112.
Noteworthy changes in crude oil, condensate and synthetic oil proved reserves for 2021 through 2023 are discussed below and shown in the table on the following page:
Revisions In 2021, the 206 million barrels increase in United States was primarily in the Gulf of Mexico and the Midland and Delaware basins. The higher commodity price environment led to the increase of 126 million barrels in the Gulf of Mexico primarily from Anchor and a 68 million barrels increase in the Midland and Delaware basins due to higher planned development activity. In TCO, entitlement effects and technical changes in field operating assumptions, reservoir model, and project schedule were primarily responsible for the 208 million barrels decrease in Kazakhstan. Entitlement effects primarily contributed to a decrease of 106 million barrels of synthetic oil at the Athabasca Oil Sands project in Canada. In the Other Americas, performance revisions and price effects, mainly in Canada and Argentina, were primarily responsible for the 41 million barrels increase.
In 2022, entitlement effects primarily contributed to a decrease of 49 million barrels of synthetic oil at the Athabasca Oil Sands project in Canada. In TCO, entitlement effects and changes in operating assumptions were primarily responsible for the 35 million barrels decrease in Kazakhstan.
In 2023, the 257 million barrels decrease in United States was primarily in the Midland and Delaware basins and California. Reservoir performance led to the decrease of 101 million barrels, and portfolio optimization led to a decrease of 59 million barrels in the Midland and Delaware basins. A reduction in planned development activities led to a decrease of 58 million barrels in California. In Other Americas, entitlement effects primarily contributed to an increase of 42 million barrels of synthetic oil at the Athabasca Oil Sands project in Canada. In Asia, reservoir performance, mainly in the Partitioned Zone of Saudi Arabia/Kuwait, was responsible for the 48 million barrels increase. Reservoir performance in Nigeria was mainly responsible for the 37 million barrels increase in Africa.
Extensions and Discoveries In 2021, extensions and discoveries in the Midland and Delaware basins, and at the Whale Project in the Gulf of Mexico, were primarily responsible for the 349 million barrels increase in the United States.
In 2022, extensions and discoveries in the Midland, Delaware and DJ basins, and approval of the Ballymore Project in the Gulf of Mexico, were primarily responsible for the 264 million barrels increase in the United States. In Other Americas, the 32 million barrels of extensions and discoveries were from Argentina and Canada.
In 2023, extensions and discoveries of 124 million barrels in the Midland and Delaware basins were primarily responsible for the 170 million barrels increase in the United States. In Other Americas, the 55 million barrels of extensions and discoveries increase was mainly from shale and tight assets in Argentina.
Purchases In 2022, the company exercised its option to acquire additional land acreage in the Athabasca Oil Sands project in Canada contributing 168 million barrels in synthetic oil. The extension of deepwater licenses in Nigeria and the Republic of Congo contributed 36 million barrels in Africa.
In 2023, the acquisition of PDC in the DJ and Delaware basins was primarily responsible for the 207 million barrels increase in the United States.
Sales In 2021, sales of 32 million barrels in the United States were in the Midland and Delaware basins.
| | | | | | | | |
| 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, 2021 | 1,750 | | 260 | | 554 | | 403 | | 141 | | 61 | | 597 | | 3,766 | | | 1,550 | | — | | 3 | | | 5,319 | |
| Changes attributable to: | | | | | | | | | | | | | | |
| Revisions | 206 | | 41 | | 10 | | (8) | | 8 | | 6 | | (106) | | 157 | | | (208) | | — | | 2 | | | (49) | |
| Improved recovery | — | | 9 | | — | | — | | — | | — | | — | | 9 | | | — | | — | | — | | | 9 | |
| Extensions and discoveries | 349 | | 16 | | — | | — | | — | | — | | — | | 365 | | | — | | — | | — | | | 365 | |
| Purchases | 26 | | — | | — | | 2 | | — | | — | | — | | 28 | | | — | | — | | — | | | 28 | |
| Sales | (32) | | — | | — | | (1) | | — | | — | | — | | (33) | | | — | | — | | — | | | (33) | |
| Production | (235) | | (38) | | (84) | | (74) | | (15) | | (5) | | (20) | | (471) | | | (92) | | — | | (1) | | | (564) | |
Reserves at December 31, 2021 4, 5 | 2,064 | | 288 | | 480 | | 322 | | 134 | | 62 | | 471 | | 3,821 | | | 1,250 | | — | | 4 | | | 5,075 | |
| Changes attributable to: | | | | | | | | | | | | | | |
| Revisions | (26) | | (9) | | 4 | | 8 | | 2 | | 1 | | (49) | | (69) | | | (35) | | — | | — | | | (104) | |
| Improved recovery | 2 | | 15 | | 4 | | 5 | | — | | — | | — | | 26 | | | — | | — | | — | | | 26 | |
| Extensions and discoveries | 264 | | 32 | | 6 | | — | | — | | — | | — | | 302 | | | 10 | | — | | — | | | 312 | |
| Purchases | 22 | | 5 | | 36 | | — | | — | | — | | 168 | | 231 | | | — | | — | | — | | | 231 | |
| Sales | (16) | | — | | (3) | | — | | — | | — | | — | | (19) | | | — | | — | | — | | | (19) | |
| Production | (237) | | (36) | | (73) | | (42) | | (15) | | (5) | | (16) | | (424) | | | (99) | | — | | (1) | | | (524) | |
Reserves at December 31, 2022 4, 5 | 2,073 | | 295 | | 454 | | 293 | | 121 | | 58 | | 574 | | 3,868 | | | 1,126 | | — | | 3 | | | 4,997 | |
| Changes attributable to: | | | | | | | | | | | | | | |
| Revisions | (257) | | 9 | | 37 | | 48 | | 1 | | (1) | | 42 | | (121) | | | (20) | | — | | 1 | | | (140) | |
| Improved recovery | 9 | | — | | 2 | | — | | — | | — | | — | | 11 | | | — | | — | | — | | | 11 | |
| Extensions and discoveries | 170 | | 55 | | — | | — | | — | | — | | — | | 225 | | | — | | — | | — | | | 225 | |
| Purchases | 207 | | — | | 24 | | — | | — | | — | | — | | 231 | | | — | | — | | — | | | 231 | |
| Sales | (1) | | — | | — | | — | | — | | — | | — | | (1) | | | — | | — | | — | | | (1) | |
| Production | (259) | | (35) | | (72) | | (40) | | (15) | | (4) | | (18) | | (443) | | | (102) | | — | | (1) | | | (546) | |
Reserves at December 31, 2023 4, 5 | 1,942 | | 324 | | 445 | | 301 | | 107 | | 53 | | 598 | | 3,770 | | | 1,004 | | — | | 3 | | | 4,777 | |
1Ending reserve balances in North America were 188, 185 and 183 and in South America were 136, 110 and 105 in 2023, 2022 and 2021, respectively.
2Reserves associated with Canada.
3Reserves associated with Africa.
4Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to page E-8 for the definition of a PSC). PSC-related reserve quantities are 6 percent, 6 percent and 7 percent for consolidated companies for 2023, 2022 and 2021, respectively.
5Reserve quantities include synthetic oil projected to be consumed in operations of 27, 28 and 17 millions of barrels as of December 31, 2023, 2022 and 2021, respectively.
Noteworthy changes in NGLs proved reserves for 2021 through 2023 are discussed below and shown in the table on the following page:
Revisions In 2021, higher commodity prices resulting in the increase of planned development activity in the Midland and Delaware basins were primarily responsible for the 107 million barrels increase in the United States.
In 2023, the 110 million barrels decrease in the United States was primarily in the Midland and Delaware basins with a decrease of 49 million barrels due to portfolio optimization and a decrease of 29 million barrels due to reservoir performance.
Extensions and Discoveries In 2021, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 190 million barrels increase in the United States.
In 2022, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 163 million barrels increase in the United States.
In 2023, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 92 million barrels increase in the United States.
Purchases In 2023, the acquisition of PDC in the DJ and Delaware basins was primarily responsible for the 262 million barrels increase in the United States.
Sales In 2022, sales of 35 million barrels in the United States were primarily from the divestment of the Eagle Ford shale assets and some properties in the Midland and Delaware basins.
| | | | | | | | |
| 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, 2021 | 593 | | 8 | | 104 | | — | | 4 | | — | | 709 | | | 102 | | 17 | | | 828 | |
| Changes attributable to: | | | | | | | | | | | | |
| Revisions | 107 | | 5 | | 8 | | — | | — | | — | | 120 | | | (10) | | 4 | | | 114 | |
| Improved recovery | — | | — | | — | | — | | — | | — | | — | | | — | | — | | | — | |
| Extensions and discoveries | 190 | | 4 | | — | | — | | — | | — | | 194 | | | — | | — | | | 194 | |
| Purchases | 8 | | — | | — | | — | | — | | — | | 8 | | | — | | — | | | 8 | |
| Sales | (8) | | — | | — | | — | | — | | — | | (8) | | | — | | — | | | (8) | |
| Production | (78) | | (2) | | (6) | | — | | (1) | | — | | (87) | | | (8) | | (3) | | | (98) | |
Reserves at December 31, 20213 | 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 | |
1Reserves associated with North America.
2Reserves associated with Africa.
3Year-end reserve quantities related to PSC are not material for 2023, 2022 and 2021, respectively.
Noteworthy changes in natural gas proved reserves for 2021 through 2023 are discussed below and shown in the table on the following page:
Revisions In 2021, the approval of the Jansz Io Compression project was mainly responsible for the 1.2 trillion cubic feet (TCF) increase in Australia. Higher commodity prices, resulting in the increase of planned development activity in the Midland and Delaware basins, were mainly responsible for the 829 billion cubic feet (BCF) increase in the United States. In TCO, entitlement effects and technical changes in field operating assumptions, reservoir model, and project schedule were primarily responsible for the 179 BCF decrease.
In 2022, the performance of the Leviathan and Tamar fields in Israel and the Bibiyana and Jalalabad fields in Bangladesh were mainly responsible for the 1.8 TCF increase in Asia. In Australia, the 377 BCF decrease was mainly due to updated reservoir characterization of the Wheatstone field. In TCO, entitlement effects and changes in operating assumptions were primarily responsible for the 285 BCF decrease.
In 2023, portfolio optimization decrease of 276 BCF and a reservoir performance decrease of 186 BCF in the Midland and Delaware basins along with a reduction in planned development activities leading to a decrease of 485 BCF in the Haynesville shale formation of east Texas, were mainly responsible for the 1.2 TCF decrease in the United States. In Asia, final investment decision on a new gas pipeline project in Israel and reservoir performance in Bangladesh were mainly responsible for the 481 BCF increase.
Extensions and Discoveries In 2021, extensions and discoveries of 1.4 TCF in the United States were primarily in the Midland and Delaware basins.
In 2022, extensions and discoveries of 1.6 TCF in the United States were primarily in the Midland and Delaware basins.
| | | | | | | | |
| Supplemental Information on Oil and Gas Producing Activities - Unaudited | |
In 2023, extensions and discoveries of 660 BCF in the United States were primarily in the Midland and Delaware basins.
Purchases In 2023, the acquisition of PDC in the DJ basin was primarily responsible for the 2.2 TCF in the United States.
Sales In 2022, sales of 243 BCF in the United States were primarily in the Eagle Ford shale and Midland and Delaware basins.
Net Proved Reserves of Natural Gas
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated Companies | | Affiliated Companies | | Total
Consolidated |
| | Other | | | | | | | | | | and Affiliated |
| Billions of cubic feet (BCF) | U.S. | Americas1 | Africa | Asia | Australia | Europe | Total | | TCO | Other2 | | Companies |
| Reserves at January 1, 2021 | 4,250 | | 329 | | 2,837 | | 8,183 | | 11,385 | | 22 | | 27,006 | | | 2,018 | | 898 | | | 29,922 | |
| Changes attributable to: | | | | | | | | | | | | |
| Revisions | 829 | | 129 | | 147 | | 119 | | 1,181 | | 1 | | 2,406 | | | (179) | | 82 | | | 2,309 | |
| Improved recovery | — | | — | | — | | — | | — | | — | | — | | | — | | — | | | — | |
| Extensions and discoveries | 1,408 | | 63 | | — | | — | | 19 | | — | | 1,490 | | | — | | — | | | 1,490 | |
| Purchases | 44 | | — | | — | | — | | — | | — | | 44 | | | — | | — | | | 44 | |
| Sales | (29) | | — | | — | | — | | (13) | | — | | (42) | | | — | | — | | | (42) | |
Production3 | (617) | | (66) | | (188) | | (829) | | (888) | | (2) | | (2,590) | | | (138) | | (87) | | | (2,815) | |
Reserves at December 31, 2021 4, 5 | 5,885 | | 455 | | 2,796 | | 7,473 | | 11,684 | | 21 | | 28,314 | | | 1,701 | | 893 | | | 30,908 | |
| Changes attributable to: | | | | | | | | | | | | |
| Revisions | 171 | | 62 | | (118) | | 1,765 | | (377) | | 2 | | 1,505 | | | (285) | | 3 | | | 1,223 | |
| Improved recovery | 1 | | — | | — | | — | | — | | — | | 1 | | | — | | — | | | 1 | |
| Extensions and discoveries | 1,573 | | 64 | | — | | — | | — | | — | | 1,637 | | | — | | 17 | | | 1,654 | |
| Purchases | 85 | | 25 | | 30 | | — | | — | | — | | 140 | | | — | | — | | | 140 | |
| Sales | (243) | | — | | (11) | | — | | — | | — | | (254) | | | — | | — | | | (254) | |
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 | |
1Ending reserve balances in North America and South America were 363, 407 and 347 and 211, 138 and 108 in 2023, 2022 and 2021, respectively.
2Reserves associated with Africa.
3Total “as sold” volumes are 2,609, 2,600 and 2,599 for 2023, 2022 and 2021, respectively.
4Includes reserve quantities related to PSC. PSC-related reserve quantities are 7 percent, 8 percent and 8 percent for consolidated companies for 2023, 2022 and 2021, respectively.
5Reserve quantities include natural gas projected to be consumed in operations of 2,655, 2,737 and 2,505 billions of cubic feet as of December 31, 2023, 2022 and 2021, respectively.
| | | | | | | | |
| 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 average of first-day-of-the-month oil and gas prices for the 12-month period prior to the end of the reporting period, estimated future development and production costs assuming the continuation of existing economic conditions, estimated costs for asset retirement obligations (includes costs to retire existing wells and facilities in addition to those future wells and facilities necessary to produce proved undeveloped reserves), and estimated future income taxes based on appropriate statutory tax rates. Discounted future net cash flows are calculated using 10 percent mid-period discount factors. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. The valuation requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and do not represent management’s estimate of the company’s future cash flows or value of its oil and gas reserves. In the following table, the caption “Standardized Measure Net Cash Flows” refers to the standardized measure of discounted future net cash flows.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated Companies | | Affiliated Companies | | Total
Consolidated |
| | Other | | | | | | | | | | and Affiliated |
| Millions of dollars | U.S. | Americas | Africa | Asia | Australia | Europe | Total | | TCO | Other | | Companies |
| At December 31, 2023 | | | | | | | | | | | | |
| Future cash inflows from production | $ | 181,152 | | $ | 65,265 | | $ | 42,786 | | $ | 62,094 | | $ | 99,003 | | $ | 4,395 | | $ | 454,695 | | | $ | 74,758 | | $ | 7,324 | | | $ | 536,777 | |
| Future production costs | (48,784) | | (22,549) | | (16,502) | | (13,000) | | (11,534) | | (1,194) | | (113,563) | | | (21,467) | | (484) | | | (135,514) | |
| Future development costs | (16,938) | | (3,538) | | (4,474) | | (2,845) | | (5,804) | | (438) | | (34,037) | | | (3,617) | | (67) | | | (37,721) | |
| Future income taxes | (21,089) | | (10,337) | | (12,446) | | (27,415) | | (24,499) | | (1,160) | | (96,946) | | | (14,902) | | (2,371) | | | (114,219) | |
| Undiscounted future net cash flows | 94,341 | | 28,841 | | 9,364 | | 18,834 | | 57,166 | | 1,603 | | 210,149 | | | 34,772 | | 4,402 | | | 249,323 | |
| 10 percent midyear annual discount for timing of estimated cash flows | (39,553) | | (16,623) | | (3,262) | | (9,343) | | (22,011) | | (600) | | (91,392) | | | (11,283) | | (1,640) | | | (104,315) | |
Standardized Measure Net Cash Flows | $ | 54,788 | | $ | 12,218 | | $ | 6,102 | | $ | 9,491 | | $ | 35,155 | | $ | 1,003 | | $ | 118,757 | | | $ | 23,489 | | $ | 2,762 | | | $ | 145,008 | |
| At December 31, 2022 | | | | | | | | | | | | |
| Future cash inflows from production | $ | 257,478 | | $ | 76,940 | | $ | 55,865 | | $ | 67,188 | | $ | 147,839 | | $ | 5,920 | | $ | 611,230 | | | $ | 106,114 | | $ | 22,630 | | | $ | 739,974 | |
| Future production costs | (51,022) | | (22,744) | | (16,373) | | (12,261) | | (13,313) | | (1,069) | | (116,782) | | | (28,046) | | (574) | | | (145,402) | |
| Future development costs | (20,907) | | (3,233) | | (2,657) | | (2,879) | | (5,030) | | (502) | | (35,208) | | | (4,127) | | (8) | | | (39,343) | |
| Future income taxes | (40,096) | | (13,207) | | (26,160) | | (30,674) | | (38,861) | | (2,827) | | (151,825) | | | (22,182) | | (7,707) | | | (181,714) | |
| Undiscounted future net cash flows | 145,453 | | 37,756 | | 10,675 | | 21,374 | | 90,635 | | 1,522 | | 307,415 | | | 51,759 | | 14,341 | | | 373,515 | |
| 10 percent midyear annual discount for timing of estimated cash flows | (62,918) | | (22,165) | | (3,001) | | (10,769) | | (37,519) | | (571) | | (136,943) | | | (18,810) | | (5,824) | | | (161,577) | |
Standardized Measure Net Cash Flows | $ | 82,535 | | $ | 15,591 | | $ | 7,674 | | $ | 10,605 | | $ | 53,116 | | $ | 951 | | $ | 170,472 | | | $ | 32,949 | | $ | 8,517 | | | $ | 211,938 | |
| At December 31, 2021 | | | | | | | | | | | | |
| Future cash inflows from production | $ | 174,976 | | $ | 48,328 | | $ | 41,698 | | $ | 52,881 | | $ | 87,676 | | $ | 4,366 | | $ | 409,925 | | | $ | 80,297 | | $ | 8,446 | | | $ | 498,668 | |
| Future production costs | (40,009) | | (16,204) | | (15,204) | | (13,871) | | (13,726) | | (1,400) | | (100,414) | | | (23,354) | | (285) | | | (124,053) | |
| Future development costs | (16,709) | | (2,707) | | (2,245) | | (2,774) | | (5,283) | | (661) | | (30,379) | | | (5,066) | | (18) | | | (35,463) | |
| Future income taxes | (24,182) | | (7,723) | | (17,228) | | (21,064) | | (20,600) | | (922) | | (91,719) | | | (15,563) | | (2,850) | | | (110,132) | |
| Undiscounted future net cash flows | 94,076 | | 21,694 | | 7,021 | | 15,172 | | 48,067 | | 1,383 | | 187,413 | | | 36,314 | | 5,293 | | | 229,020 | |
| 10 percent midyear annual discount for timing of estimated cash flows | (41,357) | | (11,370) | | (1,899) | | (7,277) | | (21,141) | | (485) | | (83,529) | | | (14,372) | | (2,244) | | | (100,145) | |
Standardized Measure Net Cash Flows | $ | 52,719 | | $ | 10,324 | | $ | 5,122 | | $ | 7,895 | | $ | 26,926 | | $ | 898 | | $ | 103,884 | | | $ | 21,942 | | $ | 3,049 | | | $ | 128,875 | |
| | | | | | | | |
| 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, 2021 | | $ | 48,443 | | | | $ | 10,094 | | | | $ | 58,537 | |
| Sales and transfers of oil and gas produced net of production costs | | (34,668) | | | | (5,760) | | | | (40,428) | |
| Development costs incurred | | 5,770 | | | | 2,445 | | | | 8,215 | |
| Purchases of reserves | | 772 | | | | — | | | | 772 | |
| Sales of reserves | | (889) | | | | — | | | | (889) | |
| Extensions, discoveries and improved recovery less related costs | | 12,091 | | | | — | | | | 12,091 | |
| Revisions of previous quantity estimates | | 2,269 | | | | (6,675) | | | | (4,406) | |
| Net changes in prices, development and production costs | | 89,031 | | | | 30,076 | | | | 119,107 | |
| Accretion of discount | | 6,657 | | | | 1,503 | | | | 8,160 | |
| Net change in income tax | | (25,592) | | | | (6,692) | | | | (32,284) | |
| Net Change for 2021 | | 55,441 | | | | 14,897 | | | | 70,338 | |
| Present Value at December 31, 2021 | | $ | 103,884 | | | | $ | 24,991 | | | | $ | 128,875 | |
| Sales and transfers of oil and gas produced net of production costs | | (53,356) | | | | (9,127) | | | | (62,483) | |
| Development costs incurred | | 7,962 | | | | 2,430 | | | | 10,392 | |
| Purchases of reserves | | 2,248 | | | | — | | | | 2,248 | |
| Sales of reserves | | (1,807) | | | | — | | | | (1,807) | |
| Extensions, discoveries and improved recovery less related costs | | 16,054 | | | | 823 | | | | 16,877 | |
| Revisions of previous quantity estimates | | 5,281 | | | | (1,481) | | | | 3,800 | |
| Net changes in prices, development and production costs | | 110,467 | | | | 28,052 | | | | 138,519 | |
| Accretion of discount | | 14,075 | | | | 3,429 | | | | 17,504 | |
| Net change in income tax | | (34,336) | | | | (7,651) | | | | (41,987) | |
| Net Change for 2022 | | 66,588 | | | | 16,475 | | | | 83,063 | |
| Present Value at December 31, 2022 | | $ | 170,472 | | | | $ | 41,466 | | | | $ | 211,938 | |
| Sales and transfers of oil and gas produced net of production costs | | (38,638) | | | | (6,350) | | | | (44,988) | |
| Development costs incurred | | 11,381 | | | | 2,281 | | | | 13,662 | |
| Purchases of reserves | | 9,628 | | | | — | | | | 9,628 | |
| Sales of reserves | | (51) | | | | — | | | | (51) | |
| Extensions, discoveries and improved recovery less related costs | | 7,262 | | | | — | | | | 7,262 | |
| Revisions of previous quantity estimates | | (14,389) | | | | (493) | | | | (14,882) | |
| Net changes in prices, development and production costs | | (80,284) | | | | (23,517) | | | | (103,801) | |
| Accretion of discount | | 23,306 | | | | 5,722 | | | | 29,028 | |
| Net change in income tax | | 30,070 | | | | 7,142 | | | | 37,212 | |
| Net Change for 2023 | | (51,715) | | | | (15,215) | | | | (66,930) | |
| Present Value at December 31, 2023 | | $ | 118,757 | | | | $ | 26,251 | | | | $ | 145,008 | |
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, 2023.
(3) Exhibits:
The Exhibit Index on the following pages lists the exhibits that are filed as part of this report.
Schedule II — Valuation and Qualifying Accounts
| | | | | | | | | | | | | | | | | |
| Year ended December 31 |
| Millions of Dollars | 2023 | | 2022 | | 2021 |
| Employee Termination Benefits | | | | | |
| Balance at January 1 | $ | 11 | | | $ | 43 | | | $ | 470 | |
| Additions (reductions) charged to expense | (2) | | | 1 | | | (30) | |
| Payments | (3) | | | (33) | | | (397) | |
| Balance at December 31 | $ | 6 | | | $ | 11 | | | $ | 43 | |
| Expected Credit Losses | | | | | |
| Beginning allowance balance for expected credit losses | $ | 1,008 | | | $ | 745 | | | $ | 671 | |
| Current period provision | (367) | | | 263 | | | 74 | |
| | | | | |
| Write-offs charged against the allowance, if any | — | | | — | | | — | |
| | | | | |
| Balance at December 31 | $ | 641 | | | $ | 1,008 | | | $ | 745 | |
Deferred Income Tax Valuation Allowance* | | | | | |
| Balance at January 1 | $ | 19,532 | | | $ | 17,651 | | | $ | 17,762 | |
| Additions to deferred income tax expense | 2,348 | | | 3,533 | | | 3,691 | |
| Reduction of deferred income tax expense | (1,464) | | | (1,652) | | | (3,802) | |
| Balance at December 31 | $ | 20,416 | | | $ | 19,532 | | | $ | 17,651 | |
Item 16. Form 10-K Summary
Not applicable.
EXHIBIT INDEX | | | | | |
Exhibit No. | Description |
| 2.1 | |
| 3.1 | |
| 3.2 | |
| 4.1 | Indenture, dated as of June 15, 1995, filed as Exhibit 4.1 to Chevron Corporation’s Amendment Number 1 to Registration Statement on Form S-3 filed June 14, 1995, and incorporated herein by reference. |
| 4.2 | |
| 4.3 | |
| 4.4 | |
| 4.5 | |
| 10.1+ | |
| 10.2+ | |
| 10.3+ | |
| 10.4+ | |
| 10.5+ | |
| 10.6+ | Summary of Chevron Incentive Plan Award Criteria, filed as Exhibit 10.6 to Chevron Corporation's Annual Report on Form 10-K for the year ended December 31, 2022, and incorporated herein by reference. |
| 10.7+ | |
| 10.8+ | |
| 10.9+ | |
| 10.10+ | |
| |
| | | | | |
| Exhibit No. | Description |
| |
| 10.11+ | |
| 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+ |
|
| |
| | | | | |
| Exhibit No. | Description |
| 10.30+ | |
| 10.31+ | |
| 10.32+ | |
| 10.33+ | |
| 10.34+ | |
| 10.35+ | |
| 10.36+ | |
| 10.37+ | |
| 10.38+ | |
| 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 26th day of February, 2024.
| | | | | |
| Chevron Corporation
|
| By: | /s/ MICHAEL K. WIRTH |
| Michael K. Wirth, Chairman of the Board
and Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 26th day of February, 2024.
| | | |
| Principal Executive Officer | |
| (and Director) | |
| |
/s/ MICHAEL K. WIRTH
Michael K. Wirth, Chairman of the
Board and Chief Executive Officer | |
| |
| |
| Principal Financial Officer | |
| |
/s/ PIERRE R. BREBER
Pierre R. Breber, Vice President
and Chief Financial Officer
| |
| |
| Principal Accounting Officer | |
| |
/s/ ALANA K. KNOWLES
Alana K. Knowles, Vice President
and Controller | |
| |
*By: /s/ MARY A. FRANCIS
Mary A. Francis,
Attorney-in-Fact | |
| | |
| Directors |
|
WANDA M. AUSTIN*
Wanda M. Austin |
|
JOHN B. FRANK*
John B. Frank |
|
ALICE P. GAST*
Alice P. Gast |
|
ENRIQUE HERNANDEZ, JR.*
Enrique Hernandez, Jr. |
|
MARILLYN A. HEWSON* Marillyn A. Hewson |
|
JON M. HUNTSMAN JR.* Jon M. Huntsman Jr. |
|
CHARLES W. MOORMAN*
Charles W. Moorman |
|
DAMBISA F. MOYO*
Dambisa F. Moyo |
|
DEBRA REED-KLAGES*
Debra Reed-Klages |
|
D. JAMES UMPLEBY III*
D. James Umpleby III |
|
CYNTHIA J. WARNER*
Cynthia J. Warner |
|
|
|
|
