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Chevron
CVX
#31
Rank
$368.20 B
Marketcap
๐Ÿ‡บ๐Ÿ‡ธ United States
Country
$184.16
Share price
-0.03%
Change (1 day)
21.49%
Change (1 year)
๐Ÿ›ข Oil&Gas๐Ÿ‡บ๐Ÿ‡ธ Dow jones โšก Energy
Categories
  1. Chevron
  2. Annual Reports (10-K)
  3. Financial Year 2025

Chevron - 10-K annual report 2025


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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, 2025
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)
1400 Smith Street
Delaware94-0890210
Houston, TX 77002-7327
(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 (832) 854-1000
Securities registered pursuant to Section 12(b) of the Act:
 
Title of each classTrading SymbolName of each exchange on which registered
Common stock, par value $.75 per shareCVXNew 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 þ          No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o          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.
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 — $247.4 billion (As of June 30, 2025)
 Number of Shares of Common Stock outstanding as of February 6, 2026 — 1,995,385,539
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of the 2026 Annual Meeting and 2026 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2026 Annual Meeting of Stockholders (in Part III)




TABLE OF CONTENTS

ITEMPAGE
PART I
3
General Development of Business
3
Description of Business and Properties
5
Upstream
5
Downstream
18
Other Businesses
20
21
27
27
29
29
29
PART II
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
30
30
30
30
30
30
30
31
31
PART III
32
33
33
33
33
PART IV
121
121
121
125
1



CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION
FOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995
This Annual Report on Form 10-K of Chevron Corporation contains forward-looking statements relating to Chevron’s operations, assets, and strategy that are based on management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words or phrases such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “advances,” “commits,” “drives,” “aims,” “forecasts,” “projects,” “believes,” “approaches,” “seeks,” “schedules,” “estimates,” “positions,” “pursues,” “progress,” “design,” “enable,” “may,” “can,” “could,” “should,” “will,” “budgets,” “outlook,” “trends,” “guidance,” “focus,” “on track,” “trajectory,” “goals,” “objectives,” “strategies,” “opportunities,” “poised,” “potential,” “ambitions,” “future,” “aspires” and similar expressions, and variations or negatives of these words, are intended to identify such forward-looking statements, but not all forward-looking statements include such words. These statements are not guarantees of future performance and are subject to numerous risks, uncertainties and other factors, many of which are beyond the company’s control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: changing crude oil and natural gas prices and demand for the company’s products, and production curtailments due to market conditions; crude oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries and other producing countries; technological advancements; changes to government policies in the countries in which the company operates; public health crises, such as pandemics and epidemics, and any related government policies and actions; disruptions in the company’s global supply chain, including supply chain constraints and escalation of the cost of goods and services; changing economic, regulatory and political environments in the various countries in which the company operates, including Venezuela; general domestic and international economic, market and political conditions, including the conflict between Russia and Ukraine, the conflict in the Middle East and the global response to these hostilities; changing refining, marketing and chemicals margins; the company’s ability to realize anticipated cost savings and efficiencies associated with enterprise structural cost reduction initiatives; actions of competitors or regulators; timing of exploration expenses; changes in projected future cash flows; timing of crude oil liftings; uncertainties about the estimated quantities of crude oil, natural gas liquids and natural gas reserves; the competitiveness of alternate-energy sources or product substitutes; pace and scale of the development of large carbon capture and storage 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 company’s ability to achieve the anticipated benefits from the acquisition of Hess Corporation; 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 21 through 27 in this report, and as updated in the future. Other unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.
2

PART I
Item 1. Business
General Development of Business
Summary Description of Chevron
Chevron Corporation1, a Delaware corporation, manages its investments in subsidiaries and affiliates and provides administrative, financial, management and technology support to U.S. and international subsidiaries that engage in integrated energy and chemicals operations. Upstream operations consist primarily of exploring for, developing, producing and transporting crude oil and natural gas; processing, liquefaction, transportation and regasification associated with liquefied natural gas; transporting crude oil by major international oil export pipelines; transporting, storage and marketing of natural gas; carbon capture and storage; and a gas-to-liquids plant. Downstream operations consist primarily of refining crude oil into petroleum products; marketing of crude oil, refined products and lubricants; manufacturing and marketing of renewable fuels; transporting crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses and fuel and lubricant additives.
A list of the company’s significant subsidiaries is presented in Exhibit 21.1.
Overview of Petroleum Industry
Petroleum industry operations and profitability are influenced by many factors. Prices for crude oil, natural gas, liquefied natural gas (LNG), petroleum products and petrochemicals are generally determined by supply and demand. Production levels from the members of Organization of Petroleum Exporting Countries (OPEC), Russia and the United States are major factors in determining worldwide supply. Demand for crude oil and its products and for natural gas is largely driven by the conditions of local, national and global economies, although weather patterns, the pace of energy transition and taxation relative to other energy sources also play a significant part. Laws and governmental policies, particularly in the areas of taxation, energy and the environment, affect where and how companies invest, conduct their operations, select feedstocks, and formulate their products and, in some cases, limit their profits directly.
Strong competition exists in all sectors of the petroleum and petrochemical industries in supplying the energy, fuel and chemical needs of industry and individual consumers. In the upstream business, Chevron competes with fully integrated, major global petroleum companies, as well as independent and national petroleum companies, for the acquisition of crude oil and natural gas leases and other properties and for the equipment and labor required to develop and operate those properties. In its downstream business, Chevron competes with fully integrated, major petroleum companies, as well as independent refining and marketing, transportation and chemicals entities and national petroleum companies in the refining, manufacturing, sale and marketing of fuels, lubricants, additives and petrochemicals.
Operating Environment
Refer to Business Environment and Outlook of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the company’s current business environment and outlook.
Chevron’s Strategic Direction
Chevron’s strategy is to leverage our strengths to safely deliver lower carbon energy to a growing world. Our objective is to safely deliver higher returns, lower carbon and superior shareholder value in any business environment. We are leveraging our capabilities, assets, partnerships and customer relationships as we aim to grow our oil and gas business, lower the carbon intensity of operations and grow new energies businesses.
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
1 Incorporated in Delaware in 1926 as Standard Oil Company of California, the company adopted the name Chevron Corporation in 1984 and ChevronTexaco Corporation in 2001. In 2005, ChevronTexaco Corporation changed its name to Chevron Corporation. As used in this report, the term “Chevron” and such terms as “the company,” “the corporation,” “our,” “we,” “us” and "its" may refer to Chevron Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole, but unless stated otherwise they do not include “affiliates” of Chevron — i.e., those companies accounted for by the equity method (generally owned 50 percent or less) or non-equity method investments. All of these terms are used for convenience only and are not intended as a precise description of any of the separate companies, each of which manages its own affairs.
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after such reports are filed with or furnished to the U.S. Securities and Exchange Commission (SEC). The reports are also available on the SEC’s website at www.sec.gov.
Human Capital Management
The Chevron Way explains the company’s purpose, vision and values. It guides how the company’s employees work and establishes a common understanding of culture and aspirations.
Chevron leadership is accountable for investing in the company’s people and culture with the objective of engaging employees to develop their full potential to help deliver energy solutions and enable human progress.
The following table summarizes the number of Chevron employees by sex, where data is available, and by region as of December 31, 2025.
At December 31, 2025
FemaleMaleData not available*Total Employees
Number of EmployeesPercentageNumber of EmployeesPercentageNumber of EmployeesPercentageNumber of EmployeesPercentage
Non-Service Station Employees
U.S.4,645 24 %14,703 76 %18 — %19,366 45 %
Other Americas1,305 33 %2,632 67 %8 — %3,945 9 %
Africa531 16 %2,779 84 %1 — %3,311 8 %
Asia2,732 35 %5,161 65 %12 — %7,905 18 %
Australia480 26 %1,396 74 %3 — %1,879 5 %
Europe401 28 %1,028 71 %25 1 %1,454 3 %
Total Non-Service Station Employees10,094 27 %27,699 73 %67 — %37,860 88 %
Service Station Employees2,344 45 %2,314 45 %521 10 %5,179 12 %
Total Employees12,438 29 %30,013 70 %588 1 %43,039 100 %
* Includes employees where data was not collected or employee chose not to disclose.
Chevron’s approach to attracting, developing and retaining a skilled and diverse global workforce is grounded in creating an environment that supports growth, engagement and operational excellence.
The company’s philosophy is to offer compelling career opportunities and a competitive total compensation and benefits package linked to individual and enterprise performance.
Chevron seeks to foster an inclusive work environment that values the uniqueness and diversity of individual talents, experiences and ideas. Chevron rejects the use of quotas, focuses on removing barriers to opportunity and makes selection decisions based on merit.
Leader accountability and employee engagement remain key indicators of organizational health. Regular employee surveys help monitor engagement, support operational excellence, and track progress in culture, competitive performance, and execution.
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.



4


Description of Business and Properties
The upstream and downstream activities of the company and its equity affiliates are widely dispersed geographically, with operations and projects2 in North America, South America, Europe, Africa, Asia and Australia. These activities are managed by the Oil, Products and Gas organization. Tabulations of segment income statements for the three years ended December 31, 2025, and assets as of the end of 2025 and 2024 — 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. Throughout the document, certain totals and percentages may not sum to their component parts due to rounding.

Upstream
Reserves
Refer to Table V for a tabulation of the company’s proved reserves by geographic area for each year-end from 2023 through 2025. 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, 2025, are summarized in the discussion for Table V. Discussion is also provided regarding the nature of, status of, and planned future activities associated with the development of proved undeveloped reserves. The company recognizes reserves for projects with various development periods, sometimes exceeding five years. The external factors that impact the duration of a project include scope and complexity, remoteness or adverse operating conditions, infrastructure constraints, and contractual limitations.
The company’s proved reserves at year-end 2025 were approximately 10.6 billion barrels of oil-equivalent (BOE), eight percent higher than 2024. The largest additions were from the acquisition of Hess Corporation (Hess) and extensions and discoveries in shale and tight assets in the Permian Basin, and project approvals in Australia and Guyana. At December 31, 2025, 43 percent of the company’s net proved oil-equivalent reserves were located in the United States, 15 percent were located in Australia and 11 percent were located in Kazakhstan.
The net proved reserve balances at the end of each of the three years 2023 through 2025 are shown in the following table:
At December 31
202520242023
Crude Oil, Condensate and Synthetic Oil  — Millions of barrels
Consolidated Companies3,608 3,027 3,770 
Affiliated Companies761 889 1,007 
Total Crude Oil, Condensate and Synthetic Oil4,369 3,916 4,777 
Natural Gas Liquids  — Millions of barrels
Consolidated Companies1,271 1,075 1,138 
Affiliated Companies77 84 91 
Total Natural Gas Liquids1,348 1,159 1,229 
Natural Gas — Billions of cubic feet
Consolidated Companies27,642 26,526 28,318 
Affiliated Companies1,603 1,849 2,063 
Total Natural Gas29,245 28,375 30,381 
Oil-Equivalent — Millions of barrels*
Consolidated Companies9,486 8,523 9,628 
Affiliated Companies1,105 1,281 1,441 
Total Oil-Equivalent10,591 9,804 11,069 
* Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil.
2 As used in this report, the term “project” may describe certain new upstream development activity, individual phases in a multiphase development, maintenance activities, existing assets, new investments in downstream and chemicals capacity, investments in emerging and lower carbon activities, and other activities. All of these terms are used for convenience only and are not intended as a precise description of the term “project” as it relates to any specific governmental law or regulation.


5

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 2025, 2024 and 2023.
Gross and Net Productive Wells
The following table summarizes gross and net productive wells at year-end 2025 for the company and its affiliates:
At December 31, 2025
Productive Oil Wells1
Productive Gas Wells1
Gross Net Gross Net
United States37,907 24,534 1,901 1,528 
Other Americas1,123 564 — — 
Africa1,635 623 46 18 
Asia1,750 834 1,432 455 
Australia532 299 121 34 
Europe33 6 — — 
Total Consolidated Companies42,980 26,860 3,500 2,035 
Affiliates2
1,640 592 — — 
Total Including Affiliates44,620 27,452 3,500 2,035 
Multiple completion wells included above703 395 147 115 
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 1,396 and net 470 productive oil wells for interests accounted for by the non-equity method.

Production Outlook
The company estimates its average worldwide oil-equivalent production in 2026 to increase 7 to 10 percent over 2025, assuming a Brent crude oil price of $60 per barrel and excluding the impact of asset sales. This includes a full-year contribution from Hess assets. This estimate is subject to many factors and uncertainties, as described beginning on page 39. 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, 2025, 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 States4,256 3,707 4,982 3,293 9,238 7,000 
Other Americas29,532 16,027 1,152 303 30,684 16,330 
Africa18,460 11,157 1,283 519 19,743 11,676 
Asia13,417 6,350 1,186 490 14,603 6,840 
Australia3,332 2,597 2,010 771 5,342 3,368 
Europe106 21 12 2 118 23 
Total Consolidated Companies69,103 39,859 10,625 5,378 79,728 45,237 
Affiliates3
693 287 111 51 804 338 
Total Including Affiliates69,796 40,146 10,736 5,429 80,532 45,575 
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 2026, 2027 and 2028 if production is not established by certain required dates are 4,919, 12,250, and 2,968, 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.
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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 2025 and 2024 by the company and its affiliates. Worldwide oil-equivalent production of 3.7 million barrels per day in 2025 was up approximately 12 percent from 2024, mainly due to the acquisition of Hess, completion of the Future Growth Project at Tengizchevroil (TCO), record production in the Permian Basin, and ramp-up of production in the Gulf of America, partially offset by asset sales in Canada and the Republic of Congo. 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-EquivalentCrude OilNatural Gas LiquidsNatural Gas
Thousands of barrels per day (MBD)
(MBD)1
(MBD)2
(MBD)(MMCFD)
Millions of cubic feet per day (MMCFD)20252024202520242025202420252024
United States1,858 1,599 906 782 436 370 3,099 2,684 
Other Americas
Argentina
65 51 52 43 — 74 47 
  Canada3,4
48 132 46 104 6 10 131 
Guyana5
120 — 119 — — 10 
Total Other Americas233 183 217 147 — 6 94 178 
Africa
Angola
58 64 47 52 4 4 45 48 
Equatorial Guinea37 46 7 9 4 5 155 191 
Nigeria
134 129 92 96 5 3 220 183 
Republic of Congo— 28 — 26 — 10 
Total Africa229 267 146 183 13 12 420 432 
Asia
Bangladesh
85 99 2 3 — 494 577 
China
23 29 7 — 139 132 
Israel98 100 1 1 — 581 592 
Kazakhstan
46 45 28 26 — 106 113 
  Malaysia / JDA6
17 — 2 — 92 — 
  Myanmar7
— 4 — — — — 22 
Partitioned Zone65 61 65 60 — 2 5 
Thailand47 47 14 14 — 199 200 
Total Asia381 385 112 111 — — 1,613 1,641 
Australia
 Australia472 479 37 40 1 2 2,605 2,625 
Total Australia472 479 37 40 1 2 2,605 2,625 
Europe
United Kingdom12 12 11 11 — 7 7 
Total Europe12 12 11 11 — — 7 7 
Total Consolidated Companies3,185 2,925 1,429 1,274 450 390 7,838 7,567 
Affiliates8
538 413 398 286 27 25 677 611 
Total Including Affiliates9
3,723 3,338 1,827 1,560 477 415 8,515 8,178 
1 Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil.
2 Includes crude oil, condensate and synthetic oil.
3 Includes synthetic oil:
— 46— 46— — — — 
4 Canada Duvernay shale and AOSP assets were sold in December 2024.
5 Chevron acquired Guyana assets as part of the acquisition of Hess in July 2025.
6 Chevron acquired assets in Malaysia and the Joint Development Area with Thailand (JDA) as part of the acquisition of Hess in July 2025. JDA was sold immediately following the acquisition.
7 Chevron withdrew from Myanmar in April 2024.
8 Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil in Kazakhstan and Angola LNG in Angola.
9 Volumes include natural gas consumed in operations of 646 million and 609 million cubic feet per day in 2025 and 2024, respectively. Total “as sold” natural gas volumes were 7,869 million and 7,569 million cubic feet per day for 2025 and 2024, respectively.


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Delivery Commitments
The company sells crude oil, natural gas, and NGLs from its producing operations under a variety of contractual obligations. Most contracts generally commit the company to sell quantities based on production from specified properties, but some NGLs and natural gas sales contracts specify delivery of fixed and determinable quantities.
In the United States, the company is contractually committed to deliver approximately 110 million barrels of NGLs and 830 billion cubic feet of natural gas to third parties and affiliates from 2026 through 2028. The company believes it can satisfy these contracts through a combination of equity production from the company’s proved developed U.S. reserves and third-party purchases. These commitments are primarily based on contracts with indexed pricing terms.
Outside the United States, the company is contractually committed to deliver a total of 3.2 trillion cubic feet of natural gas to third parties and affiliates from 2026 through 2028 mainly from operations in Australia and Israel. The Australia sales contracts contain variable pricing formulas that generally reference the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery. The sales contracts for Israel contain formulas that generally reflect an initial base price subject to price indexation, Brent-linked or other, over the life of the contract. The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed reserves in these countries.
Development Activities
Refer to Table I for details associated with the company’s development expenditures and costs of proved property acquisitions for 2025, 2024 and 2023.
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, 2025. 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 12/31/25202520242023
Gross Net Prod. Dry Prod. Dry Prod. Dry
United States300 131 927 — 630 3 697 2 
Other Americas54 20 46 — 64 — 39 — 
Africa6 2 8 — 6 — 7 — 
Asia25 8 78 — 72 1 58 2 
Australia— — — — 2 — 3 — 
Europe1 — — — — — — — 
Total Consolidated Companies386 161 1,059 — 774 4 804 4 
Affiliates5 3 8 — 3 — 4 — 
Total Including Affiliates391 164 1,067 — 777 4 808 4 
* 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.
 
 

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Exploration Activities
Refer to Table I for detail on the company’s exploration expenditures and costs of unproved property acquisitions for 2025, 2024 and 2023.
The following table summarizes the company’s net interests in productive and dry exploratory wells completed in each of the past three years, and the number of exploratory wells drilling at December 31, 2025. “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 12/31/25202520242023
Gross Net Prod. Dry Prod. Dry Prod. Dry
United States2 1 3 1 5 2 — 2 
Other Americas— — 1 1 1 — — — 
Africa— — 1 — 1 1 — — 
Asia2 1 1 — 3 2 1 — 
Australia— — — 2 — — — — 
Europe— — — — — — — — 
Total Consolidated Companies4 2 6 4 10 5 1 2 
Affiliates— — — — — — — — 
Total Including Affiliates4 2 6 4 10 5 1 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.
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Review of Ongoing Activities in Key Areas
Chevron has exploration and production activities in many of the world’s major hydrocarbon basins. Chevron’s 2025 key upstream activities, some of which are also discussed in the section Management’s Discussion and Analysis of Financial Condition and Results of Operations, are presented below. The comments include references to “total production” and “net production,” which are defined under “Production” in Exhibit 99.1.
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
Upstream activities in the United States are primarily located in Texas, New Mexico, Colorado, North Dakota, California and the Gulf of America. Acreage for the United States can be found in the Acreage table. Net daily oil-equivalent production in the United States can be found in the Net Production of Crude Oil, Natural Gas Liquids and Natural Gas table.
Texas/New Mexico As one of the largest producers in the Permian Basin, Chevron continues to develop its advantaged portfolio of more than 1,750,000 net acres in the Delaware and Midland basins in West Texas and Southeast New Mexico. In 2025, production reached one million barrels of net oil-equivalent per day. The resource is comprised of stacked formations enabling production of 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. Chevron’s 2025 net daily production in the Permian Basin averaged 435,000 barrels of crude oil, 280,000 barrels of NGLs and 1.8 billion cubic feet of natural gas.
Chevron sold 70 percent of its working interest in Haynesville shale in East Texas in 2025 while retaining a 30 percent non-operated working interest and an approximately 12.5 percent overriding royalty interest in the newly formed joint venture. Chevron holds approximately 70,000 net acres and obtained a capital carry of $450 million for the development of this area through the sale transaction.
Colorado Chevron is the largest oil and natural gas producer in Colorado, where development is focused across approximately 580,000 net acres in the Denver-Julesburg (DJ) Basin. Chevron follows a factory development strategy utilizing multi-well pads to drill a series of horizontal wells that are subsequently completed using hydraulic fracture stimulation. Net daily production in Colorado averaged 125,000 barrels of crude oil, 100,000 barrels of NGLs and 945 million cubic feet of natural gas during the year. Chevron also has operations in Colorado’s Piceance Basin.
North Dakota Chevron holds approximately 469,000 net acres in the Bakken shale play, located in the Williston Basin of North Dakota following its acquisition of Hess. During 2025, there were 121 wells drilled and 127 new wells brought online, bringing the total operated production wells to 1,967. In second-half 2025, net daily production in North Dakota averaged 99,000 barrels of crude oil, 62,000 barrels of NGLs and 260 million cubic feet of natural gas.
Chevron holds an approximately 38 percent consolidated ownership interest in Hess Midstream LP (HESM) following the acquisition of Hess. HESM provides fee-based services for Chevron and third-party customers in the Bakken. The midstream integrated infrastructure is primarily located in McKenzie, Williams, and Mountrail Counties, North Dakota, and Mentor, Minnesota. It includes a natural gas gathering and compression system, a crude oil gathering system and a produced water gathering and disposal system. Key facilities include the Tioga Gas Plant, 50 percent ownership of the Little Missouri 4 gas plant, the Mentor Propane Storage Terminal, the Ramberg Terminal crude oil facility, the Tioga Rail Terminal and a fleet of 550 crude oil rail cars. Additional infrastructure such as the Johnson’s Corner Header System and various connections to the Dakota Access Pipeline provide further crude oil export optionality.
California Chevron owns and operates between 87 and 100 percent interests in six fields in California including Kern River, Cymric/McKittrick, Midway Sunset, San Ardo, Coalinga and Lost Hills. In 2025, Chevron’s California average net
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daily oil-equivalent production was 63,000 barrels. Following Kern County’s reinstatement of drilling permit approvals, Chevron plans to undertake limited development drilling in 2026.
Gulf of America Chevron is the largest acreage holder in the Gulf of America, following its acquisition of Hess. During 2025, Chevron’s net daily production in the Gulf of America averaged 235,000 barrels of crude oil, 19,000 barrels of NGLs and 150 million cubic feet of natural gas. Net daily production from Hess legacy assets in second-half 2025 averaged 29,000 barrels of crude oil, 4,000 barrels of NGLs, and 48 million cubic feet of natural gas. Chevron is engaged in various operated and nonoperated exploration, development and production activities in the deepwater Gulf of America. Chevron also holds nonoperated interests in several shelf fields.
Chevron holds a 62.9 percent-owned and operated interest in the unit areas containing the Anchor Field located in the Green Canyon area. In 2025, Chevron completed the first full year of production safely utilizing its industry-leading high-pressure subsea technology, which helps produce energy from deeper reservoirs at higher pressures. An additional well was brought online during the year as a part of the initial Stage 1, seven-well subsea development, and a debottlenecking project was sanctioned to increase production capacity. The field has an estimated remaining production life of more than 25 years.
Chevron has a 60 percent-owned and operated interest in the Ballymore Field, located in the Mississippi Canyon area. The field has been developed as a three well, subsea tieback to the upgraded 75 percent-owned and operated Blind Faith facility. First oil was achieved in April 2025 and production reached design capacity ahead of schedule. The field has an estimated remaining production life of 20 years.
Chevron has a 60 percent-owned and operated interest in the Big Foot Field, located in the deepwater Walker Ridge area. Its platform supports an onboard, full-capacity drilling rig for development well drilling and future interventions. Production wells are equipped with electric submersible pumps. First oil was achieved from two additional development wells in 2025, and further development is planned in 2026. The field has an estimated remaining production life of more than 20 years.
Chevron has a 50 percent-owned and operated interest in the Jack Field, a 51 percent-owned and operated interest in the St. Malo Field and a 40.6 percent-owned and operated interest in the production host facility used for the joint development of both fields, all located in the Walker Ridge area. In 2025, two Jack development wells delivered first oil, and the St. Malo Stage 4 water injection operations continued. The Jack/St. Malo Stage 5 Project achieved first oil in December 2025. The Jack and St. Malo fields have an estimated remaining production life of more than 20 years.
Chevron has a 50 percent-owned and operated interest in the Stampede Field, located in the Green Canyon area, an increase of 25 percent following its acquisition of Hess and assumption of operatorship. In July 2025, the Black Pearl development well achieved first oil. The Stampede Field has an estimated remaining production life of more than 25 years.
Chevron has a 58 percent-owned and operated interest in the deepwater Tahiti Field, located in the Green Canyon area. In 2025, a development well workover was executed to deliver first oil from a shallower reservoir as water injection operations continued. The Tahiti Field has an estimated remaining production life of more than 15 years.
Chevron has a 42.5 percent nonoperated working interest in Green Canyon Block 584. In 2025, the operator announced an oil discovery at the Far South prospect in this Block, with an initial well and sidetrack drilled to a total depth of 23,830 feet.
Chevron has a 15.6 percent nonoperated working interest in the deepwater Mad Dog Field, located in the Green Canyon area. The field consists of two production facilities: Spar A and Argos. In 2025, development at Spar A continued with the completion of the eleventh producing well, and development at Argos continued through the Mad Dog 2 project, which has completed 12 producing wells and five water injection wells to date. Argos development was further supported by the Argos Southwest Extension (ASWX) project, a three-well development with dual flowlines and a manifold tied back to the Argos subsea infrastructure, along with minor topside modifications to the Argos floating production unit. The ASWX project commenced production in 2025. The field has an estimated remaining production life of more than 40 years.
Chevron has a 37.5 percent nonoperated working interest in the Perdido Regional Host, which accommodates production from the Great White, Silvertip and Tobago fields in the Alaminos Canyon area. In 2025, four development wells and one water injection well in the Great White Field, where Chevron holds a 33.3 percent nonoperated working interest, were brought online. Also in 2025, development activities continued on the Silvertip Expansion Project, where Chevron has a 60 percent nonoperated working interest, with first oil expected in 2026. The Perdido asset has an estimated remaining production life of more than 15 years.
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Chevron has a 41.5 percent nonoperated working interest in the deepwater Whale Field located in the Alaminos Canyon area. Whale consists of a 15-well subsea development and floating production unit. First production was achieved in January 2025, and nameplate capacity was reached in September as eight wells were brought online throughout the year. The field has an estimated remaining production life of more than 25 years.
In addition to Stampede, Chevron acquired further assets in the Gulf of America from Hess, including a 100 percent-owned and operated interest in the Pickerel Field, a 50 percent-owned and operated interest in the Baldpate and Penn State fields, a 38 percent-owned and operated interest in the Conger Field and an additional 57.1 percent-owned and operated interest in the Tubular Bells Field, taking its interest to 100 percent. Chevron also acquired a 50 percent nonoperated working interest in the Llano field, where a sidetrack well achieved first oil in 2025.
In 2025, Chevron was the apparent high bidder on 24 exploration blocks in the Gulf of America Big Beautiful Gulf 1 Lease Sale.
Other Chevron has a 50 percent interest in Bayou Bend CCS LLC, a carbon dioxide transportation and sequestration affiliate that holds approximately 140,000 acres for carbon dioxide storage in Texas.
Chevron also owns a majority interest in ACES Delta, LLC, a joint venture developing the Advanced Clean Energy Storage Project in Delta, Utah. In 2025, hydrogen was produced and safely introduced into the salt cavern for storage at the ACES Delta site. Construction is complete, and the company is conducting final commissioning activities.
In 2025, Chevron advanced work on its first power project for data centers, which is expected to be supplied with gas from the Permian Basin in West Texas.
In 2025, Chevron also acquired approximately 135,000 net acres in the Smackover Formation in Northeast Texas and Southwest Arkansas for the purpose of exploring lithium development.
Other Americas
“Other Americas” includes Argentina, Brazil, Canada, Colombia, Guyana, Mexico, Peru, Suriname, Uruguay and Venezuela. Acreage for “Other Americas” 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.
Argentina Chevron has a 50 percent nonoperated interest in the Loma Campana and Narambuena concessions in the Vaca Muerta shale. At Loma Campana, 30 horizontal wells were drilled in 2025, including Argentina’s longest unconventional well that reached a total depth of approximately 27,480 feet and a record-setting 16,778 feet lateral; in total, 42 wells were put on production. The Loma Campana concession expires in 2048, while the Narambuena concession was extended in 2025 under a 35-year unconventional license, now expiring in 2060.
Chevron owns and operates a 100 percent interest in the El Trapial Field with focus on unconventional development in the Vaca Muerta formation and continuing conventional waterflood activities. The unconventional concession expires in 2057 and the conventional concession expires in 2032.
Chevron has a 14 percent interest in the Oldelval pipeline system that provides an important export route for Argentina’s crude oil. During 2025, a majority of the company’s exported crude oil was transported through this pipeline system. Additionally, in 2025, Chevron joined the Vaca Muerta Sur pipeline project as a shareholder. The project involves the construction of a 437-kilometer pipeline from the Vaca Muerta oil fields to a new export terminal in Punta Colorada, Río Negro, featuring monobuoy loading systems and storage facilities. The pipeline is expected to be operational in 2027 and provide additional export capacity for the country.
Brazil Chevron holds a 35 percent nonoperated interest in two blocks in the Campos Basin and has exploration rights in 15 blocks in the North and South Pelotas basins. In 2025, Chevron secured nine additional offshore exploration blocks, six blocks with a 65 percent-owned and operated interest and three blocks with a 50 percent-owned and operated interest, in the Foz do Amazonas Basin through a government-conducted auction, opening a new exploration frontier for the company. In 2025, the company commenced a 3D seismic campaign to evaluate opportunities to develop the blocks.
Canada Upstream interests in Canada are concentrated in the offshore Atlantic region of Newfoundland and Labrador. The company also has interests in the Northeast British Columbia and the Beaufort Sea region of the Northwest Territories.
Chevron has a 26.9 percent nonoperated working interest in the Hibernia Field and a 24.1 percent nonoperated working interest in the unitized Hibernia Southern Extension areas offshore Atlantic Canada. The company has a 29.6 percent nonoperated working interest in the Hebron Field, also offshore Atlantic Canada.
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Colombia In 2025, Chevron relinquished a 40 percent-owned and operated interest in the offshore Colombia-3 Block.
Guyana Chevron has a 30 percent nonoperated interest in the Stabroek Block, offshore Guyana, covering approximately 6.6 million acres, following its acquisition of Hess. In August 2025, the One Guyana Floating Production, Storage and Offloading vessel (FPSO) with a production capacity of approximately 250,000 gross barrels of oil per day, achieved first production. This is the fourth producing FPSO on the Block, in addition to the existing Liza Destiny, Liza Unity and Prosperity vessels. It is expected that by 2030, eight FPSOs will be in production with an aggregate expected production capacity of approximately 1.7 million gross barrels of oil per day.
The fifth development, Uaru, sanctioned in April 2023, will utilize the Errea Wittu FPSO with a production capacity of approximately 250,000 gross barrels of oil per day with first production expected in 2026.
The sixth development, Whiptail, sanctioned in April 2024, will utilize the Jaguar FPSO with a production capacity of approximately 250,000 gross barrels of oil per day with first production expected in 2027.
The seventh development, Hammerhead, was sanctioned in September 2025 with an expected production capacity of approximately 150,000 gross barrels of oil per day with first production expected in 2029.
Chevron has a 30 percent nonoperated interest in the 130-mile pipeline from the Liza Field to shore. This pipeline is expected to transport approximately 50 million standard cubic feet of natural gas per day to a 300 megawatt onshore power plant which, when complete, will be operated by the Government of Guyana.
Mexico All blocks in which Chevron had a participating interest were relinquished in 2023, awaiting official release from the government.
Peru In 2025, Chevron acquired a 35 percent nonoperated interest in exploration Blocks Z-61, Z-62 and Z-63 in the Trujillo Basin, offshore Peru. Seismic data is being analyzed for possible future exploratory drilling investment.
Suriname Chevron has a 40 percent-owned and operated working interest in shallow water Block 5 and an 80 percent-owned and operated interest in the shallow water Block 7. Chevron also holds a 66.6 percent nonoperated working interest in deepwater Block 42 which increased by 33.3 percent in 2025 due to the acquisition of Hess.
Additionally in 2025, Chevron was awarded exploration acreage consisting of a 20 percent nonoperated interest in shallow water Block 9 and a 30 percent-owned and operated interest in shallow water Block 10.
Uruguay Chevron has a 60 percent-owned and operated interest in offshore exploration Block OFF-1.
Venezuela Chevron’s interests in Venezuela are located in western Venezuela, the Orinoco Belt and offshore Venezuela. As of December 31, 2025, no proved reserves are recognized for these interests. In 2025, the company conducted activities in Venezuela consistent with the authorization provided pursuant to licenses issued by the United States government.
Chevron has a 39.2 percent interest in Petroboscan, which operates the Boscan Field in western Venezuela, as well as a 25.2 percent interest in Petroindependiente, which operates the LL-652 Field in Lake Maracaibo with licenses that expire in 2041. Chevron has a 30 percent interest in Petropiar, which operates heavy oil production from Huyapari Field, processing output through its upgrader located in Anzoátegui that refines the oil to a lighter, high-quality synthetic crude oil or blends it with light oil to produce Merey crude, under an agreement expiring in 2047. Chevron has a 35.8 percent interest in Petroindependencia, which includes the Carabobo 3 heavy oil project located in three blocks in the Orinoco Belt under a contract expiring in 2050.
Chevron also operates and holds a 60 percent interest in the Loran gas field offshore Venezuela. This is part of a cross- border field that includes the Manatee Field in Trinidad and Tobago. This license expires in 2039.
Africa
In Africa, the company is engaged in upstream activities in Angola, Cameroon, Egypt, Equatorial Guinea, Guinea-Bissau, 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 that expires in 2050. In 2025, first oil was reached at the South N’Dola project located in Block 0.
Chevron also operates and holds a 31 percent interest in a Production Sharing Agreement (PSA) for deepwater Block 14. In 2025, the Block 14 partners and National Concessionaire signed an extension for an additional 10 years.
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In 2025, Chevron signed a Heads of Agreement for an owned and operated interest in Block 33 offshore Angola in the deepwater lower Congo Basin. The formalization of this acquisition through the execution of the Risk Service Contract is pending regulatory approval.
In 2025, Chevron completed a seismic survey for Blocks 33, 49 and 50 offshore Angola in the deepwater lower Congo Basin to assess geological potential.
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. 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 been recognized for this project.
Angola-Democratic Republic of Congo (DRC) Joint Development Area Chevron has a 31 percent interest in a unitization and cross-border asset PSA with the Angola and DRC governments to explore Block 14/23 located in the Zone of Common Interest established between the Republic of Angola and DRC maritime area.
Angola-Republic of Congo (ROC) Joint Development Area Chevron holds a 15.5 percent nonoperated interest in the Lianzi Unitization Zone (Lianzi), which is located in an area shared equally by Angola and the ROC. This interest expires in 2031. In January 2025, Chevron sold its interest in the ROC portion of Lianzi, while retaining the Angolan portion.
Republic of Congo In January 2025, the company sold its 31.5 percent nonoperated interest in the offshore Haute Mer permit area.
Cameroon Chevron has a 100 percent interest in the YoYo Block in the Douala Basin. Preliminary development plans include a possible joint development between the YoYo and Yolanda fields located in Equatorial Guinea Block I.
Egypt Chevron has interests in blocks in the Mediterranean Sea. Following a farmdown in 2025, Chevron holds a 40 percent-owned and operated interest in North El Dabaa (Block 4), as well as a 45 percent-owned and operated interest in the Nargis Block and a 27 percent nonoperated working interest in North Cleopatra (Block 7).
In 2025, the company relinquished its 45 percent-owned and operated interest in Block 1 in the Red Sea.
Equatorial Guinea Chevron has a 38 percent-owned and operated interest in the Aseng Field and the Yolanda Field in Block I and a 45 percent-owned and operated interest in the Alen Field in Block O. The Yolanda field is a discovered natural gas field that straddles the Equatorial Guinea and Cameroon maritime border, for which development options are being reviewed with both governments.
The company also holds a 32.8 percent nonoperated interest in the Alba natural gas and condensate field that is located in shallow waters near Bioko Island.
Chevron holds interests in two processing facilities located in Punta Europa. These include a 28 percent nonoperated interest in the Alba LPG Plant and a 45 percent nonoperated interest in the Atlantic Methanol Production Company.
Chevron holds interests in two exploration acreage positions for Blocks EG-06 and EG-11, offshore Bioko Island.
Guinea-Bissau In 2025, Chevron was awarded a 90 percent working interest in frontier exploration Blocks 5B (Carapau) and 6B (Becuda), offshore Guinea-Bissau.
Libya In early 2026, Chevron was designated as the winning bidder for Contract Area 106 located in the Sirte Basin.
Namibia Following a farmdown in 2025, Chevron has a 52.5 percent-owned and operated interest in Petroleum Exploration License (PEL) 90 (Block 2813B) in the Orange Basin, offshore Namibia. In early 2025, Chevron acquired an 80 percent-owned and operated interest in PEL 82 (Blocks 2112B and 2212A) in the Walvis Basin.
Nigeria Chevron holds 40 percent interests in concessions across the onshore and shallow-offshore regions of the Niger Delta. The company also holds acreage positions in five operated and six nonoperated deepwater blocks, with working interests ranging from 20 to 100 percent.
Chevron operates and holds a 67.3 percent working interest in the Agbami Field, which straddles deepwater Petroleum Mining Lease (PML) 52 and Oil Mining License (OML) 128. PML 52 expires in 2044, and OML 128 expires in 2042. Additionally, Chevron holds a 30 percent nonoperated working interest in the Usan Field in OML 138 that expires in 2042.
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In deepwater exploration, Chevron operates and holds a 55 percent working interest in the Nsiko discovery in OML 140 and a 100 percent working interest in the Aparo discovery in OML 132. Chevron also holds a 27 percent nonoperated working interest in OML 139 and OML 154, and the company continues to work with the operator to evaluate development options for the multiple deepwater discoveries in the Usan area, including the Owowo Field, which straddles OML 139 and OML 154. The development plan for the Owowo Field involves a subsea tie-back to the existing Usan floating, production, storage and offloading vessel. At the end of 2025, no proved reserves were recognized for this project.
Also, in the deepwater area, the third-party-operated Bonga South West Aparo Field in OML 118 straddles both OML 132 and OML 140. Chevron holds a 16.6 percent nonoperated working interest in the unitized area. The development plan involves subsea wells tied back to a floating production, storage and offloading vessel. At the end of 2025, no proved reserves were recognized for this project.
In 2025, Chevron discovered hydrocarbons in two exploration and appraisal wells in the Delta South-AA in PML 46 and the Awodi-07 in Petroleum Prospecting License (PPL) 263 in shallow offshore Nigeria. These wells provided additional data to support ongoing evaluation of development options. Chevron also holds a 40 percent-owned and operated working interest in Oil Prospecting License (OPL) 215 that covers 256,000 net acres. Chevron signed agreements to acquire 40 percent nonoperated working interest in PPL 2000/2001, with close anticipated in 2026.
Chevron operates the Escravos Gas Plant, which has a total processing capacity of 680 million cubic feet per day of natural gas and liquefied petroleum gas and condensate export capacity of 58,000 barrels per day. The company operates the 33,000-barrel-per-day Escravos Gas to Liquids facility. In addition, the company holds a 36.9 percent interest in the West African Gas Pipeline Company Limited affiliate, which supplies Nigerian natural gas to customers in Benin, Togo and Ghana.
Asia
In Asia, the company is engaged in upstream activities in Bangladesh, China, Cyprus, Indonesia, Israel, Kazakhstan, the Partitioned Zone between Saudi Arabia and Kuwait, Malaysia, 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 Production Sharing Contracts (PSCs). The rights to produce from Bibiyana and Jalalabad expire in 2034 and from Moulavi Bazar in 2038.
China Chevron has a 49 percent nonoperated working interest in the Chuandongbei project, including the Luojiazhai and Gunziping natural gas fields located onshore in the Sichuan Basin, with the PSC expiring in 2038. In the Pearl River Mouth Basin, the company previously held a 32.7 percent nonoperated working interest in Block 16/19, where production ceased in April 2025.
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 January 2026, the company successfully entered FEED (Front End Engineering Design) in alignment with the PSC project milestone in the approved development and production plan.
Indonesia Chevron is participating in an early phase exploration study managed by a joint venture at the Way Ratai geothermal working area in Lampung.
Israel Chevron holds a 39.7 percent-owned and operated interest in the Leviathan Field, which operates under a concession that expires in 2044. A third gathering pipeline is under construction and is expected to increase gas production capacity from approximately 1.2 to 1.4 billion cubic feet per day from the Leviathan reservoir. This pipeline is scheduled for completion in early 2026. In early 2026, Chevron reached final investment decision (FID) to invest in the Leviathan Expansion Phase 1 Project that is expected to increase Leviathan’s upstream production capacity to 2.1 billion cubic feet per day.
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 included installation of a new pipeline to increase delivery capacity to the processing platform, allowing for production capacity at the platform to increase from approximately 1.0 billion to 1.2 billion cubic feet per day. First gas was achieved in early 2026. Phase 2 of the Tamar Optimization Project, approved in February 2024, is expected to further increase capacity up to approximately 1.6 billion
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cubic feet of gas per day and includes investment in additional midstream infrastructure. This project is scheduled for completion in the first half of 2026.
In 2025, Chevron signed an agreement to develop the Nitzana natural gas pipeline to transport gas from both Leviathan and Tamar fields to Egypt. The pipeline capacity is expected to reach 0.6 billion cubic feet per day and scheduled for completion in 2028.
Kazakhstan Chevron has a 50 percent interest in the TCO affiliate and an 18 percent nonoperated working interest in the Karachaganak field.
TCO operates the Tengiz and Korolev crude oil fields in western Kazakhstan under a concession agreement that expires in 2033. Most of TCO’s 2025 crude oil production was exported through the Caspian Pipeline Consortium (CPC) pipeline. In 2025, TCO completed the Future Growth Project (FGP) at the Tengiz oil field, which increased crude oil production by 260,000 barrels per day with a total gross output of one million barrels of oil-equivalent per day.
The Karachaganak field is located in Northwest Kazakhstan, and operations are conducted under a PSA that expires in 2038. During 2025, a majority of the exported liquids were transported through the CPC pipeline. In 2025, the Karachaganak Expansion Project Stage 1A facility scope was fully completed and Stage 1B development is expected to complete in the second half of 2026. Both projects are designed to increase gas re-injection capacity and extend stable field production. Proved reserves have been recognized for both projects.
Kazakhstan/Russia Chevron has a 15 percent interest in CPC. Through 2025, CPC transported an average of 1.5 million barrels of crude oil per day, composed of 1.4 million barrels per day from Kazakhstan and 0.1 million barrels per day from Russia.
Kurdistan Region of Iraq In 2025, Chevron completed exit agreements and withdrew from the country.
Malaysia Following the acquisition of Hess, Chevron has a 50 percent-owned and operated interest in Blocks PM302 and PM325 located in the North Malay Basin and a 50 percent interest in Block PM301, which has been unitized within the nonoperated Malaysia/Thailand Joint Development Area.
Malaysia/Thailand Joint Development Area (JDA) During 2025, the JDA Block A-18, acquired through the acquisition of Hess, was sold.
Partitioned Zone Chevron holds a concession to operate the Kingdom of Saudi Arabia’s 50 percent interest in the hydrocarbon resources in the onshore and nearshore area of the Partitioned Zone between Saudi Arabia and Kuwait. The concession expires in 2046. In 2025, the NWWB-2 appraisal well was drilled and completed, helping further assess resources discovered in 2024, and making a new oil discovery north of the Wafra Field.
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 2030 and 2038. Chevron has a 35 percent-owned and operated interest in the Pailin Field in Block B12/27, and a 51.7 percent-owned and operated interest in the Benchamas and Maliwan field in Block B8/32. In December 2025, the government approved the 10-year extension of the Pailin Field (Block 12/27) to 2038. 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. Following a farmdown in 2025, Chevron also has a 70 percent-owned and operated exploration and production license for Block G2/65, which covers 2.6 million net acres.
Chevron holds between 16 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
Chevron is the largest producer of LNG in Australia. Acreage can be found in the Acreage table. Net daily oil-equivalent production can be found in the Net Production of Crude Oil, Natural Gas Liquids and Natural Gas table.
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
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underground storage facility and a domestic gas plant. Progress on the Jansz-Io Compression project continued during 2025, with first gas expected in 2028. In 2025, FID was reached on the Gorgon Stage 3 Project to develop additional backfill fields, Geryon and Eurytion, with first gas expected in 2029. As part of this decision, Chevron completed a farmdown for the permit area WA-22-R to 47.3 percent to align interests with the Gorgon Project partners. Proved reserves have been recognized for both of these projects. Gorgon’s estimated remaining economic life exceeds 40 years.
Chevron holds a 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. In 2025, Wheatstone marked its 1,000th LNG shipment since commencement of the project in 2017. Wheatstone’s estimated remaining economic life exceeds 14 years.
Chevron holds a 16.7 percent nonoperated working interest in the NWS Venture in Western Australia. In 2024, the company agreed to an asset swap of its 16.7 percent interest in the NWS Project, NWS Oil Project and its 20 percent interest in Angel Carbon Capture and Storage Project with Woodside’s 13 percent nonoperated interest in the Wheatstone Project and 65 percent operated interest in the Julimar-Brunello fields and related infrastructure, which is expected to close in 2026, subject to customary closing conditions and regulations.
Chevron holds a 57.1 percent-owned and operated interest in the Barrow Island Joint Venture (known as WA Oil). In May 2025, the Barrow Island oil field ceased production and entered the decommissioning phase.
The company continues to evaluate exploration and appraisal activity across the North Carnarvon Basin, in which it holds approximately 2.6 million net acres. Chevron owns and operates the Clio, Acme and Acme West fields. This activity includes the evaluation of opportunities to develop resources, such as Clio, Acme, and Acme West through existing infrastructure.
Chevron holds operated and nonoperated working interests ranging from 20 to 70 percent in five greenhouse gas assessment permits to evaluate the potential of carbon dioxide storage. The blocks, including four in the Carnarvon Basin off the northwestern coast of Western Australia and one in the Bonaparte Basin offshore Northern Territory, total nearly 10.2 million gross acres. This acreage includes the Angel Carbon Capture and Storage Project, which is subject to the asset swap mentioned above.
Europe
In Europe, the company is engaged in upstream activities in Greece and the United Kingdom. Acreage 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.
Greece In early 2026, Chevron was awarded four deep-sea blocks off the Peloponnese peninsula and the island of Crete.
United Kingdom Chevron holds a 19.4 percent nonoperated working interest in the Clair Field, located west of the Shetland Islands. The Clair Field consists of two platform drilling centers: the original Clair Phase 1 and a later added Clair Ridge center. The company is assessing alternatives to develop further resources in the area. The Clair Field has an estimated remaining production life extending beyond 2050.
Sales of Natural Gas Liquids and Natural Gas
The company sells NGLs and natural gas from its producing operations under a variety of contractual arrangements. In addition, the company also makes third-party purchases and sales of NGLs and natural gas in connection with its supply and trading activities.
U.S. and international sales of NGLs averaged 562,000 and 249,000 barrels per day, respectively, in 2025.
During 2025, U.S. and international sales of natural gas averaged 5.7 billion and 5.5 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, China, Equatorial Guinea, Israel, Kazakhstan, Malaysia, 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.
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Downstream
Refining Operations
At the end of 2025, the company had a refining network capable of processing 1.8 million barrels per day. Operable capacity at December 31, 2025, and daily refinery inputs for the company and affiliate refineries for 2023 through 2025, are summarized in the table below. Average crude unit distillation capacity utilization was 92.9 percent in 2025 and 87.9 percent in 2024.
At U.S. refineries, crude unit distillation capacity utilization, which includes all crude oil and other inputs, averaged 94.5 percent in 2025, compared with 86.6 percent in 2024. Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for approximately 60 percent of Chevron’s U.S. refinery inputs in both 2025 and 2024.
In the United States, the company continued work on projects aimed at improving refinery flexibility and reliability. In 2025, the expansion of the Pasadena Refinery became fully operational, increasing light crude oil throughput capacity to 125,000 barrels per day. This project allowed the company to process more equity crude from the Permian Basin, supply more products to customers in the U.S. Gulf Coast and realize synergies with the company’s Pascagoula Refinery.
Outside the United States, the company has interests in three large refineries in Singapore, South Korea and Thailand. Singapore Refining Company (SRC), a 50 percent-owned joint venture, has a total capacity of 290,000 barrels of crude per day and manufactures a wide range of petroleum products. The 50 percent-owned GS Caltex (GSC) Yeosu Refinery in South Korea remains one of the world’s largest refineries with a total crude capacity of 800,000 barrels per day. The company’s 60.6 percent-owned refinery in Thailand, Star Petroleum Refining Public Company Limited (SPRC), continues to supply high-quality petroleum products into regional markets.
Petroleum Refineries: Locations, Capacities and Crude Unit Inputs
Capacities and inputs in thousands of barrels per dayDecember 31, 2025
Refinery Crude Unit Inputs*
Locations Number Operable Capacity 202520242023
PascagoulaMississippi1 369 365 337 355 
El SegundoCalifornia1 290 261 224 232 
RichmondCalifornia1 257 253 242 236 
PasadenaTexas1 125 110 65 84 
Salt Lake CityUtah1 58 49 49 55 
Total Consolidated Companies — United States 5 1,099 1,038 917962
Map Ta PhutThailand1 175 163 160 153 
Total Consolidated Companies — International 1 175 163 160 153
YeosuSouth Korea1 400 365 369 367 
Pulau MerlimauSingapore1 145 124 117 116 
Total Affiliates2 545 489 486 483 
Total Including Affiliates — International 3 720 652 646 636 
Total Including Affiliates — Worldwide 8 1,819 1,690 1,563 1,598 
* Includes crude oil and all other feedstocks to the crude distillation units.
Renewable Fuels
The company develops, produces and sells renewable fuels, including but not limited to renewable diesel, biodiesel, renewable natural gas (RNG), and sustainable aviation fuel (SAF).
Chevron owns and operates 11 biofuel refineries located in the U.S. and Germany, including eight producing biodiesel, one producing renewable diesel and two others that remained idle in 2025. In 2025, the company began production and continues ramp-up at its Geismar renewable diesel plant in Louisiana, following an expansion to increase plant capacity from 7,000 to 22,000 barrels per day.
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. A new oilseed processing plant in Louisiana is expected to begin operations in 2026.
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In early 2025, Chevron acquired the remaining equity of Brightmark RNG Holdings LLC and renamed the company to Chevron RNG Holdings LLC (Chevron RNG). Chevron continues to advance its dairy biomethane activities through Chevron RNG and investments in CalBioGas LLC and CalBioGas Hilmar LLC (collectively, CalBioGas investments). Chevron’s wholly-owned and operated renewable gas assets include 26 anaerobic digester facilities (25 operational, one under construction) in nine U.S. states that capture methane from manure at dairy farms and process it into natural gas. CalBioGas investments have 29 anaerobic digester projects at dairy farms in California producing natural gas or directly supplying electricity.
Chevron sells RNG to third parties and through Chevron’s network of 67 compressed natural gas (CNG) stations under the Chevron and Beyond6 brands.
Chevron has successfully demonstrated the ability to produce both renewable diesel and SAF at its El Segundo Refinery, with the flexibility to switch between traditional fuels and renewables dependent upon market conditions.
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, 2025.
Refined Products Sales Volumes
Thousands of barrels per day202520242023
United States
Gasoline1
685 667642
Jet Fuel278 255260
Diesel/Gas Oil1
216 213227
Fuel Oil41 5444
Other Petroleum Products2
97 97114
Total United States1,317 1,286 1,287 
International3
Gasoline388 382353
Jet Fuel223 229234
Diesel/Gas Oil1
483 479472
Fuel Oil174 182161
Other Petroleum Products2
216 223225
Total International 1,484 1,495 1,445 
Total Worldwide3
2,801 2,781 2,732 
1 Includes renewable fuel sales:
23 4044
2 Principally naphtha, lubricants, asphalt and coke.
3 Includes share of affiliates’ sales:
384 386389
 In the United States, the company markets primarily under the principal brands of “Chevron” and “Texaco.” At year-end 2025, the company supplied directly or through retailers and marketers approximately 8,600 Chevron- and Texaco-branded service stations, primarily in the southern and western states. Approximately 380 of these outlets are company-owned or company-leased stations.
Outside the United States, Chevron supplied directly or through retailers and marketers approximately 5,200 branded service stations, including affiliates. The company markets using the Chevron and Texaco brands in Latin America and the Caltex brand in the Asia-Pacific region. In South Korea, the company operates through its 50 percent-owned affiliate, GSC.
Chevron markets commercial aviation fuel to 58 airports worldwide. The company markets base oil globally under the Chevron and Nexbase brands and markets lubricant and coolant products under the Chevron, Texaco and Caltex brands.
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 2025, 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
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specialty chemical and specialty plastics markets. At the end of 2025, CPChem owned or had joint-venture interests in 29 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 expected in the first half of 2027. CPChem completed the Low Viscosity Poly Alpha Olefin Expansion Project at the CPChem Beringen, Belgium site in 2025.
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, 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 2025, Chevron acquired further pipeline infrastructure through its acquisition of Hess. Refer to the United States - Hess Midstream in the Upstream section above for more information related to these assets. 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 CPC.
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 2025, Chevron completed upgrades to four LNG vessels aimed at reducing emissions.
Other Businesses
Technology, Projects and Execution (TPE) Chevron’s TPE organization centralizes technical expertise to drive innovation, ensure disciplined project execution, and promote operational excellence across the company, supporting the delivery of more affordable, reliable and cleaner energy solutions. Areas of expertise include advanced technology development and deployment, digital and data science, facilities engineering, reserve governance and reporting, capital projects execution and global procurement. TPE specializes in maintaining a strong safety culture and environmental stewardship by proactively managing risks, sustaining compliance, and protecting people, assets and communities.
TPE also includes the company’s information technology organization, which integrates computing, data management and analytics, cybersecurity and other key infrastructure technologies to provide a digital foundation to enable Chevron’s global operations, projects and business processes.
The organization is focused on technologies that are ready to adopt and scale today, as well as breakthrough technologies in support of its oil, natural gas and products and new energies 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 expertise to undertake research and development to advance energy solutions. The company holds more than 4,000 patents for new technologies, with nearly 3,400 additional patents pending, making Chevron one of the leading U.S. 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. 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 26 years of being the primary on-ramp for early-stage, external innovation into Chevron, including venture investing, with 10 funds that have supported more than 140 startups. Chevron also makes investments indirectly through a few select limited partnership funds.
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Chevron is applying artificial intelligence (AI) to drive productivity, efficiency and value to its global operations. The company is building high-impact use cases leveraging its extensive data and insights and collaborating with others to access AI solutions to help unlock value. In an effort to ensure its AI systems are reliable and effective, the company is employing processes to assess its capabilities, limitations and readiness. Chevron is a member of the Responsible AI institute, a consortium focused on integrating AI responsibly while safeguarding human values.
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.
New Energies The new energies organization is focused on developing new businesses with the aim to support the company’s objectives to lower the carbon intensity of its operations and enable growth opportunities with the potential to generate competitive returns. These include additional fuel solutions utilizing hydrogen and its derivatives such as ammonia, carbon emissions management through carbon capture and storage and offsets, and power generation for data centers. The company is also pursuing opportunities in other emerging areas, including enhanced geothermal to deliver non-intermittent lower carbon power, and lithium extraction primarily for energy storage applications.
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 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 America. 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 related laws and regulations to which it is subject. Refer to Item 1A. Risk Factors for further discussion of government action with respect to greenhouse gas 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 in Business Environment and Outlook on pages 35 through 37 for further discussion of climate change related trends and uncertainties.
Refer to Management’s Discussion and Analysis of Financial Conditions and Results of Operations on page 55 for additional information on environmental matters and their impact on Chevron, and on the company’s 2025 environmental expenditures. Refer to page 54 and Note 24 Other Contingencies and Commitments for a discussion of environmental remediation provisions and year-end reserves.
Item 1A. Risk Factors
As a global energy company, Chevron is subject to a variety of risks. The following disclosures reflect our beliefs and opinions as to factors that could materially and adversely affect us in the future. References to past events are provided by way of example only and are not intended to be a complete listing or a representation as to whether or not such factors have occurred in the past or their likelihood of occurring in the future.
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 are the prices of crude oil, natural gas, and natural gas liquids, 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
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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 prices of crude oil, natural gas, and natural gas liquids.
Extended periods of low prices or demand for crude oil, natural gas, and natural gas liquids have had, and in the future 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 New Energies businesses. In some cases, transferred liabilities, including for decommissioning of previously divested assets, have returned and may continue to return to the company when an acquirer of those assets subsequently defaults on the assumed transferred liabilities (e.g., 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, and other forms of severe weather; wildfires; ambient temperature increases; sea level rise; war or other military conflicts such as the conflict between Russia and Ukraine and in the Middle East; accidents; civil unrest; political events such as current geopolitical tensions in Venezuela; 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 and events affecting 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 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 organizational changes, relocating work to international geographies, or other corporate transactions; 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
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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. Our use of third-party software, services and support may also result in unintentional, non-malicious events or outages that affect our ability to operate critical business systems. Regardless of the precise method or form, events affecting our networks or digital infrastructure 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.
Chevron is incorporating artificial intelligence technologies into its processes and these technologies may present business, compliance, and reputational risks The company is increasingly utilizing artificial intelligence (“AI”) technologies in certain of its processes, information systems and various operations, and expects that AI will assume a more critical role in its operations over time. The use of AI technologies introduces certain risks to the company, including potential dependency on biased or incorrect AI outputs, new or enhanced regulatory requirements, litigation, privacy risks, cybersecurity risks, reputational harm, liability or other adverse consequences, any of which could adversely affect its business, financial condition and results of operations. Additionally, other unforeseen risks stemming from either the company’s or third-party service providers’ use and development of AI tools and technologies, or the company’s inability to adopt such technologies at the same pace as its competitors, may arise in the future that could adversely affect its 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.
The acquisition of Hess 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 the acquisition of Hess, which closed in July 2025, will depend, in part, on Chevron’s ability to realize the anticipated benefits, including the anticipated run-rate cost synergies, estimated five-year production and free cash flow growth rates, and anticipated higher returns to shareholders over the long-term. Failure to realize anticipated synergies in the expected timeframe, operational challenges, the diversion of management’s attention from ongoing business concerns, and unforeseen expenses associated with the acquisition may have an adverse impact on our financial results.

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One of our subsidiaries acts as the general partner of a publicly traded limited partnership, Hess Midstream LP, which may involve a potential legal liability One of our subsidiaries acts as the general partner of Hess Midstream, a publicly traded limited partnership. Our control of the general partner of Hess Midstream may increase the possibility that we could be subject to claims of breach of duties owed to Hess Midstream, including claims of conflict of interest. Any liability resulting from such claims could have an adverse impact on our future business, financial condition, results of operations and cash flows.
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 current or former operations or products on human health or the environment. It is also 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, tariffs, royalties, fees, penalties or other costs. In a number of locations, including the European Union, governments have proposed or imposed direct and indirect obligations with respect to the company’s activities, trade, taxes, and public disclosures, as well as currency exchange controls that might harm the company’s competitiveness, return on investments, 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. 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.
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For information concerning the company’s tax liabilities, see Note 17 Taxes and Note 24 Other Contingencies and Commitments.
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. 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 operates in jurisdictions with developing or existing programs, such as the Renewable Fuel Standard program in the U.S., California’s Cap-and-Trade Program and Low Carbon Fuel Standard, and 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; 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. 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, 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. Additionally, some jurisdictions are in various stages of enacting or implementing legislation that imposes retroactive liability on estimated past GHG emissions by certain energy producers and refiners.
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, the use of standardized carbon accounting, the extent to which Chevron would be able to receive, generate, purchase, or retire 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 and
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legal challenges, 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.
Attention to environmental, social, and governance (ESG) matters impacts our company Attention to ESG matters, including those related to climate change and sustainability, evolving societal, investor and governmental 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, trends in attention to ESG matters, including climate change, have resulted and may result in the future in shifting demand for our hydrocarbon products, additional litigation and governmental investigations, and/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, 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 been developed that may limit the ability of certain sectors, including the oil and gas sector, from accessing capital, and may result in exclusion of the company’s equity or debt 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 lower carbon 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 human rights, 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 ambitions 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 set a number of lower carbon-related ambitions, which may include aspirations, targets, guidance, objectives, metrics, and/or goals. Chevron regularly evaluates its ambitions. The company has changed and/or eliminated some of these aspirations, targets, and other ambitions and may continue to do so in the future for various reasons, including market conditions; its strategy or portfolio; and financial, operational, policy, reputational, legal and other factors.
Our ability to achieve any ambition, including those related to GHG emissions or climate-related initiatives, such as those outlined in the Management’s Discussion and Analysis of Financial Condition and Results of Operations, on pages 36 through 37, as well as efforts concerning new businesses, is subject to numerous risks and contingencies, many of which are outside of Chevron’s control and persist. Examples of such risks and contingencies include: (1) sufficient and substantial advances in technology, including progress of commercially viable technologies and low- or non-carbon-based energy sources; (2) laws, governmental regulation, policies, and other enabling actions, including those regarding subsidies, tax and other incentives as well as the granting of necessary permits by governing authorities; (3) successful generation, acquisition, retirement and accounting of cost-effective, verifiable carbon offsets from nature-based solutions or carbon capture and storage; (4) the availability of suppliers that can meet sustainability-related standards; (5) evolving regulatory requirements affecting ESG standards or disclosures; (6) evolving standards for tracking and reporting on
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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.
The standards and regulations for tracking, reporting, disclosing, marketing and advertising related to ESG matters are relatively new, have not been harmonized and continue to evolve. Further, our selection of disclosure frameworks that seek to align with various voluntary reporting standards may change from time to time. Either of these circumstances may result in a lack of comparative data from period to period.
Our existing processes and controls may not align with evolving voluntary and mandatory 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. Achievement of or efforts to achieve ambitions 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 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 ambitions within the timelines we announce, or at all, or to satisfy various reporting standards and regulations 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; estimates for decommissioning obligations, including for previously divested assets; and measurement of benefit obligations for pension and other post-employment 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
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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 Officer (CIO) oversees Chevron’s broader IT program, which includes the company’s cybersecurity program and its ability to remediate and recover from a cybersecurity incident to minimize business and operational impacts. Chevron’s CIO joined Chevron in 2024, bringing more than 20 years of experience leading global innovation initiatives in digital, data, full supply chains, vehicle commerce, energy, and IT operations for technology and automotive companies. Chevron’s Chief Information Security Officer (CISO) reports to the CIO and leads a global cybersecurity team. Chevron’s CISO has 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 senior leadership roles, including that of CISO, at other multinational, publicly traded companies.
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. The cybersecurity organization provides the IT leadership, which includes Chevron’s CIO, with regular 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 leadership of the cybersecurity organization 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 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.
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;
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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 24 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 108 through 120 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 that 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, on May 20, 2024, the New Mexico Environment Department issued a Notice of Violation (NOV) for alleged violations of state and federal regulations of air quality between October 2022 and September 2023 at different Chevron facilities in New Mexico. Resolution of the alleged violations may result in the payment of a civil penalty of $1.0 million or more.
As previously disclosed, on May 26, 2023, Chevron’s refinery in El Segundo, California notified the U.S. EPA that it had inadvertently overstated the number of biofuel credits generated by co-processing in 2022 in violation of the Renewable Fuel Standard program. The parties began negotiating a resolution of the violation in October 2024. Resolution of the violation will result in the payment of a civil penalty of $1.0 million or more.
As previously disclosed, on October 31, 2024, California’s Bay Area Air District (formerly Bay Area Air Quality Management District) issued two NOVs for the alleged noncompliance with permit conditions that governed operation of certain equipment associated with low-NOx burners at the thermal oxidizers and stack gas heaters for sulfur recovery units 1 & 2 at Chevron’s refinery in Richmond, California. Resolution of the alleged violations may result in the payment of a civil penalty of $1.0 million or more.
As previously disclosed, in February 2025, the United States Department of Justice notified Hess of alleged Clean Water Act violations relating to Hess’s National Pollutant Discharge Elimination System permit covering operations in Hess facilities in the Gulf of America. Resolution of the alleged violations may result in the payment of a civil penalty of $1.0 million or more.
As previously disclosed, on June 26, 2025, the Colorado Energy & Carbon Management Commission (ECMC) issued a notice alleging violations of certain ECMC rules following the loss of well control incident that occurred in Galeton, Colorado, on April 6, 2025. Resolution of the alleged violations may result in the payment of a civil penalty of $1.0 million or more.
On July 22, 2025, ECMC issued a notice alleging various violations of reporting rules associated with environmental remediation data. Resolution of the alleged violations may result in the payment of a civil penalty of $1.0 million or more.
Please see information related to other legal proceedings in Note 16 Litigation.
Item 4. Mine Safety Disclosures
Not applicable.
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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 6, 2026, stockholders of record numbered approximately 91,000. 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, 2025
 
Total NumberAverageTotal Number of SharesApproximate Dollar Values of Shares that
of SharesPrice PaidPurchased as Part of PubliclyMay Yet be Purchased Under the Program
Period
Purchased 1, 2
per Share Announced Program
(Billions of dollars) 2
October 1 - October 31, 20256,121,636 $153.55 6,121,482 $38.6
November 1 - November 30, 20255,583,177 $152.49 5,583,177 $37.7
December 1 - December 31, 20258,036,375 $150.08 8,034,641 $36.5
Total October 1 - December 31, 202519,741,188 $151.84 19,739,300 
1 Includes common shares repurchased from participants in the company’s deferred compensation plans for personal income tax withholdings.
2 Refer to Liquidity and Capital Resources for additional detail regarding the company's authorized stock repurchase program.

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
The company’s discussion of interest rate, foreign currency and commodity price market risk is contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial and Derivative Instruments and in Note 10 Financial and Derivative Instruments.
Item 8. Financial Statements and Supplementary Data
The index to Financial Statements and Supplementary Data is presented in the Financial Table of Contents.
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, 2025.
(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, 2025.
The company excluded Hess from our assessment of internal control over financial reporting as of December 31, 2025, because it was acquired by the company in a business combination during 2025. Total assets and total revenues of Hess, a
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wholly-owned subsidiary of Chevron Corporation, represent 24 percent and 3 percent, respectively, of the related consolidated financial statement amounts as of and for the period ended December 31, 2025.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2025, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein.
(c) Changes in Internal Control Over Financial Reporting During the quarter ended December 31, 2025, 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 26, 2025. Mr. Wirth’s plan provides for the potential exercise of vested stock options and the associated sale of up to 262,900 shares of Chevron common stock between March 2, 2026 and February 26, 2027.
Eimear P. Bonner, Chief Financial Officer, entered into a pre-arranged stock trading plan on November 22, 2025. Ms. Bonner’s plan provides for the potential exercise of vested stock options and the associated sale of up to 132,768 shares of Chevron common stock between February 27, 2026 and February 26, 2027.
R. Hewitt Pate, Chief Legal Officer, entered into a pre-arranged stock trading plan on November 26, 2025. Mr. Pate’s plan provides for the potential exercise of vested stock options and the associated sale of up to 335,509 shares of Chevron common stock between February 27, 2026 and February 26, 2027.
The trading plans were entered into during an open insider trading window and are intended to satisfy the affirmative defense of Rule 10b5-1(c) under the Securities Exchange Act of 1934, as amended, and Chevron’s policies regarding transactions in Chevron securities.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
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PART III
Item 10. Directors, Executive Officers and Corporate Governance
Information about our Executive Officers at February 24, 2026
The Corporation’s executive officers are shown in the table below:
NameAgeCurrent and Prior Positions (up to five years)Primary Areas of Responsibility
Michael K. Wirth*65Chairman of the Board and Chief Executive Officer (since Feb 2018)
Chairman of the Board and
Chief Executive Officer
Eimear P. Bonner*51
Chief Financial Officer (since Mar 2024)
President and Chief Technology Officer, Chevron Technical Center (Feb 2021 - Dec 2023)
General Director, Tengizchevroil (Dec 2018 - Jan 2021)
Finance; Investor Relations
Mark A. Nelson*62
Vice Chairman (since Feb 2023); Executive Vice President, Oil, Products & Gas (since Oct 2024)
Executive Vice President, Strategy, Policy & Development (Oct
  2022 - Sep 2023)
Executive Vice President, Downstream (Mar 2019 - Sep 2022)
Upstream - Worldwide Exploration and Production; Subsurface; Wells;
Downstream - Worldwide Manufacturing, Marketing, Lubricants, and Chemicals; Midstream; Asset Performance and Process Safety
T. Ryder Booth*57Chief Technology and Engineering Officer (since Jul 2025)
Vice President, Midcontinent (Aug 2021 - Jun 2025)
Reserves and Storage; Facilities Engineering; Capital Projects; Technology Strategy Execution and Performance; Information Technology; Operations and Turnarounds; Asset Retirement; Environmental Management; Innovation; Health, Safety and Environment; Supply Chain Management
Jeff B. Gustavson*53President, New Energies (since Aug 2021)
Vice President, Midcontinent (Feb 2018 - Jul 2021)		Lower Carbon Solutions; Power for Data Centers; Artificial Intelligence
R. Hewitt Pate*63Chief Legal Officer (since Aug 2009)Law, Governance and Compliance
Robert Clay Neff63President, Upstream (since Jul 2025)
President, Chevron International Exploration and Production (Oct 2022 - Jul 2025)
President, Chevron Middle East, Africa, South America Exploration and Production Company (Nov 2019 - Oct 2022)		Upstream - Worldwide Exploration and Production; Subsurface; Wells
Andy Walz58President, Downstream, Midstream & Chemicals (since Oct 2024)
President, Americas Products (Oct 2019 - Oct 2024)		Downstream - Worldwide Manufacturing, Marketing, Lubricants, and Chemicals; Midstream
*Member of the Corporation’s Executive Committee
The information about directors required by Item 401(a), (d), (e) and (f) of Regulation S-K and contained under the heading “Election of Directors” in the Notice of the 2026 Annual Meeting of Stockholders and 2026 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act in connection with the company’s 2026 Annual Meeting (the 2026 Proxy Statement), is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 406 of Regulation S-K and contained under the heading “Business Conduct and Ethics Code” in the 2026 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 2026 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
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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 2026 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 2026 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(e)(5) of Regulation S-K and contained under the heading “Corporate Governance — Management Compensation Committee Report” in the 2026 Proxy Statement is incorporated herein by reference into this Annual Report on Form 10-K. Pursuant to the rules and regulations of the SEC under the Exchange Act, the information under such caption incorporated by reference from the 2026 Proxy Statement shall not be deemed to be “soliciting material,” or to be “filed” with the Commission, or subject to Regulation 14A or 14C or the liabilities of Section 18 of the Exchange Act, nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933.
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 2026 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 2026 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 2026 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 2026 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 2026” in the 2026 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
33
Financial Table of Contents
Table of Contents
                                    
Information Relating to the Consolidated Statement of Cash Flows
34


Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents
Key Financial Results
Millions of dollars, except per-share amounts202520242023
Net Income (Loss) Attributable to Chevron Corporation$12,299$17,661$21,369
Per Share Amounts:
Net Income (Loss) Attributable to Chevron Corporation
– Basic$6.65$9.76$11.41
– Diluted$6.63$9.72$11.36
Dividends$6.84$6.52$6.04
Sales and Other Operating Revenues$184,432$193,414$196,913
Return on:
Capital Employed6.6 %10.1 %11.9 %
Stockholders’ Equity7.3 %11.3 %13.3 %
Earnings by Major Operating Area
Millions of dollars202520242023
Upstream
United States$5,815$7,602$4,148
International7,00711,00013,290
Total Upstream12,82218,60217,438
Downstream
United States1,3755313,904
International1,6471,1962,233
Total Downstream3,0221,7276,137
All Other(3,545)(2,668)(2,206)
Net Income (Loss) Attributable to Chevron Corporation1,2
$12,299$17,661$21,369
1 Includes foreign currency effects:
$(469)$520 $(224)
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, 2025. 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, Guyana, Israel, Kazakhstan, Malaysia, Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait, the Philippines, Singapore, South Korea, Thailand, the United Kingdom, the United States and Venezuela.
The company’s objective is to safely deliver higher returns, lower carbon and superior shareholder value in any business environment. 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.
Some governments, companies, communities and other stakeholders are 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. Some of these policies and programs include renewable and low carbon fuel standards; programs that price GHG emissions; performance standards; and measures that provide various incentives for lower carbon activities, including carbon capture and storage and the production of hydrogen and sustainable aviation fuel. Requirements for these and other similar policies and programs are complex, ever changing, program specific and encompass: (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 the potential to enable opportunities for Chevron in its oil and gas and lower carbon business lines. Although we expect the company’s costs to comply with these policies and
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 Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents

programs to continue to increase, these costs currently do not have a material impact on the company’s financial condition or results of operations.
Significant uncertainty remains as to the pace and extent to which a lower carbon future progresses, which is dependent, in part, on substantial advancements and changes in policy, technology, and customer and consumer preferences. The level of expenditure required to comply with new or potential climate change-related laws and regulations and the amount of additional investments needed in new or existing technology or facilities, such as carbon capture and storage, is difficult to predict with certainty and is expected to vary depending on the actual laws and regulations enacted, available technology options, customer and consumer preferences, the company’s activities and market conditions. 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 a global approach to governments addressing climate change and continues to take actions to help lower the carbon intensity of its operations while continuing to meet the demand for energy. Chevron believes that broad, market-based mechanisms are the most efficient approach to addressing GHG emission reductions. 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 operations and grow new energies businesses. To grow new energies businesses, Chevron plans to leverage the company’s capabilities, assets, partnerships and customer relationships. The company’s oil and gas business may increase or decrease depending upon market, economic, legislative and regulatory forces, among other factors.
In 2021, Chevron announced aspirations and targets that align with its strategy. Chevron uses emissions intensity targets, which enable the company to assess, quantify and transparently communicate its own carbon performance in a standardized way. Chevron regularly evaluates its aspirations, targets and goals. The company has changed and/or eliminated some of these aspirations, targets and goals and may continue to do so in the future for various reasons, including market conditions; its strategy or portfolio; and financial, operational, policy, reputational, legal and other factors. For its aspiration to achieve net zero for upstream production Scope 1 and 2 GHG emissions on an equity basis by 2050, many of the necessary advancements in technology, policy and collective action have not occurred. As a result, Chevron is not on track to achieve the aspiration by 2050. While Chevron continues to have the aspiration, it will no longer use 2050 as a timeline.
The company’s ability to achieve any aspiration, target or goal is subject to numerous risks and contingencies, many of which are outside of Chevron’s control and persist. Examples of such risks and contingencies include: (1) sufficient and substantial advances in technology, including progress of commercially viable technologies and low- or non-carbon-based energy sources; (2) laws, governmental regulation, policies, and other enabling actions, including those regarding subsidies, tax and other incentives as well as the granting of necessary permits by governing authorities; (3) successful generation, acquisition, retirement and accounting of cost-effective, verifiable carbon offsets from nature-based solutions or carbon capture and storage; (4) the availability of suppliers that can meet sustainability-related standards; (5) evolving regulatory requirements affecting ESG standards or disclosures; (6) evolving standards for tracking and reporting on emissions and emission reductions and removals; (7) customers’ and consumers’ preferences and use of the company’s products or substitute products; and (8) actions taken by the company’s competitors. Please refer to “Risk Factors” in Part I, Item 1A, on pages 25 through 27 for further discussion of GHG regulation and climate change and the associated risks to Chevron’s business, including the risks impacting Chevron’s strategy, aspirations, targets and disclosures related to environmental, social, and governance matters.
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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 Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents

•Oil production GHG intensity of 24 kilograms (kg) carbon dioxide equivalent per barrel of oil-equivalent (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 zero routine flaring by 2030 as outlined in the World Bank’s “Zero Routine Flaring by 2030” initiative.
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.
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.
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.
Trends in the costs of goods and services vary by spend category. Chevron has applied inflation mitigation strategies to temper cost increases, including fixed price and index-based contracts. Lead times for key capital equipment remain long due to strong demand levels. Chevron has addressed equipment cost increases and long lead times by partnering with suppliers on demand planning, volume commitments, standardization, and scope optimization. The offshore market remains competitive for vessels and subsea equipment. In the United States, cost pressures for onshore drilling and completion equipment continue to ease.
In 2025, the U.S. announced the imposition of various changing tariffs on imports from our trade partners. The tariff impact in 2025 was less than one percent of the company’s third party spend and was not material to the company’s financial results. In first quarter 2026, the company continued to work with partners across its supply chain to identify alternative sourcing options and mitigate the impact of the tariffs. Although the U.S. Supreme Court struck down some global tariffs in February 2026, there remains significant uncertainty as to the duration and magnitude of any future tariffs that may be imposed as permitted under U.S. laws and, accordingly, as to the resultant impacts these tariffs could have on the company and its suppliers and the company’s future results of operations.
Acquisition and Disposition of Assets The company continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value and to acquire assets or operations complementary to its asset base to help augment the company’s financial performance and value growth. The company was targeting $10-15 billion of asset sales over the five-year period ending in 2028. From 2024 through January 2026, the company has generated approximately $9 billion of asset sales proceeds. Looking ahead, the company expects $1-2 billion in annual asset sale proceeds through 2030. Asset dispositions and restructurings may result in significant gains or losses in future periods.
In addition, some assets are divested along with their related liabilities, such as decommissioning obligations. In certain instances, such transferred obligations have returned and may continue to return to the company and result in losses that could be significant. For example, in fourth quarter 2023, the company recognized charges for decommissioning obligations from certain previously divested assets in the Gulf of America. In 2025, the company spent $297 million related to these obligations and anticipates spending an additional $200-300 million annually through 2033. To the extent the current owners of the company’s previously divested assets default on their decommissioning obligations, regulators
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 Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents

may require that Chevron assume such obligations. The company could have additional significant obligations revert, primarily in the United States. The company is not currently aware of any such obligations that are reasonably possible to be material. Refer to Note 24. Other Contingencies and Commitments for additional information.
In July 2025, the company completed its acquisition of Hess Corporation (Hess). Refer to Note 29. Acquisition of Hess Corporation for additional information.
Other Impacts The company closely monitors developments in the financial and credit markets, the level of worldwide economic activity, and the implications for the company of movements in prices for crude oil, natural gas and natural gas liquids (NGLs). Management takes these developments into account in the conduct of daily operations and for business planning.
The company has announced plans to achieve $3-4 billion in structural cost reductions by the end of 2026. These cost savings will largely come from optimizing the portfolio, leveraging technology to enhance productivity, and changing how and where work is performed, including expanded use of global capability centers. In 2025, the company delivered $1.5 billion in structural cost savings, with $2 billion achieved in the annual run rate.
Comments related to earnings trends for the company’s major business areas are as follows:
Upstream Earnings for the upstream segment are closely aligned with industry prices for crude oil, natural gas and NGLs. These 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, natural gas and NGLs, changes in fiscal terms of contracts, the pace of energy transition, and changes in tax, environmental and other applicable laws and regulations.
Chevron has interests in Venezuelan assets operated by independent affiliates. Chevron has been conducting limited activities in Venezuela consistent with authorizations issued by the United States government. The financial results for Chevron’s business in Venezuela have been recorded as non-equity investments since 2020, where income is only recognized when cash is received, and production and reserves are not included in the company’s results. Following the issuance of a general license and other authorizations, crude oil liftings in Venezuela restarted in 2023. Chevron maintained its presence in Venezuela consistent with the U.S. government sanctions policy, and pursuant to this policy, continued delivering limited crude oil to the U.S. from these affiliates through January 2026. Based on recently revised authorizations that align with current U.S. sanctions policy for Venezuela, Chevron will continue delivery of crude oil produced from its Venezuelan assets to the U.S. and to the international market. Current geopolitical developments relating to Venezuela could have an impact on the company’s operations in Venezuela and, as a result, impact the company’s future results of operations.
Chevron maintains an equity interest in the Caspian Pipeline Consortium (CPC) which provides a primary export route for Tengiz field production in Kazakhstan. An adverse event or incident affecting CPC operations, which CPC has experienced from time to time, such as recent drone attacks, could have a negative impact on the Tengiz field and the company’s future results of operations and financial position. The financial impacts of such risks remain uncertain.
Governments (including Russia) have imposed and may impose additional sanctions and other trade laws, restrictions and regulations that could lead to disruption in our ability to produce, transport and/or export crude in the region around Russia.
Chevron holds a 39.7 percent interest in the Leviathan field and a 25 percent interest in the Tamar field in Israel. The conflict between Israel and various regional adversaries has not significantly impacted the company’s operations, with the company continuing to maintain safe and reliable operations while meeting its contractual commitments. The company continues to monitor the potential for further conflict in the region, and any future impacts on the company’s results of operations and financial condition remain uncertain.
Commodity Prices The following chart shows the trend in benchmark prices for Brent crude oil, West Texas Intermediate (WTI) crude oil, and U.S. Henry Hub natural gas. The Brent price averaged $69 per barrel for the full-year 2025, compared
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to $81 in 2024. As of mid-February 2026, the Brent price was $70 per barrel. The WTI price averaged $65 per barrel for the full-year 2025, compared to $76 in 2024. As of mid-February 2026, the WTI price was $63 per barrel. The majority of the company’s equity crude production is priced based on the Brent benchmark. Crude prices were lower in 2025 driven by supply growth in non-OPEC countries and slowing demand despite impacts from geopolitical conflicts and OPEC+ supply decisions.
2748779069603    Sources: Platts (crude) & Energy Intelligence (natural gas)
The U.S. Henry Hub natural gas price averaged $3.53 per thousand cubic feet (MCF) for the full-year 2025, compared to $2.25 in 2024. As of mid-February 2026, the Henry Hub price was $3.43 per MCF. In the U.S., higher Henry Hub prices were driven by higher weather-driven demand in the U.S. and increasing liquefied natural gas (LNG) export demand.
Outside the United States, prices for natural gas also depend on regional supply and demand, regulatory circumstances and infrastructure conditions in local markets. The company’s long-term contract prices for LNG are typically linked to crude oil prices. Most of the equity LNG offtake from the operated Australian LNG projects is committed under binding long-term contracts, with some sold in the Asian spot LNG market.
See page 46 for the company’s U.S. and international average realizations for each of the past three years.
Production The company’s worldwide net oil-equivalent production in 2025 was 3.7 million barrels per day, 12 percent higher than in 2024 primarily due to the acquisition of Hess and growth in TCO, the Permian Basin and the Gulf of America, which were partly offset by the impacts of asset sales. About 21 percent of the company’s net oil-equivalent production in 2025 occurred in OPEC+ member countries of Equatorial Guinea, Kazakhstan, Malaysia, Nigeria and the Partitioned Zone between Saudi Arabia and Kuwait.
The company estimates its net oil-equivalent production in 2026 to increase 7 to 10 percent over 2025, assuming a Brent crude oil price of $60 per barrel and excluding expected asset sales. This includes a full year contribution from Hess assets. This estimate is subject to many factors and uncertainties, including quotas or other actions that may be imposed by OPEC+; 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.







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Net crude oil production
Thousands of barrels per day

10995116278049
Affiliates
Europe
Australia
Asia
Africa
Other Americas
United States
Net natural gas liquids production
Thousands of barrels per day

12
Affiliates
Europe
Australia
Asia
Africa
Other Americas
United States
Net natural gas production
Millions of cubic feet per day

18
Affiliates
Europe
Australia
Asia
Africa
Other Americas
United States
Net proved reserves by geographic area
Billions of BOE*

24
Affiliates
Europe
Australia
Asia
Africa
Other Americas
United States
*barrels of oil-equivalent
Net proved reserves by product
Billions of BOE*

30
Natural gas
Natural gas liquids
Crude oil
*barrels of oil-equivalent
Proved Reserves Net proved reserves for consolidated companies and affiliated companies totaled 10.6 billion barrels of oil-equivalent at year-end 2025, an increase from year-end 2024. The reserve replacement ratio in 2025 was 158 percent. The 5 and 10 year reserve replacement ratios were 91 percent and 95 percent, respectively. Refer to Table V for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2023 and each year-end from 2023 through 2025, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2025.
Refer to the “Results of Operations” section on pages 42 through 43 for additional discussion of the company’s upstream business.
Downstream Earnings for the downstream segment are closely tied to margins on the refining, manufacturing and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil, fuel and lubricant additives, petrochemicals and renewable fuels. Industry margins are sometimes volatile and can be affected by the global and regional supply-and-demand balance for refined products and petrochemicals, and by changes in the price of crude oil, other refinery and petrochemical feedstocks, and natural gas. Industry margins can also be influenced by inventory levels, geopolitical events, costs of materials and services, refinery or chemical plant capacity utilization, maintenance programs, and disruptions at refineries or chemical plants resulting from unplanned outages due to severe weather, fires or other operational events.
Other factors affecting profitability for downstream operations include the reliability and efficiency of the company’s refining, marketing and petrochemical assets, the effectiveness of its crude oil and product supply functions, and the volatility of tanker-charter rates for the company’s shipping operations, which are driven by the industry’s demand for crude oil and product tankers. Other factors beyond the company’s control include the general level of inflation and energy costs to operate the company’s refining, marketing and petrochemical assets, and changes in tax, environmental, and other applicable laws and regulations.
The company’s most significant marketing areas are the West Coast and Gulf Coast of the United States and Asia Pacific. Chevron operates or has significant ownership interests in refineries in each of these areas.
Refer to the “Results of Operations” section on page 43 for additional discussion of the company’s downstream operations.
All Other consists of worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities and technology companies.
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Noteworthy Developments
Key noteworthy developments and other events during 2025 and early 2026 included the following:
Angola Achieved first oil from the South N’dola platform, leveraging existing infrastructure.
Argentina Exercised option to participate in the Vaca Muerta Sur Pipeline Project to export crude from the Vaca Muerta shale to a new export terminal.
Australia Reached final investment decision (FID) on the Gorgon backfill development to connect the Geryon and Eurytion fields to existing infrastructure, enabling long-term supply of domestic gas in Western Australia and LNG in Asia.
Brazil Secured nine offshore blocks in the Foz do Amazonas Basin.
Guinea-Bissau Secured two frontier exploration blocks (Blocks 5B and 6B).
Guyana Achieved first oil at Yellowtail, the fourth development in the offshore Stabroek Block, and reached FID on the Hammerhead project, the seventh development.
Israel Reached FID on the Leviathan Gas Expansion project, which is expected to increase production capacity to 2.1 billion cubic feet per day and support increased exports to Egypt.
Kazakhstan Started production at the Future Growth Project and ramped up total production to approximately 1 million barrels of oil-equivalent per day at Tengiz.
Malaysia/Thailand JDA Completed the sale of the company’s interest in the Malaysia-Thailand Joint Development Area.
Namibia Secured exploration blocks in Petroleum Exploration License 82 (Blocks 2112B and 2212A) in Walvis Basin.
Nigeria Discovered hydrocarbons in two exploration and appraisal wells in the Delta South-AA in Petroleum Mining Lease 46 and the Awodi-07 in Petroleum Prospecting License 263 in shallow offshore water.
Peru Secured three offshore exploration blocks (Blocks Z-61, Z-62, and Z-63) in the Trujillo Basin.
Republic of Congo Completed the sale of the company’s interest in the Republic of Congo.
Suriname Secured two shallow water blocks (Blocks 9 and 10).
United States Completed the acquisition of Hess, creating a combined company with a premier upstream portfolio and achieving the initial run-rate synergy target of $1 billion.
United States Started and ramped up production at the Anchor, Ballymore, Stampede, and Whale fields in the deepwater Gulf of America.
United States Grew production in the Permian Basin by more than 10 percent with lower Capex compared to the prior year, reaching one million barrels of oil equivalent per day.
United States Discovered oil at the non-operated Far South well in the deepwater Gulf of America and secured additional exploration blocks in the Gulf of America.
United States Completed the sale of a portion of its interest in certain gas assets in East Texas and the sale of certain non-operated midstream pipelines and facilities.
United States Started production from the Geismar renewable diesel plant in Louisiana after completing an expansion that increased capacity from 7,000 to 22,000 barrels per day.
United States Entered the U.S. lithium sector and acquired approximately 135,000 net acres in the Smackover Formation in Northeast Texas and Southwest Arkansas for direct lithium extraction.
United States Announced plans to provide power solutions to support U.S. data center growth, with the first project under development in West Texas.
United States Achieved the highest U.S. refinery throughput in 20 years through recent expansion projects and efficiency improvements.
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Common Stock Dividends The 2025 annual dividend was $6.84 per share, making 2025 the 38th consecutive year that the company increased its annual per share dividend payout. In January 2026, the company’s Board of Directors increased its quarterly dividend by $0.07 per share, approximately four percent, to $1.78 per share payable in March 2026.
Common Stock Repurchase Program The company repurchased $12.1 billion of its common stock in 2025 under its stock repurchase program. For more information on the common stock repurchase program, see Liquidity and Capital Resources.
Results of Operations
The following section presents the results of operations and variances on an after-tax basis for the company’s business segments – Upstream and Downstream – as well as for “All Other.” Earnings are also presented for the U.S. and international geographic areas of the Upstream and Downstream business segments. Refer to Note 14 Operating Segments and Geographic Data for a discussion of the company’s “reportable segments.” This section should also be read in conjunction with the discussion in Business Environment and Outlook. Refer to the Selected Operating Data for a three-year comparison of production volumes, refined product sales volumes and refinery inputs. A discussion of variances between 2024 and 2023 can be found in the “Results of Operations” section on pages 43 through 44 of the company’s 2024 Annual Report on Form 10-K filed with the SEC on February 21, 2025.
Worldwide Upstream earnings
Billions of Dollars

6
United States
International
Worldwide Downstream earnings
Billions of dollars

12
United States
International
U.S. refined product sales
Thousands of barrels per day

18
Other
Fuel oil
Diesel/Gas oil
Jet fuel
Gasoline
International refined product sales*
Thousands of barrels per day

24
Other
Fuel oil
Diesel/Gas oil
Jet fuel
Gasoline
*includes equity share in affiliates

U.S. Upstream
Unit *
202520242023
Earnings$MM$5,815 $7,602 $4,148 
Net Oil-Equivalent ProductionMBOED1,858 1,5991,349
Liquids ProductionMBD1,3411,152997
Natural Gas ProductionMMCFD3,0992,6842,112
Liquids Realization$/BBL$48.13 $56.24 $59.19 
Natural Gas Realization$/MCF$2.05 $1.04 $1.67 
* 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 $1.8 billion, primarily due to lower liquids realizations of $2.4 billion, higher operating expenses of $2.0 billion, and higher depreciation, depletion and amortization of $1.4 billion, partly offset by higher sales volumes of $2.8 billion, and higher natural gas realizations of $800 million. All figures are inclusive of Hess.
Net oil-equivalent production was up 259,000 barrels per day, or 16 percent, primarily due to the acquisition of Hess and higher production in the Permian Basin and the Gulf of America.
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International Upstream
Unit2
202520242023
Earnings1
$MM$7,007 $11,000 $13,290 
Net Oil-Equivalent ProductionMBOED1,865 1,7391,771
Liquids ProductionMBD962823833
Natural Gas ProductionMMCFD5,4165,4945,632
Liquids Realization$/BBL$61.58 $71.38 $71.70 
Natural Gas Realization$/MCF$7.04 $7.32 $7.69 
1 Includes foreign currency effects:
$(408)$395 $376 
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 $4.0 billion, primarily due to higher DD&A of $2.8 billion, lower realizations of $2.0 billion, an unfavorable foreign currency effect of $803 million between periods, and the absence of prior year favorable asset sales impacts of $260 million, partly offset by higher liftings of $2.2 billion, and lower operating expenses of $470 million. All figures are inclusive of Hess.
Net oil-equivalent production was up 126,000 barrels per day, or 7 percent. The increase was primarily due to the acquisition of Hess and higher production at TCO in Kazakhstan, partly offset by impacts from asset sales in Canada and the Republic of Congo.
U.S. Downstream
Unit *
202520242023
Earnings$MM$1,375 $531 $3,904 
Refinery Crude Unit InputsMBD1,038917962
Refined Product SalesMBD1,3171,2861,287
* MBD — thousands of barrels per day.
U.S. downstream earnings increased by $844 million, primarily due to lower operating expenses of $730 million and higher margins on refined product sales of $580 million, partly offset by lower earnings from the 50 percent-owned Chevron Phillips Chemical Company of $440 million.
Refinery crude unit inputs were up 121,000 barrels per day, or 13 percent, primarily due to increased capacity at the Pasadena, Texas refinery upon completion of the Light Tight Oil project.
Refined product sales were up 31,000 barrels per day, or 2 percent, compared to the year-ago period.
International Downstream
Unit 2
202520242023
Earnings 1
$MM$1,647 $1,196 $2,233 
Refinery Crude Unit InputsMBD652646636
Refined Product SalesMBD1,4841,4951,445
1 Includes foreign currency effects:
$(48)$126 $(12)
2 MBD — thousands of barrels per day.
International downstream earnings increased by $451 million, primarily due to higher margins on refined product sales of $440 million and the absence of prior year impairments of $185 million, partly offset by foreign currency effects, which had an unfavorable impact on earnings of $174 million between periods.
Refinery crude unit inputs were up 6,000 barrels per day, or 1 percent from the year-ago period.
Refined product sales were down 11,000 barrels per day, or 1 percent from the year-ago period.
All Other
Unit202520242023
Net charges*
$MM$(3,545)$(2,668)$(2,206)
*Includes foreign currency effects:
$(13)$(1)$(588)
All Other consists of worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology companies.
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Net charges increased by $877 million, primarily due to higher interest expense, and higher pension settlement and curtailment costs.
Consolidated Statement of Income
Comparative amounts for certain income statement categories are shown below. A discussion of variances between 2024 and 2023 can be found in the “Consolidated Statement of Income” section on pages 45 and 46 of the company’s 2024 Annual Report on Form 10-K.
Millions of dollars202520242023 
Sales and other operating revenues$184,432 $193,414 $196,913 
Sales and other operating revenues decreased in 2025 mainly due to lower crude oil and refined product prices, partially offset by higher crude oil and refined product sales volumes and higher natural gas prices and volumes.
Millions of dollars202520242023 
Income (loss) from equity affiliates$3,000 $4,596 $5,131 
Income from equity affiliates decreased in 2025 mainly due to lower upstream-related earnings from Tengizchevroil LLP (TCO) in Kazakhstan as higher liftings from the FGP project were more than offset by higher depreciation, depletion and amortization and lower realizations, and lower downstream-related earnings from CPChem primarily due to lower chemicals margins. These decreases were partially offset by higher downstream-related earnings from GS Caltex in South Korea. Refer to Note 15 Investments and Advances for a discussion of Chevron’s investments in affiliated companies.
Millions of dollars202520242023 
Other income (loss)$1,599 $4,782 $(1,095)
Other income decreased in 2025 mainly due to the absence of before tax gains on asset sales in Canada, an unfavorable swing in foreign currency effects, and lower income from Venezuela.
Millions of dollars202520242023 
Purchased crude oil and products$108,214 $119,206 $119,196 
Purchased crude oil and products decreased in 2025 due to lower crude oil and refined product prices and volumes, partially offset by higher natural gas prices and volumes.
Millions of dollars202520242023 
Operating, selling, general and administrative expenses$33,131 $32,298 $29,028 
Operating, selling, general and administrative expenses increased compared to last year primarily due to the acquisition of Hess and higher professional service costs, partially offset by lower severance accruals.
Millions of dollars202520242023 
Exploration expense$1,051 $995 $914 
Exploration expenses in 2025 were relatively flat compared to last year.
Millions of dollars202520242023 
Depreciation, depletion and amortization$20,132 $17,282 $17,326 
Depreciation, depletion and amortization expenses increased in 2025 primarily due to higher production and higher rates.
Millions of dollars202520242023 
Taxes other than on income$5,230 $4,716 $4,220 
Taxes other than on income increased in 2025 primarily due to higher excise taxes related to downstream activities.
Millions of dollars202520242023 
Interest and debt expense$1,217 $594 $469 
Interest and debt expenses increased in 2025 mainly due to higher debt balances, including debt assumed from the acquisition of Hess.


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Millions of dollars202520242023 
Other components of net periodic benefit costs$313 $195 $212 
Other components of net periodic benefit costs increased in 2025 primarily due to higher settlement and curtailment losses, partially offset by higher expected return on plan assets.
Millions of dollars202520242023 
Income tax expense (benefit) $7,258 $9,757 $8,173 
The decrease in income tax expense in 2025 of $2.5 billion was primarily due to the decrease in total income before tax for the company of $7.8 billion, along with the absence of the tax impacts of the asset sales in Canada. The decrease in income before taxes for the company was primarily the result of higher upstream depreciation, depletion and amortization, lower upstream realizations, unfavorable foreign exchange impacts, and higher operating costs, partially offset by higher upstream sales volumes and higher downstream margins.
U.S. income before tax decreased from $8.1 billion in 2024 to $6.0 billion in 2025. This $2.1 billion decrease in income was primarily driven by lower upstream realizations, higher upstream depreciation, depletion and amortization and higher operating expenses, partially offset by higher upstream sales volumes and higher downstream margins. The decrease of $337 million in U.S. income tax expense between year-over-year periods, from $1.9 billion in 2024 to $1.6 billion in 2025, was primarily driven by the decrease in income before tax, partially offset by current period unfavorable tax items.
International income before tax decreased from $19.5 billion in 2024 to $13.8 billion in 2025. This $5.7 billion decrease in income was primarily driven by higher upstream depreciation, depletion and amortization, lower upstream realizations, unfavorable foreign exchange impacts and the absence of impacts related to the asset sales in Canada, partially offset by higher upstream sales volumes. The decrease of $2.2 billion in international income tax expense between year-over-year periods, from $7.9 billion in 2024 to $5.7 billion in 2025, was primarily driven by the decrease in income before tax, along with the absence of tax impacts of the asset sales in Canada.
Refer also to the discussion of the effective income tax rate in Note 17 Taxes.
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Selected Operating Data1,2
Unit202520242023
U.S. Upstream
Net Crude Oil and Natural Gas Liquids (NGLs) ProductionMBD1,3411,152997
Net Natural Gas Production3
MMCFD3,0992,6842,112
Net Oil-Equivalent ProductionMBOED1,8581,5991,349
Sales of Natural Gas4
MMCFD5,7175,1724,637
Sales of Natural Gas LiquidsMBD536490354
Revenues from Net Production
Crude$/BBL$62.22 $73.47 $75.04 
NGLs$/BBL$18.80 $19.88 $20.04 
Liquids (weighted average of Crude and NGLs)$/BBL$48.13 $56.24 $59.19 
Natural Gas$/MCF$2.05 $1.04 $1.67 
International Upstream
Net Crude Oil and NGLs Production5
MBD962823833
Net Natural Gas Production3
MMCFD5,4165,4945,632
Net Oil-Equivalent Production5
MBOED1,8651,7391,771
Sales of Natural GasMMCFD5,5355,6786,025
Sales of Natural Gas LiquidsMBD12613294
Revenues from Liftings
Crude$/BBL$63.25 $73.72 $74.29 
NGLs$/BBL$21.19 $26.49 $24.01 
Liquids (weighted average of Crude and NGLs)$/BBL$61.58 $71.38 $71.7 
Natural Gas$/MCF$7.04 $7.32 $7.69 
Worldwide Upstream
Net Oil-Equivalent Production5
United StatesMBOED1,8581,5991,349
InternationalMBOED1,8651,7391,771
TotalMBOED3,7233,3383,120
U.S. Downstream
Gasoline Sales6
MBD685667642
Other Refined Product SalesMBD632619645
Total Refined Product SalesMBD1,3171,2861,287
Sales of Natural Gas4
MMCFD282832
Sales of Natural Gas LiquidsMBD262122
Refinery Crude Unit Inputs8
MBD1,038917962
International Downstream
Gasoline Sales6
MBD388382353
Other Refined Product SalesMBD1,0961,1131,092
Total Refined Product Sales7
MBD1,4841,4951,445
Sales of Natural Gas4
MMCFD1—1
Sales of Natural Gas LiquidsMBD123136153
Refinery Crude Unit Inputs8
MBD652646636
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 StatesMMCFD64 60 64 
InternationalMMCFD582 549 532 
4 Downstream sales of Natural Gas separately identified from Upstream.
5 Includes net production of synthetic oil:
CanadaMBD— 46 51 
6 Includes branded and unbranded gasoline.
7 Includes sales of affiliates:
MBD384 386 389 
8 Includes crude oil and other inputs.

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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 $6.3 billion and $6.8 billion at December 31, 2025 and 2024, 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 2025 was $33.9 billion, compared to $31.5 billion in 2024, primarily as higher cash distributions from TCO and contributions from legacy Hess assets more than offset the impact of lower commodity prices. Between January and March 2025, Chevron purchased 15.38 million shares of Hess common stock in open market transactions for approximately $2.2 billion. Cash provided by operating activities was net of contributions to employee pension plans of approximately $588 million in 2025 and $844 million in 2024. Capital expenditures totaled $17.3 billion in 2025 compared to $16.4 billion in 2024. Proceeds and deposits related to asset sales and return of investments totaled $1.8 billion in 2025 compared to $7.7 billion in 2024. Net repayment (borrowing) of loans by equity affiliates included an inflow of $778 million in 2025 mainly due to a loan repayment from TCO, compared with an outflow of $233 million in the year ago period.
Restricted cash of $1.0 billion and $1.5 billion at December 31, 2025 and 2024, respectively, was held in cash and short-term marketable securities and recorded as “Deferred charges and other assets” and “Prepaid expenses and other current assets” on the Consolidated Balance Sheet. These amounts are generally associated with upstream decommissioning activities and tax payments. The decrease of restricted cash in 2025 is mainly due to the release of funds for tax-deferred exchanges.
Dividends Dividends paid to common stockholders were $12.8 billion in 2025 and $11.8 billion in 2024.
Debt and Finance Lease Liabilities Total debt, including finance lease liabilities, was $40.8 billion at December 31, 2025, up from $24.5 billion at year-end 2024. In 2025, the company issued $11.2 billion of public bonds, retired $4.0 billion of public bonds at maturity and reduced commercial paper balances. In third quarter 2025, the company also assumed $10.0 billion of debt and finance lease liabilities as part of the acquisition of Hess, including approximately $3.7 billion related to Hess Midstream Operations LP that is non-recourse to Chevron Corporation.
The company’s total debt due within one year, consisting primarily of the current portion of long-term debt and redeemable long-term obligations, totaled $10.9 billion at December 31, 2025, compared with $12.7 billion at year-end 2024. Of these amounts, $9.9 billion and $8.25 billion were reclassified to long-term debt at the end of 2025 and 2024, respectively, since settlement of these obligations was not expected to require the use of working capital within one year, as the company had the intent and the ability, as evidenced by committed credit facilities, to continue refinancing them.
The company has access to a commercial paper program as a financing source for working capital or other short-term needs. The company had $4.6 billion of commercial paper outstanding as of December 31, 2025, compared with $5.4 billion at December 31, 2024.
The company has an automatic shelf registration statement that expires in November 2027 for an unspecified amount of nonconvertible debt securities issued by Chevron Corporation or Chevron U.S.A. Inc. (CUSA).
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Cash from operating activities compared with capital expenditures and cash returned to shareholders
Billions of dollars
6
Hess stock purchase
Stock repurchases
Capital expenditures
Dividends
Cash from operating activities




Capital expenditures by segment
Billions of dollars
11
All Other
Downstream
Upstream





Affiliate capital expenditures
Billions of dollars
16
Downstream
Upstream






Debt at year-end
Billions of dollars
10995116277793
Total debt
Net debt*
*Refer to page 52 for calculations of debt and debt ratios





Debt coverage ratios
10995116277817
Debt-to-CFFO*
Net debt-to-CFFO*
*Refer to page 52 for calculations of debt and debt ratios


The major debt rating agencies routinely evaluate the company’s debt, and the company’s cost of borrowing can increase or decrease depending on these debt ratings. The company has outstanding public bonds issued by Chevron Corporation, CUSA, Noble Energy, Inc. (Noble), Texaco Capital Inc., and Hess Corporation. The securities that are the obligation of, or guaranteed by, Chevron Corporation carry an AA- rating by Standard and Poor’s Corporation and an Aa2 rating by Moody’s Investors Service. The company’s U.S. 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, acquisitions, investments, lending commitments to affiliates and cash returned to shareholders. 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,
20252024
(Millions of dollars) (unaudited)
Sales and other operating revenues$92,272 $96,035 
Sales and other operating revenues - related party36,700 43,562 
Total costs and other deductions92,316 102,116 
Total costs and other deductions - related party33,229 35,454 
Net income (loss) $40,967 $73,119 
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At December 31,
20252024
 (Millions of dollars) (unaudited)
Current assets$17,315 $16,918 
Current assets - related party2,266 2,626 
Other assets 58,530 57,921 
Current liabilities 26,388 30,563 
Current liabilities - related party18,033 22,997 
Other liabilities29,539 23,719 
Total net equity (deficit)$4,151 $186 

Common 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. During 2025, the company purchased a total of 79.9 million shares for $12.1 billion and paid an additional $146 million in excise taxes related to 2024 buybacks. As of December 31, 2025, the company had purchased a total of 250.8 million shares for $38.5 billion excluding excise taxes, resulting in $36.5 billion remaining under the 2023 Program. Chevron expects share repurchases in the first quarter of 2026 to be between $2.5-$3.0 billion.
Repurchases of shares of the company’s common stock may be made from time to time in the open market, by block purchases, in privately negotiated transactions or in such other manner as determined by the company. 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 2025, 2024, and 2023 is as follows:
Year ended December 31
Capex202520242023
Millions of dollarsU.S.Int’l.TotalU.S.Int’l.TotalU.S.Int’l.Total
Upstream$9,777 $6,113 $15,890 $9,481 $4,850 $14,331 $9,842 $3,836 $13,678 
Downstream676 252 928 1,443 251 1,694 1,536 237 1,773 
All Other476 53 529 406 17 423 351 27 378 
Capex$10,929 $6,418 $17,347 $11,330 $5,118 $16,448 $11,729 $4,100 $15,829 
Capex for 2025 was $17.3 billion, 5 percent higher than 2024 as spend on legacy Hess assets post-acquisition and increased investments in U.S. data center power solutions more than offset lower spend in the downstream segment.
The company estimates that 2026 organic capex will range from $18 to $19 billion. Upstream Capex is projected at $17 billion, including nearly $6 billion for U.S. shale and tight assets in the Permian, DJ and Bakken basins, and about $7 billion for global offshore developments, primarily supporting growth in Guyana, Eastern Mediterranean and Gulf of America. Downstream Capex is expected to be around $1 billion, with nearly three-fourths allocated to the U.S. operations. About $1 billion of total Capex, which is included within upstream and downstream budgets, is dedicated to lowering the carbon intensity of our operations and growing new energies businesses. Corporate and other Capex is projected to be about $0.6 billion.
Affiliate Capital Expenditures Equity affiliate capital expenditures (Affiliate Capex) primarily includes additions to fixed asset and investment accounts in the equity affiliate companies’ financial statements and does not require cash outlays by the company.
Affiliate Capex by business segment for 2025, 2024 and 2023 is as follows:
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Year ended December 31
Affiliate Capex202520242023
Millions of dollarsU.S.Int’l.TotalU.S.Int’l.TotalU.S.Int’l.Total
Upstream$— $797 $797 $— $1,451 $1,451 $— $2,310 $2,310 
Downstream795 208 1,003 802 196 998 983 241 1,224 
All Other— — — — — — — — — 
Affiliate Capex$795 $1,005 $1,800 $802 $1,647 $2,449 $983 $2,551 $3,534 
Affiliate Capex for 2025 was $1.8 billion, 27 percent lower than 2024 mainly due to lower spend at TCO’s Wellhead Pressure Management Project (WPMP) and Future Growth Project (FGP).
Affiliate Capex is expected to range between $1.3 to $1.7 billion in 2026. Nearly half of this amount is allocated to CPChem’s two major integrated polymer projects, while TCO’s budget accounts for roughly one-fourth.
The company monitors market conditions and can adjust future capital outlays should conditions change.
Noncontrolling Interests The company had noncontrolling interests of $5.7 billion at December 31, 2025, including non-controlling interest in Hess Midstream LP (HESM), and $839 million at December 31, 2024. Distributions to noncontrolling interests net of contributions totaled $323 million and $195 million in 2025 and 2024, respectively.
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: 2026 – $1.6 billion; 2027 – $1.4 billion; 2028 – $1.2 billion; 2029 – $1.1 billion; 2030 – $915 million; after 2030 – $6.0 billion.
Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements Information related to these off-balance sheet matters is included in Note 24 Other Contingencies and Commitments, under the heading “Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements.”
Direct Guarantees Information related to guarantees is included in Note 24 Other Contingencies and Commitments under the heading “Guarantees.”
Indemnifications Information related to indemnifications is included in Note 24 Other Contingencies and Commitments under the heading “Indemnifications.”
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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 2025, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $4.8 billion.
At December 31
Millions of dollars202520242023
Current assets$38,552 $40,911 $41,128 
Current liabilities33,387 38,558 32,258 
Current Ratio1.21.11.3
Interest Coverage Ratio Income before income tax expense, plus interest and debt expense and amortization of capitalized interest, less net income attributable to noncontrolling interests, divided by before-tax interest costs. This ratio indicates the company’s ability to pay interest on outstanding debt.
Year ended December 31
Millions of dollars202520242023
Income (Loss) Before Income Tax Expense $19,743 $27,506 $29,584 
Plus: Interest and debt expense 1,217 594 469 
Plus: Before-tax amortization of capitalized interest226 214 223 
Less: Net income attributable to noncontrolling interests186 88 42 
Subtotal for calculation21,000 28,226 30,234 
Total financing interest and debt costs$1,392 $773 $617 
Interest Coverage Ratio15.1 36.5 49.0 
Free Cash Flow The cash provided by operating activities less capital expenditures, which represents the cash from operations available to creditors and investors after investing in the business.
Year ended December 31
Millions of dollars202520242023
Net cash provided by operating activities $33,939 $31,492 $35,609 
Less: Capital expenditures17,347 16,448 15,829 
Free Cash Flow$16,592 $15,044 $19,780 
Adjusted Free Cash Flow Free cash flow excluding operating working capital impacts, plus proceeds and deposits related to asset sales and returns of investments, plus net repayments (borrowings) of loans by equity affiliates, which represents the total cash available to creditors and investors after investing in the business excluding the timing impacts of working capital. The company believes the preceding free cash flow measures are useful to monitor the financial health of the company and its performance over time.
Year ended December 31
Millions of dollars202520242023
Net cash provided by operating activities $33,939 $31,492 $35,609 
Less: Capital expenditures17,347 16,448 15,829 
Free Cash Flow$16,592 $15,044 $19,780 
Less: Net decrease (increase) in operating working capital(1,008)1,211 (3,185)
Plus: Proceeds and deposits related to asset sales and returns of investment1,826 7,704 669 
Plus: Net repayment (borrowing) of loans by equity affiliates778 (233)(302)
Adjusted Free Cash Flow$20,204 $21,304 $23,332 
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Debt Ratio Total debt as a percentage of total debt plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage.
At December 31
Millions of dollars202520242023
Short-term debt$977 $4,406 $529 
Long-term debt39,781 20,135 20,307 
Total debt 40,758 24,541 20,836 
Total Chevron Corporation Stockholders’ Equity186,450 152,318 160,957 
Total debt plus total Chevron Corporation Stockholders’ Equity$227,208 $176,859 $181,793 
Debt Ratio17.9 %13.9 %11.5 %

Net Debt Ratio Total debt less cash and cash equivalents, time deposits and marketable securities as a percentage of total debt less cash and cash equivalents, time deposits and marketable securities, plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage, net of its cash balances.
At December 31
Millions of dollars202520242023
Short-term debt$977 $4,406 $529 
Long-term debt39,781 20,135 20,307 
Total debt40,758 24,541 20,836 
Less: Cash and cash equivalents6,293 6,781 8,178 
Less: Time deposits4 4 — 
Less: Marketable securities— — 45 
Total net debt34,461 17,756 12,613 
Total Chevron Corporation Stockholders’ Equity
186,450 152,318 160,957 
Total net debt plus total Chevron Corporation Stockholders’ Equity$220,911 $170,074 $173,570 
Net Debt Ratio15.6 %10.4 %7.3 %

Debt-to-CFFO The sum of total debt divided by CFFO, which measures the company’s ability to cover its debt using the cash it generates from operations.
At December 31
Millions of dollars202520242023
Short-term debt$977 $4,406 $529 
Long-term debt39,781 20,135 20,307 
Total debt 40,758 24,541 20,836 
Net cash provided by operating activities (CFFO)33,939 31,492 35,609 
Debt-to-CFFO1.2x0.8x0.6x

Net Debt-to-CFFO The sum of total debt less cash and cash equivalents, time deposits and marketable securities, divided by CFFO, which measures the company’s ability to cover its net debt using the cash it generates from operations. The company believes the preceding debt measures are useful to monitor the strength of the company’s balance sheet.
At December 31
Millions of dollars202520242023
Short-term debt$977 $4,406 $529 
Long-term debt39,781 20,135 20,307 
Total debt40,758 24,541 20,836 
Less: Cash and cash equivalents6,293 6,781 8,178 
Less: Time deposits4 4 — 
Less: Marketable securities— — 45 
Total net debt34,461 17,756 12,613 
Net cash provided by operating activities (CFFO)33,939 31,492 35,609 
Net Debt-to-CFFO1.0x0.6x0.4x
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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 dollars202520242023
Chevron Corporation Stockholders’ Equity$186,450 $152,318 $160,957 
Plus: Short-term debt977 4,406 529 
Plus: Long-term debt39,781 20,135 20,307 
Plus: Noncontrolling interest5,726 839 972 
Capital Employed at December 31$232,934 $177,698 $182,765 
Return on Average Capital Employed (ROCE) Net income attributable to Chevron (adjusted for after-tax interest expense and noncontrolling interest) divided by average capital employed. Average capital employed is computed by averaging the sum of capital employed at the beginning and end of the year. ROCE is a ratio intended to measure annual earnings as a percentage of historical investments in the business.
Year ended December 31
Millions of dollars202520242023
Net income attributable to Chevron$12,299 $17,661 $21,369 
Plus: After-tax interest and debt expense 1,096 539 432 
Plus: Noncontrolling interest186 88 42 
Net income after adjustments13,581 18,288 21,843 
Average capital employed$205,316 $180,232 $183,173 
Return on Average Capital Employed6.6 %10.1 %11.9 %
Return on Stockholders’ Equity (ROSE) Net income attributable to Chevron divided by average Chevron Corporation Stockholders’ Equity. Average stockholders’ equity is computed by averaging the sum of stockholders’ equity at the beginning and end of the year. ROSE is a ratio intended to measure earnings as a percentage of shareholder investments.
Year ended December 31
Millions of dollars202520242023
Net income attributable to Chevron$12,299 $17,661 $21,369 
Chevron Corporation Stockholders’ Equity at December 31186,450 152,318 160,957 
Average Chevron Corporation Stockholders’ Equity169,384 156,638 160,120 
Return on Average Stockholders’ Equity7.3 %11.3 %13.3 %
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.
Derivative Commodity Instruments Chevron is exposed to market risks related to the price volatility of crude oil, refined products, NGLs, natural gas, LNG and refinery feedstocks. The company 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, LNG 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 2025.
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 2025 was not material to the company’s results of operations.
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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, 2025 and 2024 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, 2025.
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 2025, the company had no interest rate swaps.
Transactions With Related Parties
Chevron enters into a number of business arrangements with related parties, principally its equity affiliates. These arrangements include long-term supply or offtake agreements and long-term purchase agreements. Refer to “Other Information” in Note 15 Investments and Advances for further discussion. Management believes these agreements have been negotiated on terms consistent with those that would have been negotiated with an unrelated party.
Litigation and Other Contingencies
Climate Change Information related to climate change-related matters is included in Note 16 Litigation under the heading “Climate Change.”
Louisiana Information related to Louisiana coastal matters is included in Note 16 Litigation under the heading “Louisiana.”
Environmental The following table displays the annual changes to the company’s before-tax environmental remediation reserves, including those for U.S. federal Superfund sites and analogous sites under state laws.
Millions of dollars 202520242023
Balance at January 1$945 $936 $868 
Net additions395 264 327 
Expenditures(281)(255)(259)
Balance at December 31$1,059 $945 $936 
The company records asset retirement obligations when there is a legal obligation associated with the retirement of long-lived assets and the liability can be reasonably estimated. These asset retirement obligations include costs related to environmental issues. The liability balance of approximately $15.0 billion for asset retirement obligations at year-end 2025 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.
The company records decommissioning obligations for previously divested assets when it is probable that the decommissioning obligations would revert to the Company and costs can be reasonably estimated. At the end of 2025, the liability balance was $2.2 billion. Refer to Note 24 Other Contingencies and Commitments for additional discussion of decommissioning obligations for previously divested assets.
Refer to the discussion below for additional information on environmental matters and their impact on Chevron, and on the company’s 2025 environmental expenditures. Refer to Note 24 Other Contingencies and Commitments for additional discussion of environmental remediation provisions. Refer also to Note 25 Asset Retirement Obligations for additional discussion of the company’s asset retirement obligations.
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Suspended Wells Information related to suspended wells is included in Note 21 Accounting for Suspended Exploratory Wells.
Income Taxes Information related to income tax contingencies is included in Note 17 Taxes and in Note 24 Other Contingencies and Commitments under the heading “Income Taxes.”
Other Contingencies Information related to other contingencies is included in Note 24 Other Contingencies and Commitments under the heading “Other Contingencies.”
Environmental Matters
The company is subject to various international and U.S. federal, state and local environmental, health and safety laws, regulations and market-based programs. These laws, regulations and programs continue to evolve and are expected to increase in both number and complexity over time and govern not only the manner in which the company conducts its operations, but also the products it sells. Consideration of environmental issues and the responses to those issues through international agreements and national, regional or state legislation or regulations are integrated into the company’s strategy and planning, capital investment reviews and risk management tools and processes, where applicable. They are also factored into the company’s long-range supply, demand and energy price forecasts. These forecasts reflect long-range effects from electric vehicle and renewable fuel penetration, energy efficiency standards, climate-related policy actions, and demand response to oil and natural gas prices. In addition, legislation and regulations intended to address hydraulic fracturing also continue to evolve in many jurisdictions where we operate. Refer to Item 1A. Risk Factors for a discussion of some of the inherent risks of increasingly restrictive environmental and other regulation that could materially impact the company’s results of operations or financial condition. Refer to Business Environment and Outlook on pages 35 through 37 for a discussion of legislative and regulatory efforts to address climate change.
Most of the costs of complying with existing laws and regulations pertaining to company operations and products are embedded in the normal costs of doing business. However, it is not possible to predict with certainty the amount of additional investments in new or existing technology or facilities or the amounts of increased operating costs to be incurred in the future to prevent, control, reduce or eliminate releases of hazardous materials or other pollutants into the environment; remediate and restore areas damaged by prior releases of hazardous materials; or comply with new environmental laws or regulations. Although these costs may be significant to the results of operations in any single period, the company does not presently expect them to have a material adverse effect on the company’s liquidity or financial position.
Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. The company may incur expenses for corrective actions at various owned and previously owned facilities and at third-party-owned waste disposal sites used by the company. An obligation may arise when operations are closed or sold or at non-Chevron sites where company products have been handled or disposed of. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered acceptable at the time but now require investigative or remedial work or both to meet current standards.
Using definitions and guidelines established by the American Petroleum Institute, Chevron estimated its worldwide environmental spending in 2025 at approximately $2.8 billion for its consolidated companies. Included in these expenditures were approximately $0.8 billion of environmental capital expenditures and $2.0 billion of costs associated with the prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites, and the decommissioning and restoration of sites.
For 2026, total worldwide environmental capital expenditures are estimated at $0.7 billion. 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
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the issuance of the financial statements. Materially different results can occur as circumstances change and additional information becomes known.
The discussion in this section of “critical” accounting estimates and assumptions is according to the disclosure guidelines of the SEC, wherein:
1.the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters, or the susceptibility of such matters to change; and
2.the impact of the estimates and assumptions on the company’s financial condition or operating performance is material.
The development and selection of accounting estimates and assumptions, including those deemed “critical,” and the associated disclosures in this discussion have been discussed with the Audit Committee of the Board of Directors. The areas of accounting and the associated “critical” estimates and assumptions made by the company are as follows:
Oil and Gas Reserves Crude oil, NGLs and natural gas reserves are estimates of future production that impact certain asset and expense accounts included in the Consolidated Financial Statements. Proved reserves are the estimated quantities of oil and gas that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in the future under existing economic conditions, operating methods and government regulations. Proved reserves include both developed and undeveloped volumes. Proved developed reserves represent volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for recompletion. Variables impacting Chevron’s estimated volumes of crude oil, NGLs and natural gas reserves include field performance, available technology, commodity prices, and development, production and carbon costs.
The estimates of crude oil, NGLs and natural gas reserves are important to the timing of expense recognition for costs incurred and to the valuation of certain oil and gas producing assets. Impacts of oil and gas reserves on Chevron’s Consolidated Financial Statements, using the successful efforts method of accounting, include the following:
1.Depreciation, Depletion and Amortization (DD&A) - Capitalized exploratory drilling and development costs are depreciated on a unit-of-production (UOP) basis using proved developed reserves. Acquisition costs of proved properties are amortized on a UOP basis using total proved reserves. During 2025, Chevron’s UOP DD&A for oil and gas properties was $16.2 billion, and proved developed reserves at the beginning of 2025 were 6 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 2025 would have increased by approximately $900 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, 2023, 2024 and 2025, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” for estimates of proved reserve values for each of the three years ended December 31, 2023, 2024 and 2025.
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,
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commodity chemicals and refined products. However, the impairment reviews and calculations are based on assumptions that are generally consistent with the company’s business plans and long-term investment decisions. Refer also to the discussion of impairments of properties, plant and equipment in Note 18 Properties, Plant and Equipment and to the section on Properties, Plant and Equipment in Note 1 Summary of Significant Accounting Policies.
The company performs impairment assessments when triggering events arise to determine whether any write-down in the carrying value of an asset or asset group is required. For example, when significant downward revisions to crude oil, NGLs and natural gas reserves are made for any single field or concession, an impairment review is performed to determine if the carrying value of the asset remains recoverable. Similarly, a significant downward revision in the company’s crude oil, NGLs or natural gas price outlook would trigger impairment reviews for impacted upstream assets. In addition, impairments could occur due to changes in national, state or local environmental regulations or laws, including those designed to stop or impede the development or production of oil and gas. Also, if the expectation of sale of a particular asset or asset group in any period has been deemed more likely than not, an impairment review is performed, and if the estimated future undiscounted cash flows exceed the carrying value of the asset or asset group, no impairment charge is required. Such calculations are reviewed each period until the asset or asset group is disposed. Assets that are not impaired on a held-and-used basis could possibly become impaired if a decision is made to sell such assets. That is, the assets would be impaired if they are classified as held-for-sale and the estimated proceeds from the sale, less costs to sell, are less than the assets’ associated carrying values.
Investments in common stock of affiliates that are accounted for under the equity method, as well as investments in other securities of these equity investees, are reviewed for impairment when the fair value of the investment falls below the company’s carrying value. When this occurs, a determination must be made as to whether this loss is other-than-temporary, in which case the investment is impaired. Because of the number of differing assumptions potentially affecting whether an investment is impaired in any period or the amount of the impairment, a sensitivity analysis is not practicable.
A sensitivity analysis of the impact on earnings for these periods if other assumptions had been used in impairment reviews and impairment calculations is not practicable, given the broad range of the company’s PP&E and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired, or resulted in larger impacts on impaired assets.
Asset Retirement Obligations In the determination of fair value for an asset retirement obligation (ARO), the company uses various assumptions and judgments, including such factors as the existence of a legal obligation, estimated amounts and timing of settlements, discount and inflation rates, and the expected impact of advances in technology and process improvements. A sensitivity analysis of the ARO impact on earnings for 2025 is not practicable, given the broad range of the company’s long-lived assets and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions would have reduced estimated future obligations, thereby lowering accretion expense and amortization costs, whereas unfavorable changes would have the opposite effect. Refer to Note 25 Asset Retirement Obligations for additional discussions on asset retirement obligations.
Pension and Other Post-Employment Benefit Plans Note 23 Employee Benefit Plans includes information on the funded status of the company’s pension and other post-employment benefit (OPEB) plans reflected on the Consolidated Balance Sheet; the components of pension and OPEB expense reflected on the Consolidated Statement of Income; and the related underlying assumptions.
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 2025, the company used an expected long-term rate of return of 7.1 percent and a discount rate for service costs of 5.7 percent and a discount rate for interest cost of 5.1 percent for the primary U.S. pension plan. The actual return for 2025 was 11.1 percent. For the 10 years ended December 31, 2025, actual asset returns averaged 6.0 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 7.1 percent during each year.
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 Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents

Total pension expense for 2025 was $677 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 59 percent of companywide pension expense, would have reduced total pension plan expense for 2025 by approximately $93 million. A one percent increase in the discount rates for this same plan would have reduced pension expense for 2025 by approximately $175 million.
The aggregate funded status recognized at December 31, 2025, was a net liability of approximately $70 million. An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan. At December 31, 2025, the company used a discount rate of 5.5 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 56 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $247 million, and would have increased the plan’s surplus from $804 million to $1.1 billion.
For the company’s OPEB plans, expense for 2025 was $88 million, and the total liability, all unfunded at the end of 2025, was $2.0 billion. For the primary U.S. OPEB plan, the company used a discount rate for service cost of 5.8 percent and a discount rate for interest cost of 5.2 percent to measure expense in 2025, and a 5.3 percent discount rate to measure the benefit obligations at December 31, 2025. Discount rate changes, similar to those used in the pension sensitivity analysis, resulted in an immaterial impact on 2025 OPEB expense and OPEB liabilities at the end of 2025.
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 98 in Note 23 Employee Benefit Plans for more information on the $3.1 billion of before-tax actuarial losses recorded by the company as of December 31, 2025. In addition, information related to company contributions is included on page 101 in Note 23 Employee Benefit Plans under the heading “Cash Contributions and Benefit Payments.”
Business Combinations – Purchase-Price Allocation Accounting Accounting for business combinations requires the allocation of the company’s purchase price to the various assets and liabilities of the acquired business at their respective fair values. The company uses all available information to make these fair value determinations. Determining the fair value of assets acquired generally involves assumptions regarding the amounts and timing of future revenues and expenditures, as well as discount rates. For additional discussion of purchase price allocations, refer to Note 29 Acquisition of Hess Corporation.
Contingent Losses Management also makes judgments and estimates in recording liabilities for claims, litigation, tax matters, transferred liabilities from previously divested assets, and environmental remediation. Actual costs can frequently vary from estimates for a variety of reasons. For example, the costs for settlement of claims and litigation can vary from estimates based on differing interpretations of laws, opinions on culpability and assessments on the amount of damages. The costs for decommissioning obligations for previously divested assets can also vary from estimates. Recording of liabilities for such costs typically requires judgment to assess the likelihood of decommissioning obligations reverting to the company, the timing of decommissioning activity, regulatory requirements and the scope of decommissioning activities. Similarly, liabilities for environmental remediation are subject to change because of changes in laws, regulations and their interpretation, the determination of additional information on the extent and nature of site contamination, and improvements in technology.
Under the accounting rules, a liability is generally recorded for these types of contingencies if management determines the loss to be both probable and estimable. The company generally reports these losses as “Operating expenses,” “Selling, general and administrative expenses” or “Other income (loss)” on the Consolidated Statement of Income. An exception to this handling is for income tax matters, for which benefits are recognized only if management determines the tax position is more likely than not (i.e., likelihood greater than 50 percent) to be allowed by the tax jurisdiction. For additional discussion of income tax uncertainties, refer to Note 24 Other Contingencies and Commitments under the heading “Income Taxes.” Refer also to the business segment discussions elsewhere in this section for the effect on earnings from losses associated with certain litigation, environmental remediation and tax matters for the three years ended December 31, 2025.
An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in recording these liabilities is not practicable because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss. For further information, refer to “Changes in management’s estimates and assumptions may have a material
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 Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents

impact on the company’s consolidated financial statements and financial or operational performance in any given period” in Item 1A. Risk Factors, on page 27.
New Accounting Standards
Refer to Note 4 New Accounting Standards for information regarding new accounting standards.
59



Quarterly Results
Unaudited
20252024
Millions of dollars, except per-share amounts4th Q3rd Q2nd Q1st Q4th Q3rd Q2nd Q1st Q
Revenues and Other Income
Sales and other operating revenues
$45,787 $48,169 $44,375 $46,101 $48,334 $48,926 $49,574 $46,580 
Income from equity affiliates
663 981 536 820 688 1,261 1,206 1,441 
Other income (loss)423 576 (89)689 3,204 482 401 695 
Total Revenues and Other Income46,873 49,726 44,822 47,610 52,226 50,669 51,181 48,716 
Costs and Other Deductions
Purchased crude oil and products
25,348 27,398 26,858 28,610 30,148 30,450 30,867 27,741 
Operating expenses
7,389 7,534 6,674 6,408 7,622 6,695 6,614 6,533 
Selling, general and administrative expenses
1,492 1,524 889 1,221 1,585 1,191 1,048 1,010 
Exploration expenses
324 288 252 187 449154263129
Depreciation, depletion and amortization
5,884 5,781 4,344 4,123 4,973 4,214 4,004 4,091 
Taxes other than on income
1,327 1,347 1,301 1,255 1,141 1,263 1,188 1,124 
Interest and debt expense
361 370 274 212 199 164 113 118 
Other components of net periodic benefit costs
149 70 83 11 50 49 48 48 
Total Costs and Other Deductions42,274 44,312 40,675 42,027 46,167 44,180 44,145 40,794 
Income (Loss) Before Income Tax Expense4,599 5,414 4,147 5,583 6,059 6,489 7,036 7,922 
Income Tax Expense (Benefit)1,754 1,801 1,632 2,071 2,800 1,993 2,593 2,371 
Net Income (Loss)$2,845 $3,613 $2,515 $3,512 $3,259 $4,496 $4,443 $5,551 
Less: Net income (loss) attributable to noncontrolling interests75 74 25 12 20 9 9 50 
Net Income (Loss) Attributable to Chevron Corporation$2,770 $3,539 $2,490 $3,500 $3,239 $4,487 $4,434 $5,501 
Per Share of Common Stock
Net Income (Loss) Attributable to Chevron Corporation
– Basic
$1.39 $1.83 $1.45 $2.01 $1.85 $2.49 $2.43 $2.99 
– Diluted
$1.39 $1.82 $1.45 $2.00 $1.84 $2.48 $2.43 $2.97 
Dividends per share$1.71 $1.71 $1.71 $1.71 $1.63 $1.63 $1.63 $1.63 
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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, 2025. Based on that evaluation, management concluded that the company’s disclosure controls are effective in ensuring that information required to be recorded, processed, summarized and reported are done within the time periods specified in the U.S. Securities and Exchange Commission’s rules and forms.
Management’s Report on Internal Control Over Financial Reporting
The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in the Exchange Act Rules 13a-15(f) and 15d-15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s internal control over financial reporting based on the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the results of this evaluation, the company’s management concluded that internal control over financial reporting was effective as of December 31, 2025.
The company excluded Hess from our assessment of internal control over financial reporting as of December 31, 2025 because it was acquired by the company in a business combination during 2025. Total assets and total revenues of Hess, a wholly-owned subsidiary, represent 24 percent and 3 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2025.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2025, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein.
/s/ MICHAEL K. WIRTH/s/ EIMEAR P. BONNER/s/ ALANA K. KNOWLES
Michael K. WirthEimear P. BonnerAlana K. Knowles
Chairman of the BoardChief Financial OfficerController
and Chief Executive Officer
February 24, 2026

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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Chevron Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheet of Chevron Corporation and its subsidiaries (the “Company”) as of December 31, 2025 and 2024, 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, 2025, 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, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 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, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded Hess Corporation (Hess) from its assessment of internal control over financial reporting as of December 31, 2025 because it was acquired by the Company in a purchase business combination during 2025. We have also excluded Hess from our audit of internal control over financial reporting. Hess is a wholly-owned subsidiary of Chevron Corporation whose total assets and total revenues represent 24 percent and 3 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2025.
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Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
The Impact of Proved Developed Crude Oil and Natural Gas Reserves on Upstream Property, Plant, and Equipment, Net
As described in Notes 1 and 18 to the consolidated financial statements, the Company’s upstream property, plant and equipment, net balance was $200.8 billion as of December 31, 2025, and the related depreciation, depletion and amortization expense was $18.4 billion for the year ended December 31, 2025, the majority of which related to proved developed crude oil and natural gas reserves. The Company follows the successful efforts method of accounting for crude oil and natural gas exploration and production activities. Depreciation and depletion of all capitalized costs of proved crude oil and natural gas producing properties, except mineral interests, are expensed using the unit-of-production method, generally by individual field, as the proved developed reserves are produced. Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of-production method by individual field as the related proved reserves are produced. As disclosed by management, variables impacting the Company’s estimated volumes of proved crude oil, natural gas liquids (NGLs) and natural gas reserves include field performance, available technology, commodity prices, and development, production and carbon costs. Proved reserves are estimated by Company asset teams composed of earth scientists and engineers. As part of the internal control process related to reserves estimation, the Company maintains a Reserves Advisory Committee (RAC) (the Company’s earth scientists, engineers and RAC are collectively referred to as “management’s specialists”).
The principal considerations for our determination that performing procedures relating to the impact of proved developed crude oil and natural gas reserves on upstream property, plant, and equipment, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved developed crude oil and natural gas reserves, which are derived using historical production volumes and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, specifically historical production volumes, methods, and assumptions used by management and its specialists in developing the estimates of proved developed crude oil and natural gas reserves.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls
63

relating to management’s estimates of proved developed crude oil and natural gas reserves. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of proved developed crude oil and natural gas reserves. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included (i) evaluating the methods and assumptions used by the specialists; (ii) testing the completeness and accuracy of the data used by the specialists related to historical production volumes; and (iii) evaluating the specialists’ findings related to estimated future production volumes by comparing the estimate to relevant historical and current period production volumes, as applicable.
Acquisition of Hess - Valuation of Oil and Gas Properties
As described in Note 29 to the consolidated financial statements, on July 18, 2025, the Company acquired Hess and recorded estimated fair values of the acquired properties, plant and equipment of approximately $73.5 billion, of which a significant portion relates to oil and gas properties. Oil and gas properties were valued using a discounted cash flow model that incorporated assumptions for commodity prices, future production volumes, operating costs, development costs, and risk-adjusted discount rates.
The principal considerations for our determination that performing procedures relating to the valuation of oil and gas properties acquired in the acquisition of Hess is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the fair value estimates of oil and gas properties acquired; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to commodity prices, future production volumes, operating costs, development costs, and risk-adjusted discount rates; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the acquisition accounting, including controls over the valuation of oil and gas properties acquired. These procedures also included, among others (i) reading the acquisition agreement; (ii) testing management’s process for developing the fair value estimates of oil and gas properties acquired; (iii) evaluating the appropriateness of the discounted cash flow model; (iv) testing the completeness and accuracy of underlying data used in the discounted cash flow model; and (v) evaluating the reasonableness of the significant assumptions used by management related to commodity prices, future production volumes, operating costs, development costs, and risk-adjusted discount rates. Evaluating the reasonableness of management’s assumption related to commodity prices involved comparing the prices to observable market data. Evaluating the reasonableness of management’s assumptions relating to future production volumes, operating costs, and development costs involved evaluating whether the assumptions used by management were reasonable as compared to historical results of Hess. Professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of the discounted cash flow model and the reasonableness of the risk-adjusted discount rates assumptions. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the future production volumes used in the discounted cash flow model. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included (i) evaluating the methods and assumptions used by the specialists; (ii) testing the completeness and accuracy of the data used by the specialists; and (iii) evaluating the specialists’ findings.
/s/ PricewaterhouseCoopers LLP
San Francisco, California
February 24, 2026
We have served as the Company’s auditor since 1935.
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Consolidated Statement of Income
Financial Table of Contents
Millions of dollars, except per-share amounts
Year ended December 31
202520242023
Revenues and Other Income
Sales and other operating revenues$184,432 $193,414 $196,913 
Income (loss) from equity affiliates3,000 4,596 5,131 
Other income (loss)1,599 4,782 (1,095)
Total Revenues and Other Income189,031 202,792 200,949 
Costs and Other Deductions
Purchased crude oil and products108,214 119,206 119,196 
Operating expenses28,005 27,464 24,887 
Selling, general and administrative expenses5,126 4,834 4,141 
Exploration expenses1,051 995 914 
Depreciation, depletion and amortization20,132 17,282 17,326 
Taxes other than on income5,230 4,716 4,220 
Interest and debt expense1,217 594 469 
Other components of net periodic benefit costs313 195 212 
Total Costs and Other Deductions169,288 175,286 171,365 
Income (Loss) Before Income Tax Expense19,743 27,506 29,584 
Income Tax Expense (Benefit)7,258 9,757 8,173 
Net Income (Loss)12,485 17,749 21,411 
Less: Net income (loss) attributable to noncontrolling interests186 88 42 
Net Income (Loss) Attributable to Chevron Corporation$12,299 $17,661 $21,369 
Per Share of Common Stock
Net Income (Loss) Attributable to Chevron Corporation
- Basic$6.65 $9.76 $11.41 
- Diluted$6.63 $9.72 $11.36 
See accompanying Notes to the Consolidated Financial Statements.
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Consolidated Statement of Comprehensive Income
Financial Table of Contents
Millions of dollars
Year ended December 31
202520242023
Net Income (Loss)$12,485 $17,749 $21,411 
Currency translation adjustment
Unrealized net change arising during period60 (67)11 
Unrealized holding gain (loss) on securities
Net gain (loss) arising during period15 (8)1 
Derivatives
Net derivatives gain (loss) on hedge transactions— (50)(11)
Reclassification to net income27 25 33 
Income tax benefit (cost) on derivatives transactions(5)6 (5)
Total22 (19)17 
Defined benefit plans
Actuarial gain (loss)
Amortization to net income of net actuarial loss and settlements335 247 244 
Actuarial gain (loss) arising during period(180)228 (550)
Prior service credits (cost)
Amortization to net income of net prior service costs and curtailments(10)(10)(13)
Prior service (costs) credits arising during period59 (48)(29)
Defined benefit plans sponsored by equity affiliates - benefit (cost) 16 (19)6 
Income tax benefit (cost) on defined benefit plans(21)(104)151 
Total199 294 (191)
Other Comprehensive Gain (Loss), Net of Tax296 200 (162)
Comprehensive Income (Loss)12,781 17,949 21,249 
Comprehensive loss (income) attributable to noncontrolling interests(186)(88)(42)
Comprehensive Income (Loss) Attributable to Chevron Corporation$12,595 $17,861 $21,207 
See accompanying Notes to the Consolidated Financial Statements.
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Consolidated Balance Sheet
Financial Table of Contents
Millions of dollars, except per-share amounts
At December 31
20252024
Assets
Cash and cash equivalents$6,293 $6,781 
Time deposits4 4 
Marketable securities— — 
Accounts and notes receivable (less allowance: 2025 - $176; 2024 - $259)
18,075 20,684 
Inventories:
Crude oil and products6,640 6,490 
Chemicals571 502 
Materials, supplies and other2,500 2,082 
Total inventories9,711 9,074 
Prepaid expenses and other current assets4,469 4,368 
Total Current Assets38,552 40,911 
Long-term receivables, net (less allowances: 2025 - $216; 2024 - $352)
1,035 877 
Investments and advances43,867 47,438 
Properties, plant and equipment, at cost434,955 345,933 
Less: Accumulated depreciation, depletion and amortization215,226 198,134 
Properties, plant and equipment, net219,729 147,799 
Deferred charges and other assets16,236 14,854 
Goodwill4,568 4,578 
Assets held for sale25 481 
Total Assets$324,012 $256,938 
Liabilities and Equity
Short-term debt
$977 $4,406 
Accounts payable19,280 22,079 
Accrued liabilities10,763 8,486 
Federal and other taxes on income844 1,872 
Other taxes payable1,523 1,715 
Total Current Liabilities33,387 38,558 
Long-term debt1
39,781 20,135 
Deferred credits and other noncurrent obligations24,543 22,094 
Noncurrent deferred income taxes30,014 19,137 
Noncurrent employee benefit plans4,111 3,857 
Total Liabilities2
$131,836 $103,781 
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, 2025 and 2024)
1,832 1,832 
Capital in excess of par value33,886 21,671 
Retained earnings205,365 205,852 
Accumulated other comprehensive losses(2,464)(2,760)
Deferred compensation and benefit plan trust(240)(240)
Treasury stock, at cost (2025 - 448,260,458 shares; 2024 - 673,664,306 shares)
(51,929)(74,037)
Total Chevron Corporation Stockholders’ Equity186,450 152,318 
Noncontrolling interests5,726 839 
Total Equity192,176 153,157 
Total Liabilities and Equity$324,012 $256,938 
1 Includes finance lease liabilities of $659 and $546 at December 31, 2025 and 2024, respectively.
2 Refer to Note 24 Other Contingencies and Commitments.
See accompanying Notes to the Consolidated Financial Statements.
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Consolidated Statement of Cash Flows
Financial Table of Contents
Millions of dollars
Year ended December 31
202520242023
Operating Activities
Net Income (Loss)$12,485 $17,749 $21,411 
Adjustments
Depreciation, depletion and amortization20,132 17,282 17,326 
Dry hole expense325 429 436 
Distributions more (less) than income from equity affiliates2,282 (366)(885)
Net before-tax gains on asset retirements and sales(462)(1,685)(138)
Net foreign currency effects585 (629)578 
Deferred income tax provision986 1,240 298 
Net decrease (increase) in operating working capital(1,008)1,211 (3,185)
Decrease (increase) in long-term receivables(132)114 150 
Net decrease (increase) in other deferred charges(508)(1,225)(300)
Cash contributions to employee pension plans(588)(844)(1,120)
Other(158)(1,784)1,038 
Net Cash Provided by Operating Activities33,939 31,492 35,609 
Investing Activities
Acquisition of businesses, net of cash received1,056 — 55 
Acquisition of Hess Corporation common stock(2,225)— — 
Capital expenditures(17,347)(16,448)(15,829)
Proceeds and deposits related to asset sales and returns of investment1,826 7,704 669 
Net maturities of (investments in) time deposits1 (4)— 
Net sales (purchases) of marketable securities— 45 175 
Net repayment (borrowing) of loans by equity affiliates778 (233)(302)
Net Cash Used for Investing Activities(15,911)(8,936)(15,232)
Financing Activities
Net borrowings (repayments) of short-term obligations(1,061)4,868 135 
Proceeds from issuances of long-term debt11,402 478 150 
Repayments of long-term debt and other financing obligations(4,475)(1,778)(4,340)
Cash dividends - common stock(12,751)(11,801)(11,336)
Net contributions from (distributions to) noncontrolling interests(323)(195)(40)
Net sales (purchases) of treasury shares(11,855)(15,044)(14,678)
Net Cash Provided by (Used for) Financing Activities(19,063)(23,472)(30,109)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash
58 (97)(114)
Net Change in Cash, Cash Equivalents and Restricted Cash(977)(1,013)(9,846)
Cash, Cash Equivalents and Restricted Cash at January 18,262 9,275 19,121 
Cash, Cash Equivalents and Restricted Cash at December 31$7,285 $8,262 $9,275 
See accompanying Notes to the Consolidated Financial Statements.
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Consolidated Statement of Equity
Financial Table of Contents
Millions of dollars, except per-share amounts
Acc. OtherTreasuryChevron Corp.
CommonRetainedComprehensiveStockStockholders’NoncontrollingTotal
Stock1
EarningsIncome (Loss)
(at cost)
EquityInterestsEquity
Balance at December 31, 2022$20,252 $190,024 $(2,798)$(48,196)$159,282 $960 $160,242 
Treasury stock transactions174 — — — 174 — 174 
PDC Energy, Inc. acquisition2,550 — — 3,970 6,520 — 6,520 
Net income (loss)— 21,369 — — 21,369 42 21,411 
Cash dividends ($6.04 per share)
— (11,336)— — (11,336)(54)(11,390)
Stock dividends— (9)— — (9)— (9)
Other comprehensive income— — (162)— (162)— (162)
Purchases of treasury shares— — — (15,085)(15,085)— (15,085)
Issuances of treasury shares17 — — 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 
Treasury stock transactions255 — — — 255 — 255 
Net income (loss)— 17,661 — — 17,661 88 17,749 
Cash dividends ($6.52 per share)
— (11,801)— — (11,801)(210)(12,011)
Stock dividends— (22)— — (22)— (22)
Other comprehensive income— — 200 — 200 — 200 
Purchases of treasury shares— — — (15,374)(15,374)— (15,374)
Issuances of treasury shares51 — — 402 453 — 453 
Other changes, net— (11)— — (11)(11)(22)
Balance at December 31, 2024$23,263 $205,852 $(2,760)$(74,037)$152,318 $839 $153,157 
Treasury stock transactions541 — — — 541 — 541 
Hess Corporation acquisition11,775 — — 33,828 45,603 5,035 50,638 
Net income (loss)— 12,299 — — 12,299 186 12,485 
Cash dividends ($6.84 per share)
— (12,751)— — (12,751)(334)(13,085)
Stock dividends— (35)— — (35)— (35)
Other comprehensive income— — 296 — 296 — 296 
Purchases of treasury shares2
— — — (12,225)(12,225)— (12,225)
Issuances of treasury shares(101)— — 505 404 — 404 
Other changes, net — — — — — — — 
Balance at December 31, 2025$35,478 $205,365 $(2,464)$(51,929)$186,450 $5,726 $192,176 
Common Stock Share Activity
Issued3
TreasuryOutstanding
Balance at December 31, 20222,442,676,580 (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, 20232,442,676,580 (577,028,776)1,865,647,804 
Purchases— (100,444,608)(100,444,608)
Issuances— 3,809,078 3,809,078 
Balance at December 31, 20242,442,676,580 (673,664,306)1,769,012,274 
Purchases— (80,072,818)(80,072,818)
Issuances— 305,476,666 305,476,666 
Balance at December 31, 20252,442,676,580 (448,260,458)1,994,416,122 
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.
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Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts

Note 1
Summary of Significant Accounting Policies
General The company’s Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America. These require the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Although the company uses its best estimates and judgments, actual results could differ from these estimates as circumstances change and additional information becomes known. Prior years’ data have been reclassified in certain cases to conform to the 2025 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.
Variable interest entity The company enters into certain arrangements with legal entities that are evaluated under ASC 810 to determine whether they represent variable interest entities (VIEs). Hess Midstream LP (HESM) is Chevron’s only significant VIE. The company had an approximately 38 percent consolidated ownership interest at December 31, 2025 in HESM, with the balance owned by public shareholders. The company has concluded that it is the primary beneficiary of the VIE since it has the power to direct those activities that most significantly impact the economic performance of HESM, and is obligated to absorb losses and has the right to receive benefits that could potentially be significant to HESM. This conclusion was based on a qualitative analysis that considered HESM’s governance structure, the commercial agreements between HESM and the company, and the voting rights established between the members.
Noncontrolling Interests Ownership interests in the company’s subsidiaries held by parties other than the parent are presented separately from the parent’s equity on the Consolidated Balance Sheet. The amount of consolidated net income attributable to the parent and the noncontrolling interests are both presented on the face of the Consolidated Statement of Income and Consolidated Statement of Equity.
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
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arrangements, fair value receivable and payable amounts recognized for derivative instruments executed with the same counterparty are generally offset on the balance sheet.
Inventories Crude oil, products and chemicals inventories are generally stated at cost, using a last-in, first-out method. In the aggregate, these costs are below market. “Materials, supplies and other” inventories are primarily stated at cost or net realizable value.
Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and production activities. 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
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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 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.
Decommissioning Obligations from Previously Divested Assets Some assets are divested with their related liabilities, including decommissioning obligations, to a buyer that results in de-recognition of the liability from the balance sheet. In certain instances, such transferred obligations may return to the company and result in losses. To the extent the current owners of the company’s previously divested assets default on their decommissioning obligations, regulators may require that Chevron assume such obligations. The company would accrue losses associated with these obligations when management determines the loss to be both probable and reasonably estimable. This typically requires judgment to assess the likelihood of decommissioning obligations reverting to the company, the timing of decommissioning activity, regulatory requirements and the scope of decommissioning activities. For more information on decommissioning obligations related to previously divested assets, refer to Note 24 Other Contingencies and Commitments.
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 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” within Note 2. Changes in AOCL.
Revenue Recognition The company accounts for each delivery order of crude oil, NGLs, natural gas, petroleum and chemical products as a separate performance obligation. 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
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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. For more information on stock options and other share-based compensation, refer to Note 22 Stock Options and Other Share-Based Compensation.
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, 2025, are reflected in the table below.
Currency Translation AdjustmentsUnrealized Holding Gains (Losses) on SecuritiesDerivativesDefined Benefit PlansTotal
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)
Components of Other Comprehensive Income (Loss)1:
Before Reclassifications
(67)(8)(44)119 — 
Reclassifications2, 3
— — 25 175 200 
Net Other Comprehensive Income (Loss)(67)(8)(19)294 200 
Balance at December 31, 2024$(259)$(19)$(14)$(2,468)$(2,760)
Components of Other Comprehensive Income (Loss)1:
Before Reclassifications
60 15 (5)(46)24 
Reclassifications2, 3
— — 27 245 272 
Net Other Comprehensive Income (Loss)60 15 22 199 296 
Balance at December 31, 2025$(199)$(4)$8 $(2,269)$(2,464)
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 $325 that are included in employee benefit costs for the year ended December 31, 2025. Related income taxes for the same period, totaling $80, are reflected in Income Tax Expense on the Consolidated Statement of Income. All other reclassified amounts were insignificant.
3 Refer to Note 10 Financial and Derivative Instruments for cash flow hedging.
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Note 3
Information Relating to the Consolidated Statement of Cash Flows
Year ended December 31
202520242023
Distributions more (less) than income from equity affiliates includes the following:
Distributions from equity affiliates$5,282 $4,230 $4,246 
(Income) loss from equity affiliates(3,000)(4,596)(5,131)
Distributions more (less) than income from equity affiliates$2,282 $(366)$(885)
Net decrease (increase) in operating working capital was composed of the following:
Decrease (increase) in accounts and notes receivable$3,829 $(932)$1,187 
Decrease (increase) in inventories51 (574)(320)
Decrease (increase) in prepaid expenses and other current assets (109)(16)(1,202)
Increase (decrease) in accounts payable and accrued liabilities (3,469)2,569 (49)
Increase (decrease) in income and other taxes payable(1,310)164 (2,801)
Net decrease (increase) in operating working capital$(1,008)$1,211 $(3,185)
Net cash provided by operating activities includes the following cash payments:
Interest on debt (net of capitalized interest)$942 $587 $465 
Income taxes7,304 8,458 10,416 
Proceeds and deposits related to asset sales and returns of investment consisted of the following gross amounts:
Proceeds and deposits related to asset sales $1,677 $7,509 $446 
Returns of investment from equity affiliates149 195 223 
Proceeds and deposits related to asset sales and returns of investment$1,826 $7,704 $669 
Net maturities (investments) of time deposits consisted of the following gross amounts:
Investments in time deposits$(16)$(6)$— 
Maturities of time deposits17 2 — 
Net maturities of (investments in) time deposits$1 $(4)$— 
Net sales (purchases) of marketable securities consisted of the following gross amounts:
Marketable securities purchased$— $— $(289)
Marketable securities sold— 45 464 
Net sales (purchases) of marketable securities$— $45 $175 
Net repayment (borrowing) of loans by equity affiliates:
Borrowing of loans by equity affiliates$(300)$(304)$(368)
Repayment of loans by equity affiliates1,078 71 66 
Net repayment (borrowing) of loans by equity affiliates$778 $(233)$(302)
Net borrowings (repayments) of short-term obligations consisted of the following gross and net amounts:
Repayments of short-term obligations $(9,877)$(840)$— 
Proceeds from issuances of short-term debt obligations7,852 4,539 — 
Net borrowings (repayments) of short-term obligations with three months or less maturity964 1,169 135 
Net borrowings (repayments) of short-term obligations$(1,061)$4,868 $135 
Net sales (purchases) of treasury shares consists of the following gross and net amounts:
Shares issued for share-based compensation plans$370 $330 $261 
Shares purchased under share repurchase and deferred compensation plans (12,079)(15,229)(14,939)
Share repurchase excise tax payments(146)(145)— 
Net sales (purchases) of treasury shares$(11,855)$(15,044)$(14,678)
Net contributions from (distributions to) noncontrolling interests consisted of the following gross and net amounts:
Distributions to noncontrolling interests$(334)$(210)$(54)
Contributions from noncontrolling interests11 15 14 
Net contributions from (distributions to) noncontrolling interests$(323)$(195)$(40)
The “Other” line in the Operating Activities section includes changes in asset retirement obligations, decommissioning obligations associated with previously divested assets, post-employment benefit obligations, equity-based compensation adjustments, and other long-term liabilities. Refer also to Note 25 Asset Retirement Obligations for a discussion of the company’s AROs activity, including revisions that did not involve cash receipts or payments.
The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash.
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Refer also to Note 29 - Acquisition of Hess Corporation for a discussion of the acquisition of Hess. Cash received in connection with the acquisition is reflected in the Consolidated Statement of Cash Flows as “Acquisition of businesses, net of cash received.” Acquisition‑related changes to the Consolidated Balance Sheet that did not result in cash inflows or outflows are excluded from the Consolidated Statement of Cash Flows.
The components of “Capital expenditures” are presented in the following table:
Year ended December 31
202520242023
Additions to properties, plant and equipment*
$16,830 $15,544 $14,788 
Additions to investments225 573 690 
Current-year dry hole expenditures292 331 326 
Payments for other assets and liabilities, net
— — 25 
Capital expenditures$17,347 $16,448 $15,829 
* Excludes non-cash movements of $1,235 in 2025, $395 in 2024 and $1,559 in 2023.
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
202520242023
Cash and cash equivalents
$6,293 $6,781 $8,178 
Restricted cash included in “Prepaid expenses and other current assets”
174 281 275 
Restricted cash included in “Deferred charges and other assets”
818 1,200 822 
Total cash, cash equivalents and restricted cash
$7,285 $8,262 $9,275 
Note 4
New Accounting Standards
Income Taxes (Topic 740) Improvements to Income Tax Disclosures The company has adopted the Financial Accounting Standards Board (FASB) Accounting Standard Update (ASU) 2023-09 which is effective for fiscal years beginning after December 15, 2024. The standard requires companies to disclose specific categories in the income tax rate reconciliation table and the amount of income taxes paid per major jurisdiction. The adoption of this ASU did not have an impact on the company’s consolidated financial position or results of operations. For additional information, refer to Note 17 Taxes.
Income Statement (Topic 220) Reporting Comprehensive Income - Expense Disaggregation Disclosures In November 2024, the FASB issued ASU 2024-03, which becomes effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027. The standard requires companies to disclose disaggregated information about certain income statement expense line items. 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.
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Details of the right-of-use assets and lease liabilities for operating and finance leases, including the balance sheet presentation, are as follows:
At December 31, 2025At December 31, 2024
Operating
Leases		Finance
Leases		Operating
Leases		Finance
Leases
Deferred charges and other assets$6,054 $— $5,315 $— 
Properties, plant and equipment, net— 1,413 — 570 
Right-of-use assets*$6,054 $1,413 $5,315 $570 
Accrued liabilities$1,831 $— $1,519 $— 
Short-term debt— 786 — 58 
Current lease liabilities1,831 786 1,519 58 
Deferred credits and other noncurrent obligations4,154 — 3,551 — 
Long-term debt— 659 — 546 
Noncurrent lease liabilities4,154 659 3,551 546 
 Total lease liabilities
$5,985 $1,445 $5,070 $604 
Weighted-average remaining lease term (in years)6.66.56.313.2
Weighted-average discount rate4.0 %4.9 %3.7 %4.6 %
* Includes non-cash additions of $2,845 and $971 in 2025, and $2,205 and $40 in 2024 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
202520242023
Operating lease costs*$3,719 $3,447 $2,984 
Finance lease costs 154 8352
Total lease costs
$3,873 $3,530 $3,036 
* 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
202520242023
Operating cash flows from operating leases$2,838 $2,468 $2,271 
Investing cash flows from operating leases881 979 713 
Operating cash flows from finance leases42 26 15 
Financing cash flows from finance leases136 67 42 
At December 31, 2025, the estimated future undiscounted cash flows for operating and finance leases were as follows:
At December 31, 2025
Operating LeasesFinance
Leases
Year2026$2,017 $825 
20271,369 98 
2028898 96 
2029551 93 
2030365 83 
Thereafter1,701 524 
Total$6,901 $1,719 
Less: Amounts representing interest916 274 
Total lease liabilities
$5,985 $1,445 
Additionally, the company has $1,316 in future undiscounted cash flows for operating leases not yet commenced. These leases are primarily for drilling rigs, time chartered vessels, exploration and production equipment and storage tanks. For
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those leasing arrangements where the underlying asset is not yet constructed, the lessor is primarily involved in the design and construction of the asset.
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, and natural gas liquids (NGLs) 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
202520242023
Sales and other operating revenues
$142,048 $149,925 $152,347 
Total costs and other deductions
136,059 145,582 144,482 
Net income (loss) attributable to CUSA
5,197 4,151 4,598 
At December 31
20252024
Current assets$18,442 $20,153 
Other assets59,166 58,485 
Current liabilities22,943 25,825 
Other liabilities31,646 21,455 
Total CUSA net equity$23,019 $31,358 
Memo: Total debt$19,371 $8,917 
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
202520242023
Sales and other operating revenues$21,986 $18,872 $19,578 
Costs and other deductions18,419 10,616 10,193 
Net income attributable to TCO2,496 5,779 6,569 
At December 31
20252024
Current assets$6,052 $4,753 
Other assets49,993 58,057 
Current liabilities5,538 3,203 
Other liabilities8,663 12,459 
Total TCO net equity$41,844 $47,148 
Note 8
Restructuring and Reorganization Costs
The following table summarizes the accrued severance liability on the Consolidated Balance Sheet. The balance is expected to be substantially settled by the end of 2026.
Amounts Before Tax
Balance at January 1, 2025$990 
Accruals/Adjustments191 
Payments(498)
Balance at December 31, 2025$683 
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Note 9
Fair Value Measurements
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, 2025.
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, if applicable. 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 The company did not have any individually material impairments of long lived assets measured at fair value on a nonrecurring basis in 2025 or 2024.
Investments and Advances The company did not have any material impairments of investments and advances measured at fair value on a nonrecurring basis to report in 2025 or 2024.
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, 2025 and 2024.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
At December 31, 2025At December 31, 2024
TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3
Marketable securities$— $— $— $— $— $— $— $— 
Derivatives - not designated254 228 26 — 137 127 10 — 
Derivatives - designated10 10 — — — — — — 
Total assets at fair value$264 $238 $26 $— $137 $127 $10 $— 
Derivatives - not designated68 15 53 — 136 47 89 — 
Derivatives - designated— — — — 17 17 — — 
Total liabilities at fair value$68 $15 $53 $— $153 $64 $89 $— 
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
At December 31At December 31
Before-Tax LossBefore-Tax Loss
TotalLevel 1Level 2Level 3Year 2025TotalLevel 1Level 2Level 3Year 2024
Properties, plant and equipment, net (held and used)$6 $— $— $6 $133 $324 $— $— $324 $226 
Properties, plant and equipment, net (held for sale)— — — — — 616 — 616 — 274 
Investments and advances47 — 44 3 35 36 — 36 — 289 
Total nonrecurring assets at fair value$53 $— $44 $9 $168 $976 $— $652 $324 $789 
At year-end 2025, the company had assets measured at fair value Level 3 using unobservable inputs of $9. The carrying value of these assets were written down to fair value primarily based on estimates derived from discounted cash flow models. Cash flows were determined using estimates of future production, an outlook of future price based on published prices and a discount rate believed to be consistent with those used by principal market participants.
Fair value measurements related to assets and liabilities acquired in the Hess Corporation (Hess) acquisition are disclosed in Note 29 - Acquisition of Hess Corporation.
Assets and Liabilities Not Required to Be Measured at Fair Value The company holds cash equivalents in U.S. 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 $6,293 and $6,781 at
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December 31, 2025, and December 31, 2024, respectively. The fair values of cash and cash equivalents are classified as Level 1 and reflect the cash that would have been received if the instruments were settled at December 31, 2025.
“Cash and cash equivalents” do not include investments with a carrying/fair value of $992 and $1,481 at December 31, 2025, and December 31, 2024, respectively. At December 31, 2025, these investments are classified as Level 1 and include restricted funds mainly related to certain upstream decommissioning activities.
Long-term debt, excluding finance lease liabilities, of $28,532 and $10,810 at December 31, 2025, and December 31, 2024, respectively, had estimated fair values of $28,610 and $9,791, respectively. Long-term debt primarily includes corporate issued bonds. At December 31, 2025, the fair value of corporate bonds is $24,300 and classified as Level 1 and the fair value of other long-term debt classified as Level 2 is $4,310.
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, 2025 and 2024, 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, 2025, 2024 and 2023, 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 ContractBalance Sheet Classification20252024
CommodityAccounts and notes receivable$191 $122 
Commodity
Long-term receivables, net
73 15 
Total assets at fair value$264 $137 
CommodityAccounts payable$60 $127 
Commodity
Deferred credits and other noncurrent obligations
8 26 
Total liabilities at fair value$68 $153 
Consolidated Statement of Income: The Effect of Derivatives
Gain/(Loss)
Year ended December 31
Type of ContractStatement of Income Classification202520242023
CommoditySales and other operating revenues$(102)$(57)$(304)
Commodity
Purchased crude oil and products
44 28 (154)
CommodityOther income (loss)(7)6 (47)
$(65)$(23)$(505)
The amount reclassified from AOCL to “Sales and other operating revenues” from designated hedges was a net loss of $27 in 2025, compared with a net loss of $25 in the prior year. At December 31, 2025, before-tax deferred gains in AOCL
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related to outstanding crude oil price hedging contracts were $10, all of which is expected to be reclassified into earnings during the next 12 months as the hedged crude oil sales are recognized in earnings.
The table below represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated Balance Sheet at December 31, 2025 and 2024.
Consolidated Balance Sheet: The Effect of Netting Derivative Assets and Liabilities
 Gross Amounts RecognizedGross Amounts OffsetNet Amounts Presented Gross Amounts Not OffsetNet Amounts
At December 31, 2025
Derivative Assets - not designated$2,525 $2,271 $254 $1 $253 
Derivative Assets - designated$11 $1 $10 $— $10 
Derivative Liabilities - not designated$2,339 $2,271 $68 $3 $65 
Derivative Liabilities - designated$1 $1 $— $— $— 
At December 31, 2024
Derivative Assets - not designated$1,895 $1,758 $137 $3 $134 
Derivative Assets - designated$— $— $— $— $— 
Derivative Liabilities - not designated$1,894 $1,758 $136 $2 $134 
Derivative Liabilities - designated$17 $— $17 $— $17 
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, 2025, the company classified $25 of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. These assets are associated with downstream operations that are anticipated to be sold in the next 12 months. The revenues and earnings contributions of these assets in 2025 were not material.
Note 12
Equity
Retained earnings at December 31, 2025 and 2024, included $32,062 and $35,349, respectively, for the company’s share of undistributed earnings of equity affiliates.
At December 31, 2025, about 93 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, 537,174 shares remain available for issuance from the 1,600,000 shares of the company’s common stock that were reserved for awards under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan.
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:
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Year ended December 31
202520242023
Basic EPS Calculation
Earnings available to common stockholders - Basic*
$12,299 $17,661 $21,369 
Weighted-average number of common shares outstanding1,849 1,810 1,873 
Add: Deferred awards held as stock units
— — — 
Total weighted-average number of common shares outstanding1,849 1,810 1,873 
Earnings per share of common stock - Basic$6.65 $9.76 $11.41 
Diluted EPS Calculation
Earnings available to common stockholders - Diluted*
$12,299 $17,661 $21,369 
Weighted-average number of common shares outstanding1,849 1,810 1,873 
Add: Deferred awards held as stock units
— — — 
Add: Dilutive effect of employee stock-based awards
7 7 7 
Total weighted-average number of common shares outstanding1,856 1,817 1,880 
Earnings per share of common stock - Diluted$6.63 $9.72 $11.36 
* 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 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), which is comprised of the company’s Executive Committee.
The segments represent components of the company that engage in activities from which revenues are earned and expenses are incurred. Each segment has discrete financial information available. The CODM regularly reviews the operating results of these segments to assess their performance and make decisions about resources to be allocated to the segments. The company's primary country of operation is the United States of America, its country of domicile, while other components of the company's operations are reported as “International” (outside the United States).
Segment Sales and Other Operating Revenues Products are transferred between operating segments at internal product values that approximate market prices. Revenues for the upstream segment are derived primarily from the production and sale of crude oil, natural gas and NGLs, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the manufacture and sale of fuel and lubricant additives, renewable fuels, and the transportation and trading of refined products and crude oil. “All Other” activities include revenues from insurance operations, real estate activities and technology companies.
Segment Expenses Purchased crude oil and products, operating and selling, general and administrative (SG&A) expense, and depreciation, depletion and amortization are the company’s significant segment expenses. Operating and SG&A expenses include transportation, employee costs, service and fees, fuel and utilities, materials and supplies, SG&A expenses and other components of net periodic benefit costs. Other costs and deductions primarily represent taxes other than on income, exploration expense and interest and debt expenses.
Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the
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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.”
Segmented income statements for the years ended December 31, 2025, 2024 and 2023 are presented below:
UpstreamDownstreamSegment TotalAll OtherTotal
Year Ended December 31, 2025U.S.Int'l.U.S.Int'l.
Sales and other operating revenues before elimination$45,518 $42,861 $72,485 $69,925 $230,789 $581 $231,370 
Intersegment revenue elimination(25,910)(9,017)(7,154)(4,380)(46,461)(477)(46,938)
Sales and Other Operating Revenues19,608 33,844 65,331 65,545 184,328 104 184,432 
Income (loss) from equity affiliates(36)2,235 448 362 3,009 (9)3,000 
Other income (loss)1
433 466 134 17 1,050 549 1,599 
Total Revenues and Other Income20,005 36,545 65,913 65,924 188,387 644 189,031 
Intersegment product transfers2
23,717 2,812 (25,488)(896)145 (145)— 
Less expenses:
Purchased crude oil and products14,505 11,223 28,267 54,219 108,214 — 108,214 
Operating and SG&A expenses10,180 5,657 8,849 5,850 30,536 2,908 33,444 
Depreciation, depletion and amortization9,694 8,751 1,100 304 19,849 283 20,132 
Other costs and deductions3
1,663 1,420 649 2,408 6,140 1,358 7,498 
Total Costs and Other Deductions36,042 27,051 38,865 62,781 164,739 4,549 169,288 
Income Tax Expense (Benefit)1,750 5,290 185 538 7,763 (505)7,258 
Less: Net income (loss) attributable to non-controlling interests115 9 — 62 186 — 186 
Net Income (Loss) Attributable to Chevron Corporation$5,815 $7,007 $1,375 $1,647 $15,844 $(3,545)$12,299 
Values have been adjusted for eliminations, unless otherwise specified.
1 Includes interest income of $257 in “All Other.”
2 Valuation of product transfers between operating segments.
3 Includes interest expense of $1,096 in “All Other.”

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UpstreamDownstreamSegment TotalAll OtherTotal
Year ended December 31, 2024
U.S.Int'l.U.S.Int'l.
Sales and other operating revenues before elimination$44,302 $43,466 $80,417 $77,430 $245,615 $617 $246,232 
Intersegment revenue elimination(29,662)(11,258)(9,745)(1,668)(52,333)(485)(52,818)
Sales and Other Operating Revenues14,640 32,208 70,672 75,762 193,282 132 193,414 
Income (loss) from equity affiliates(62)3,642 1,010 10 4,600 (4)4,596 
Other income (loss)1
346 3,460 358 96 4,260 522 4,782 
Total Revenues and Other Income14,924 39,310 72,040 75,868 202,142 650 202,792 
Intersegment product transfers2
25,305 4,190 (26,845)(2,833)(183)183 — 
Less expenses:
Purchased crude oil and products13,326 9,445 33,514 62,921 119,206 — 119,206 
Operating and SG&A expenses7,708 6,412 9,425 6,034 29,579 2,914 32,493 
Depreciation, depletion and amortization7,562 7,935 1,091 360 16,948 334 17,282 
Other costs and deductions3
1,805 1,156 550 2,071 5,582 723 6,305 
Total Costs and Other Deductions30,401 24,948 44,580 71,386 171,315 3,971 175,286 
Income Tax Expense (Benefit)2,198 7,548 84 397 10,227 (470)9,757 
Less: Net income (loss) attributable to non-controlling interests28 4 — 56 88 — 88 
Net Income (Loss) Attributable to Chevron Corporation$7,602 $11,000 $531 $1,196 $20,329 $(2,668)$17,661 
Values have been adjusted for eliminations, unless otherwise specified.
1 Includes interest income of $296 in “All Other.”
2 Valuation of product transfers between operating segments.
3 Includes interest expense of $539 in “All Other.”
UpstreamDownstreamSegment TotalAll OtherTotal
Year Ended December 31, 2023U.S.Int'l.U.S.Int'l.
Sales and other operating revenues before elimination$40,115 $43,805 $83,567 $78,058 $245,545 $597 $246,142 
Intersegment revenue elimination(26,307)(11,871)(8,793)(1,794)(48,765)(464)(49,229)
Sales and Other Operating Revenues13,808 31,934 74,774 76,264 196,780 133 196,913 
Income (loss) from equity affiliates(387)4,272 736 519 5,140 (9)5,131 
Other income (loss)1
(2,536)776 444 39 (1,277)182 (1,095)
Total Revenues and Other Income10,885 36,982 75,954 76,822 200,643 306 200,949 
Intersegment product transfers2
23,665 4,274 (23,887)(4,184)(132)132 — 
Less expenses:
Purchased crude oil and products13,019 7,270 37,176 61,731 119,196 — 119,196 
Operating and SG&A expenses6,879 5,837 8,432 6,058 27,206 2,034 29,240 
Depreciation, depletion and amortization7,666 8,109 931 301 17,007 319 17,326 
Other costs and deductions3
1,676 1,010 515 1,782 4,983 620 5,603 
Total Costs and Other Deductions29,240 22,226 47,054 69,872 168,392 2,973 171,365 
Income Tax Expense (Benefit)1,141 5,733 1,109 519 8,502 (329)8,173 
Less: Net income (loss) attributable to non-controlling interests21 7 — 14 42 — 42 
Net Income (Loss) Attributable to Chevron Corporation$4,148 $13,290 $3,904 $2,233 $23,575 $(2,206)$21,369 
Values have been adjusted for eliminations, unless otherwise specified.
1 Includes interest income of $491 in “All Other.”
2 Valuation of product transfers between operating segments.
3 Includes interest expense of $432 in “All Other.”

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Segment Assets Segment assets do not include intercompany investments or receivables. Assets at year-end 2025 and 2024 are as follows:
At December 31
20252024
Upstream
United States$84,559 $60,914 
International168,200 123,343 
Goodwill4,216 4,226 
Total Upstream256,975 188,483 
Downstream
United States33,745 34,253 
International21,146 22,165 
Goodwill352 352 
Total Downstream55,243 56,770 
Total Segment Assets312,218 245,253 
All Other
United States10,396 8,382 
International1,398 3,303 
Total All Other11,794 11,685 
Total Assets – United States128,700 103,549 
Total Assets – International190,744 148,811 
Goodwill4,568 4,578 
Total Assets$324,012 $256,938 
Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 15 Investments and Advances. Information related to properties, plant and equipment by segment is contained in Note 18 Properties, Plant and Equipment. Information related to unusual items is contained in Note 27 Other Financial Information.

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 AdvancesEquity in Earnings
At December 31Year ended December 31
20252024202520242023
Upstream
Tengizchevroil$23,830 $27,368 $1,556 $3,033 $3,375 
Caspian Pipeline Consortium645 719 143 180 158 
Angola LNG Limited1,588 1,665 473 405 513 
Other1,681 1,716 27 (38)(161)
Total Upstream27,744 31,468 2,199 3,580 3,885 
Downstream
Chevron Phillips Chemical Company LLC8,985 8,571 352 903 608 
GS Caltex Corporation4,403 4,144 278 58 437 
Other1,895 2,432 180 60 210 
Total Downstream15,283 15,147 810 1,021 1,255 
All Other
Other10 3 (9)(5)(9)
Total equity method$43,037 $46,618 $3,000 $4,596 $5,131 
Other non-equity method investments830 820 
Total investments and advances$43,867 $47,438 
Total United States$11,866 $11,960 $404 $944 $340 
Total International$32,001 $35,478 $2,596 $3,652 $4,791 
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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 TCO, which operates the Tengiz and Korolev crude oil fields in Kazakhstan. At December 31, 2025, the company’s carrying value of its investment in TCO was about $62 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 Wellhead Pressure Management Project (WPMP) and Future Growth Project (FGP) with a principal balance of $3,500.
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 $969 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 $12,563, $13,850 and $13,623 with affiliated companies for 2025, 2024 and 2023, respectively. “Purchased crude oil and products” includes $7,322, $6,547 and $7,404 with affiliated companies for 2025, 2024 and 2023, respectively.
“Accounts and notes receivable” on the Consolidated Balance Sheet includes $913 and $1,258 due from affiliated companies at December 31, 2025 and 2024, respectively. “Accounts payable” includes $764 and $556 due to affiliated companies at December 31, 2025 and 2024, respectively.
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 $4,077, $4,731 and $4,494 at December 31, 2025, 2024 and 2023, respectively.
AffiliatesChevron Share
Year ended December 31202520242023202520242023
Total revenues$49,666 $46,081 $49,306 $23,638 $21,765 $23,217 
Income before income tax expense*
8,320 13,127 15,304 3,718 6,088 7,209 
Net income attributable to affiliates6,659 10,253 11,618 2,988 4,802 5,485 
At December 31
Current assets$21,846 $21,697 $22,772 $9,233 $9,323 $10,110 
Noncurrent assets94,291 104,396 105,965 44,948 49,435 48,753 
Current liabilities14,094 12,906 14,085 4,586 5,084 6,698 
Noncurrent liabilities18,427 22,651 23,797 7,009 7,278 6,342 
Total affiliates’ net equity$83,616 $90,536 $90,855 $42,586 $46,396 $45,823 
* 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 2025 was $1,661, with Chevron’s share being $730.
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Note 16
Litigation
Climate Change
Governmental and other plaintiffs in various jurisdictions across the United States have brought lawsuits against fossil fuel producing companies, including Chevron entities, purporting to seek legal and equitable relief to address alleged impacts of climate change. Chevron entities are or were among the codefendants in 34 separate lawsuits filed by various U.S. cities and counties, seven U.S. states, the District of Columbia, the Commonwealth of Puerto Rico, two Native American tribes, and a trade group in both federal and state courts.3 The lawsuits have asserted various causes of action, including public nuisance, private nuisance, failure to warn, fraud, conspiracy to commit fraud, design defect, product defect, trespass, negligence, impairment of public trust, equitable relief for pollution, impairment and destruction of natural resources, unjust enrichment, violations of consumer and environmental protection statutes, violations of unfair competition statutes, violations of a federal antitrust statute, and violations of federal and state RICO statutes, based upon, among other things, the company’s production of oil and gas products and alleged misrepresentations or omissions relating to climate change risks associated with those products. Further such lawsuits are likely to be brought by other parties. While defendants have sought to remove cases filed in state court to federal court, most of those cases have been remanded to state court and the U.S. Supreme Court has denied petitions for certiorari on the question of whether federal courts have jurisdiction over those cases. The U.S. Supreme Court has also denied certiorari to review a decision from the Hawaii Supreme Court allowing claims brought by the City and County of Honolulu to proceed past the pleadings. On February 23, 2026, the U.S. Supreme Court granted certiorari in Suncor Energy (U.S.A.) Inc., et. al. v. County Commissioners of Boulder County, et. al. (No. 25‑170), a case in which no Chevron entity is a party, to address the questions of whether federal law precludes state‑law claims seeking relief for injuries allegedly caused by the effects of interstate and international greenhouse gas emissions on the global climate and whether the U.S. Supreme Court has statutory and Article III jurisdiction to hear that case. The unprecedented legal theories set forth in these climate lawsuits include claims for damages (both compensatory and punitive), injunctive and other forms of equitable relief, including without limitation abatement, contribution to abatement funds, disgorgement of profits and equitable relief for pollution, impairment and destruction of natural resources, civil penalties and liability for fees and costs of suits. Due to the unprecedented nature of the suits, the company is unable to estimate any range of possible liability, but given the uncertainty of litigation there can be no assurance that the cases will not have a material adverse effect on the company’s results of operations and financial condition. Management believes that these lawsuits are legally and factually meritless and detract from constructive efforts to address the important policy issues presented by climate change and will vigorously defend against such lawsuits.
3 The cases are: Municipality of Bayamon et al. v. Exxon Mobil Corp., et al., No. 22-cv-1550 (D.P.R.) (dismissed on the merits; Plaintiffs’ appeal pending); City of Annapolis v. BP P.L.C., et al., No. C-02-CV-21-000250 (Md. Cir. Ct.) (dismissed on the merits; Plaintiff’s appeal pending); Anne Arundel County v. BP P.L.C., et al., No. C-02-CV-21-000565 (Md. Cir. Ct.) (dismissed on the merits; Plaintiff’s appeal pending); Mayor and City Council of Baltimore v. BP P.L.C., et al., No. 24-C-18-004219 (Md. Cir. Ct.) (dismissed on the merits; Plaintiff’s appeal pending); People ex rel. Bonta v. Exxon Mobil Corp., et al., No. CGC-23-609134 (Cal. Super. Ct.); Bucks County v. BP P.L.C., et al., No. 2024-01836 (Pa. Ct. Com. Pl.) (dismissed on the merits; Plaintiff’s appeal pending); City of Charleston v. Brabham Oil Co., et al., No. 2020-CP-10-3975 (S.C. Ct. of Com. Pl.) (dismissed on the merits and for lack of personal jurisdiction); District of Columbia v. Exxon Mobil Corp., et al., No. 2020-CA-002892-B (D.C. Super. Ct.); Delaware ex rel. Jennings v. BP America Inc., et al., C.A. No. N20C-09-097 (Del. Super. Ct.) (dismissed on the merits in substantial part); 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.) (dismissed on the merits; Plaintiff’s appeal pending); City of Oakland v. BP P.L.C., et al., No. RG17875889 (Cal. Super. Ct.); Platkin, et al. v. Exxon Mobil Corp., et al., No. MER-L-001797-22 (N.J. Super. Ct.) (dismissed on the merits; Plaintiff’s appeal pending); Estado Libre Asociado de Puerto Rico [Commonwealth of Puerto Rico] v. Exxon Mobil Corp., et al., No. SJ2024CV06512 (Tribunal de Primera Instancia, Estado Libre Asociado de P.R.) [P.R. Ct. of First Instance, Commonwealth of P.R.] (voluntarily dismissed); City of New York v. Chevron Corp., et al., No. 18-cv-00182 (S.D.N.Y.) (dismissed on the merits); Pacific Coast Federation of Fishermen’s Associations, Inc. v. Chevron Corp., et al., No. CGC-18-571285 (Cal. Super. Ct.) (voluntarily dismissed); State of Rhode Island v. Chevron Corp., et al., C.A. No. PC-2018-4716 (R.I. Super. Ct.); City of Richmond v. Chevron Corp., et al., No. C18-00055 (Cal. Super. Ct.); City of San Francisco v. BP P.L.C., et al., No. CGC-17-561370 (Cal. Super. Ct.); County of San Mateo v. Chevron Corp., et al., No. 17-CIV-03222 (Cal. Super. Ct.); City of Santa Cruz v. Chevron Corp., et al., No. 17-CV-03243 (Cal. Super. Ct.); County of Santa Cruz v. Chevron Corp., et al., No. 17-CV-03242 (Cal. Super. Ct.); Shoalwater Bay Indian Tribe v. Exxon Mobil Corp., et al., No. 23-2-25215-2-SEA (Wash. Super. Ct.); City of Chicago v. BP P.L.C., et al., No. 2024CH01024 (Ill. Cir. Ct.); Maine v. BP P.L.C. et al., No. PORSC-CV-24-442 (Me. Super. Ct.); State of Hawaii v. BP P.L.C., et al., 1CCV-25-0000717 (Haw. Cir. Ct.); The People of the State of Michigan v. BP p.l.c., et.al., Civ. No. 26-cv-00254 (W.D. Mich.).
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Louisiana
Seven coastal parishes and the State of Louisiana have filed lawsuits in Louisiana against numerous oil and gas companies seeking remediation damages for coastal erosion in or near oil fields located within Louisiana’s coastal zone under Louisiana’s State and Local Coastal Resources Management Act (SLCRMA). Chevron entities are defendants in 36 of these cases.4 The lawsuits allege that the defendants’ historical operations were conducted without necessary permits or failed to comply with permits obtained and seek remediation damages and other relief, including the costs of restoring coastal wetlands allegedly impacted by oil field operations. Further such proceedings may be brought by other parties. Most of these cases have been remanded to Louisiana state court. In April 2025, a jury in a Louisiana state court awarded Plaquemines Parish $744.6 million in a trial against Chevron entities (i.e., Plaquemines Parish v. Rozel Operating Co., et al. (“Rozel”)). The state court judge continued a hearing on Plaquemines Parish’s motion for entry of judgment on the Rozel trial verdict and stayed that case pending a decision by the United States Supreme Court on whether certain cases belong in federal, rather than state, court. The United States Supreme Court heard oral argument on the federal jurisdiction question on January 12, 2026.
The company does not concede the viability of the Rozel jury verdict and plans to appeal any judgment based on that verdict. The jury’s decision was unique to the facts and circumstances of the case and may not be representative of future outcomes for other claims brought against Chevron entities under the SLCRMA. In accordance with guidance on the evaluation of loss contingencies, the company has recorded an accrual of $131 million, which the company believes to be a reasonably estimable loss in light of the available defenses. It is reasonably possible that the estimate of the loss could change based on the progression of the case, including the appeals process. However, because of the uncertainties associated with ongoing litigation, we are unable to estimate the range of reasonably possible loss that may be attributable to liabilities, if any, in excess of the amount accrued. While the company believes the jury verdict is not legally or factually supported and intends to appeal and vigorously pursue post-judgment remedies, there can be no assurances that such defense efforts will be successful. To the extent the company is required to pay remediation damages in these cases, it may have a material adverse effect on our financial position and results of operations. Management believes that the claims in these lawsuits lack legal and factual merit and will continue to vigorously defend against such proceedings.



4 The cases are: Jefferson Parish v. Atlantic Richfield Company, et al., No. 732-768 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Chevron U.S.A. Holdings, Inc., et al., No. 732-769 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Destin Operating Company, Inc., et al., No. 732-770 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Canlan Oil Company, et al., No. 732-771 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Anadarko E&P Onshore LLC, et al., No. 732-772 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. ExxonMobil Corporation, et al., No. 732-774 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Equitable Petroleum Corporation, et al., No. 732-775 (24th Jud. Dist. Ct., Jefferson Par.); Plaquemines Parish v. ConocoPhillips Co., et al., No. 60-982 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. HHE Energy Co., et al., No. 60-983 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Exchange Oil & Gas Corp., et al., No. 60-984 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. LLOG Exploration & Production Co., et al., No. 60-985 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Equitable Petroleum Corporation, et al., No. 60-986 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. June Energy, et al., No. 60-987 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Linder Oil Company, et al., No. 60-988 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Riverwood Production Company, et al., No. 60-989 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Helis Oil & Gas Company, et al., No. 60-990 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Northcoast Oil Company, et al., No. 60-992 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Goodrich Petroleum Company, L.L.C., et al., No. 60-994 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Devon Energy Production Company, L.P., et al., No. 60-995 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Rozel Operating Co., et al., No. 60-996 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Palm Energy Offshore, L.L.C., et al., No. 60-997 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Great Southern Oil & Gas Company, Inc., et al., No. 60-998 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Hilcorp Energy Company, et al., No. 60-999 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Apache Oil Corporation, et al., No. 61-000 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Campbell Energy Corporation, et al., No. 61-001 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. TotalPetrochemicals & Refining USA, Inc., et al., No. 61-002 (25th Jud. Dist. Ct., Plaquemines Par.); Cameron Parish v. Alpine Exploration Companies, Inc., et al., No. 10-19580 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Apache Corporation (of Delaware), et al., No. 10-19579 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Ballard Exploration Company, Inc., et al., No. 10-19574 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Bay Coquille, Inc., et al., No. 10-19581 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. BEPCO, LP, et al., No. 10-19572 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. BP America Production Company, et al., No. 10-19576 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Brammer Engineering, Inc., et al., No. 10-19573 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Burlington Resources, et al., No. 10-19575 (38th Jud. Dist. Ct., Cameron Par.); Stutes v. Gulfport Energy Corporation, et al., No. 102,146 (15th Jud. Dist. Ct., Vermilion Par.); St. Bernard Parish v. Atlantic Richfield, et al., No. 16-1228 (34th Jud. Dist. Ct. St., Bernard Par.).
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Note 17
Taxes
Income Taxes
Year ended December 31
202520242023
Income tax expense (benefit)
U.S. federal
Current$444 $854 $895 
Deferred885 748 666 
State and local
Current309 275 211 
Deferred(88)10 1 
Total United States1,550 1,887 1,773 
International
Current5,520 7,388 6,745 
Deferred188 482 (345)
Total International5,708 7,870 6,400 
Total income tax expense (benefit)$7,258 $9,757 $8,173 

For 2025, ASU 2023-09 requires an expanded view of the rate reconciliation as well as a summary of income taxes paid for material jurisdictions. Chevron has elected a prospective presentation. The tables below represent the new standard for 2025 and revert to prior guidance for comparable years.
























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The reconciliation between the U.S. statutory federal income tax rate and the company’s effective income tax rate for the year ended December 31, 2025, in accordance with ASU 2023-09 guidance, is detailed in the following table:
Taxes On IncomeYear ended December 31
2025
$%
Income (loss) before income taxes
United States$5,979 
International13,764 
Total income (loss) before income taxes19,743 
U.S. Federal statutory income tax4,146 21.0 %
State and local income tax, net of federal income tax effect1
142 0.7 %
Foreign tax effects
Australia
Statutory tax rate difference 334 1.7 %
Additional non-U.S. income taxes2
287 1.5 %
Foreign exchange356 1.8 %
Other14 0.1 %
Kazakhstan
Additional non-U.S. income taxes2
624 3.2 %
Equity affiliate accounting effect3
(353)(1.8)%
Other128 0.6 %
Nigeria - primarily additional non-U.S. income taxes368 1.9 %
Saudi Arabia - primarily statutory tax rate difference583 3.0 %
Other foreign jurisdictions345 1.7 %
Total foreign tax effects2,686 13.6 %
Effect of cross-border tax laws - primarily surplus foreign tax credits4
(2,477)(12.5)%
Changes in valuation allowances4
2,773 14.0 %
Other adjustments5
(12)(0.1)%
Total income tax expense and effective tax rate$7,258 36.8 %
1 State taxes in California and New Mexico make up the majority (greater than 50%) of the tax effect in this category.
2 Includes items such as withholding taxes and oil profit taxes.
3 After‑tax equity affiliate income is included in pretax earnings, which results in a negative adjustment in the rate reconciliation.
4 Surplus foreign tax credits and their related valuation allowances are shown gross but largely offset.
5 Tax credits, nontaxable and nondeductible items and changes in unrecognized tax benefits were all immaterial and included in other adjustments.

The reconciliation between the U.S. statutory federal income tax rate and the company’s effective income tax rate for the years ended December 31, 2024 and 2023, as previously reported, is detailed in the following table:
Year ended December 31
20242023
Income (loss) before income taxes
 United States$8,056$8,565
 International19,45021,019
Total income (loss) before income taxes27,50629,584
Theoretical tax (at U.S. statutory rate of 21%)5,7766,213
Equity affiliate accounting effect(845)(1,072)
Effect of income taxes from international operations4,7423,001
State and local taxes on income, net of U.S. federal income tax benefit
214252
Prior year tax adjustments, claims and settlements1
(30)(32)
Tax credits(28)(20)
Other U.S.1, 2
(72)(169)
Total income tax expense (benefit)$9,757$8,173
Effective income tax rate35.5 %27.6 %
1 Includes one-time tax costs (benefits) associated with changes in uncertain tax positions.
2 Includes one-time tax costs (benefits) associated with changes in valuation allowances (2024 - $(12); 2023 - $(84)).
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The 2025 decrease in income tax expense of $2,499 was driven by the decrease in total income before tax of $7,763, along with the absence of the tax impacts from the prior year asset sales in Canada. The change in the company’s effective tax rate from 35.5 percent in 2024 to 36.8 percent in 2025 was primarily a result of unfavorable foreign exchange impacts.
The reconciliation of income taxes paid in the U.S. and other significant international jurisdictions for the year ended December 31, 2025, is detailed in the following table:
Income Taxes PaidYear ended December 31
2025
U.S. Federal1
$143 
U.S. state and local224 
All other jurisdictions
    Australia1,592 
    Canada2
1,782 
    Guyana3
406 
    Kazakhstan4
755 
    Nigeria593 
    Saudi Arabia611 
    All others1,198 
Income taxes paid$7,304 
1 U.S. Federal taxes paid are affected by accelerated depreciation and the immediate expensing of research and development costs provided by the One Big Beautiful Bill Act of 2025, as well as net operating loss carryforwards, tax credits from biofuels production and other lower carbon activities, and prior year overpayments.
2 Includes taxes associated with the Canada asset sale in 2024 that were paid in 2025.
3 Taxes settled with the government in the form of crude oil barrels.
4 Includes withholding tax and excludes taxes paid by the company’s equity affiliate, TCO.
The company records its deferred taxes on a tax-jurisdiction basis. The reported deferred tax balances are composed of the following:
At December 31
20252024
Deferred tax liabilities
Properties, plant and equipment$34,149 $20,648 
Investments and other6,668 5,254 
Total deferred tax liabilities40,817 25,902 
Deferred tax assets
Foreign tax credits(18,932)(15,261)
Asset retirement obligations/environmental reserves(4,993)(4,220)
Employee benefits(1,924)(2,050)
Tax credits(430)(292)
Tax loss carryforwards(7,141)(3,034)
Other accrued liabilities(909)(1,137)
Operating leases (1,886)(1,352)
Miscellaneous(4,311)(4,248)
Total deferred tax assets(40,526)(31,594)
Deferred tax assets valuation allowance26,861 21,313 
Total deferred income taxes, net$27,152 $15,621 
Deferred tax liabilities increased by $14,915 from year-end 2024, driven by the acquisition of Hess. Deferred tax assets increased by $8,932 from year-end 2024, primarily related to increases in foreign tax credits and tax loss carryforwards from the acquisition of Hess.
The overall valuation allowance, which increased by $5,548 from year-end 2024, relates to deferred tax assets for U.S. 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 2025, the company had gross tax loss carryforwards of approximately $29,161 and tax credit carryforwards of approximately $430, 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 2026 through 2044. U.S. foreign tax credit carryforwards of $18,932 will expire between 2026 and 2035.
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At December 31, 2025 and 2024, deferred taxes were classified on the Consolidated Balance Sheet as follows:
At December 31
20252024
Deferred charges and other assets$(2,862)$(3,516)
Noncurrent deferred income taxes30,014 19,137 
Total deferred income taxes, net$27,152 $15,621 
Income taxes, including U.S. state and foreign withholding taxes, are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely, or where no taxable temporary differences exist that are attributable to an investment in a foreign entity. The indefinite reinvestment assertion continues to apply for the purpose of determining deferred tax liabilities for U.S. state and foreign withholding tax purposes. It is not practicable to estimate the amount of state and foreign withholding taxes that might be payable on the possible remittance of earnings that are intended to be reinvested indefinitely. The company does not anticipate incurring significant additional taxes on remittances of earnings that are not indefinitely reinvested.
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, 2025, 2024 and 2023. The term “unrecognized tax benefits” in the accounting standards for income taxes refers to the differences between a tax position taken or expected to be taken in a tax return and the benefit measured and recognized in the financial statements. Interest and penalties are not included.
202520242023
Balance at January 1$4,852 $5,452 $5,323 
Foreign currency effects— — (27)
Additions based on tax positions taken in current year632 236 248 
Additions for tax positions taken in prior years
546 101 265 
Reductions based on tax positions taken in current year(29)(54)(104)
Reductions for tax positions taken in prior years
(3,390)(883)(251)
 Settlements with taxing authorities in current year — — (2)
Balance at December 31$2,611 $4,852 $5,452 
Approximately 81 percent of the $2,611 of unrecognized tax benefits at December 31, 2025, 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 2019 for the United States and 2007 for other major jurisdictions.
On the Consolidated Statement of Income, the company reports interest and penalties related to liabilities for uncertain tax positions as “Income Tax Expense (Benefit).” As of December 31, 2025, accrued expense of $306 for anticipated interest and penalties was included on the Consolidated Balance Sheet, compared with accrued expense of $268 as of year-end 2024. Income tax expense (benefit) associated with interest and penalties was $37, $40 and $124 in 2025, 2024 and 2023, respectively.
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Taxes Other Than on Income
Year ended December 31
202520242023
United States
Import duties and other levies$7 $8 $(9)
Property and other miscellaneous taxes
1,129 977 818 
Payroll taxes308 296 286 
Taxes on production816 842 801 
Total United States2,260 2,123 1,896 
International
Import duties and other levies121 90 72 
Property and other miscellaneous taxes
2,608 2,283 2,004 
Payroll taxes135 125 121 
Taxes on production106 95 127 
Total International2,970 2,593 2,324 
Total taxes other than on income$5,230 $4,716 $4,220 

Note 18
Properties, Plant and Equipment1
At December 31Year ended December 31
Gross Investment at CostNet Investment
Additions at Cost2
Depreciation Expense3
202520242023202520242023202520242023202520242023
Upstream
United States$154,579 $124,439 $117,955 $74,567 $52,428 $50,390 $31,835 $9,591 $20,408 $9,694 $7,562 $7,666 
International233,908 176,401 183,996 126,252 76,642 84,561 58,357 4,426 4,130 8,751 7,935 8,109 
Total Upstream388,487 300,840 301,951 200,819 129,070 134,951 90,192 14,017 24,538 18,445 15,497 15,775 
Downstream
United States33,398 32,336 31,192 13,718 13,667 13,521 646 1,217 1,623 1,100 1,091 931 
International8,509 8,331 8,401 2,883 2,946 3,122 249 245 237 304 360 301 
Total Downstream41,907 40,667 39,593 16,601 16,613 16,643 895 1,462 1,860 1,404 1,451 1,232 
All Other
United States4,401 4,304 4,390 2,243 2,082 1,991 439 355 311 273 328 313 
International160 122 147 66 34 34 42 7 15 10 6 6 
Total All Other4,561 4,426 4,537 2,309 2,116 2,025 481 362 326 283 334 319 
Total United States192,378 161,079 153,537 90,528 68,177 65,902 32,920 11,163 22,342 11,067 8,981 8,910 
Total International242,577 184,854 192,544 129,201 79,622 87,717 58,648 4,678 4,382 9,065 8,301 8,416 
Total$434,955 $345,933 $346,081 $219,729 $147,799 $153,619 $91,568 $15,841 $26,724 $20,132 $17,282 $17,326 
1Other than the United States, Guyana and Australia, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2025.Guyana had PP&E of $50,960 in 2025. Australia had PP&E of $36,761, $38,969 and $41,409 in 2025, 2024 and 2023, respectively. Gross Investment at Cost and Additions at Cost for 2025 each include $73,538 associated with the acquisition of Hess. Gross Investment at Cost and Additions at Cost for 2023 each include $10,487 associated with the PDC acquisition.
2Net of dry hole expense related to prior years’ expenditures of $33, $98 and $110 in 2025, 2024 and 2023, respectively.
3Depreciation expense includes accretion expense of $620, $586 and $593 in 2025, 2024 and 2023, respectively, and impairments and write-offs of $133, $500 and $2,180 in 2025, 2024 and 2023, respectively.
Note 19
Short-Term Debt
At December 31
20252024
Commercial paper$4,642 $5,386 
Notes payable to banks and others with originating terms of one year or less
96 131 
Current maturities of long-term debt2,345 4,012 
Current maturities of long-term finance leases
786 58 
Redeemable long-term obligations3,049 3,069 
Subtotal
10,918 12,656 
Reclassified to long-term debt(9,941)(8,250)
Total short-term debt$977 $4,406 
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Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date.
The company may periodically enter into interest rate swaps on a portion of its short-term debt. At December 31, 2025, the company had no interest rate swaps on short-term debt.
At December 31, 2025, the company had $11,400 in 364-day committed credit facilities with various major banks that enable the refinancing of short-term obligations. The credit facilities allow the company the option to convert outstanding short-term obligations into a term loan for a period of up to one year from the facilities termination date. This supports commercial paper borrowing and can also be used for general corporate purposes. The company’s practice has been to replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under these facilities would be unsecured indebtedness at interest rates based on the Secured Overnight Financing Rate (SOFR), or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under these facilities at December 31, 2025.
The company classified $9,941 and $8,250 of short-term debt as long-term at December 31, 2025 and 2024, respectively. Settlement of these obligations is not expected to require the use of working capital within one year, as the company had the intent and the ability, as evidenced by committed credit facilities, to continue refinancing them.
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Note 20
Long-Term Debt
Total long-term debt including finance lease liabilities at December 31, 2025, was $39,781. The company’s long-term debt outstanding at year-end 2025 and 2024 was as follows:
At December 31
20252024
Weighted Average Interest Rate (%)1
Range of Interest Rates (%)2
PrincipalPrincipal
Notes due 20262.9542,250 2,250 
Notes due 20273.594
1.018 - 8.000
5,000 2,000 
Notes due 20284.762
3.850 - 5.875
4,700 600 
Notes due 20295.872
3.250 - 7.875
1,567 500 
Notes due 20303.955
2.236 - 5.500
5,350 1,500 
Notes and Debentures due 20317.484
7.300 - 8.625
734 102 
Notes and Debentures due 20324.944
4.500 - 8.625
2,083 183 
Notes due 20337.125540 — 
Notes due 20354.909
4.850 - 4.980
1,650 — 
Notes due 20405.152
2.978 - 6.000
1,043 293 
Notes due 20415.696
5.600 - 6.000
1,646 397 
Notes due 20435.250330 330 
Notes due 20445.050222 222 
Notes due 20475.569
4.950 - 5.800
687 187 
Notes due 20494.200237 237 
Notes due 20502.763
2.343 - 3.078
1,750 1,750 
Notes due 20753.722154 — 
Debentures due 20977.25060 60 
Bank loans due 2026 to 20285.460
2.448 - 8.040
532 193 
Term loans and credit facility borrowings7.320
7.250 - 8.136
367 — 
Medium-term notes, maturing from 2033 to 20385.786
3.688 - 7.840
20 20 
Notes due 2025— 4,012 
Total including debt due within one year$30,922 14,836 
Debt due within one year(2,345)(4,012)
Fair market value adjustment for debt acquired in the Noble and Hess acquisitions649 529 
Reclassified from short-term debt9,941 8,250 
Unamortized discounts and debt issuance costs(45)(14)
Finance lease liabilities3
659 546 
Total long-term debt$39,781 $20,135 
1 Weighted-average interest rate at December 31, 2025.
2 Range of interest rates at December 31, 2025.
3 For details on finance lease liabilities, see Note 5 Lease Commitments.
    
Chevron has an automatic shelf registration statement that expires in November 2027. This registration statement is for an unspecified amount of nonconvertible debt securities issued or guaranteed by Chevron Corporation or CUSA.
Long-term debt excluding finance lease liabilities with a principal balance of $30,922 matures as follows: 2026 – $2,345; 2027 – $5,723; 2028 – $4,752; 2029 – $1,567; 2030 – $5,350; and after 2030 – $11,185.
See Note 9 Fair Value Measurements for information concerning the fair value of the company’s long-term debt.
Note 21
Accounting for Suspended Exploratory Wells
The company continues to capitalize exploratory well costs after the completion of drilling when the well has found a sufficient quantity of reserves to justify completion as a producing well, and the business unit is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met or if the company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense.
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The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended December 31, 2025:
202520242023
Beginning balance at January 1$1,662 $1,648 $1,627 
Additions to capitalized exploratory well costs pending the determination of proved reserves
150 14 88 
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
— — — 
Capitalized exploratory well costs charged to expense(1)— (67)
Other reductions*(52)— — 
Ending balance at December 31$1,759 $1,662 $1,648 
*Represents property sales.
The following table provides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:
At December 31
202520242023
Exploratory well costs capitalized for a period of one year or less
$148 $17 $78 
Exploratory well costs capitalized for a period greater than one year
1,611 1,645 1,570 
Balance at December 31$1,759 $1,662 $1,648 
Number of projects with exploratory well costs that have been capitalized for a period greater than one year*
15 14 13 
*Certain projects have multiple wells or fields or both.
Of the $1,611 of exploratory well costs capitalized for more than one year at December 31, 2025, $848 is related to nine projects that had drilling activities underway or firmly planned for the near future. The $763 balance is related to six projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not underway or firmly planned for the near future. Additional drilling was not deemed necessary because the presence of hydrocarbons had already been established, and other activities were in process to enable a future decision on project development.
The projects for the $763 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability: (a) $348 (four projects) – undergoing front-end engineering and design with final investment decision expected within four years; (b) $415 (two projects) – development alternatives under review. While progress was being made on all 15 projects, the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations associated with the projects. More than half of these decisions are expected to occur in the next five years.
The $1,611 of suspended well costs capitalized for a period greater than one year as of December 31, 2025, represents 73 exploratory wells in 15 projects. The tables below contain the aging of these costs on a well and project basis:
Aging based on drilling completion date of individual wells:AmountNumber of wells
2000-2009$263 14 
2010-20141,068 46 
2015-2024280 13 
Total$1,611 73 
Aging based on drilling completion date of last suspended well in project:AmountNumber of projects
2008-2012$292 2 
2013-20161,030 6 
2017-2025289 7 
Total$1,611 15 
Note 22
Stock Options and Other Share-Based Compensation
Compensation expense for stock options for 2025, 2024 and 2023 was $73 ($56 after tax), $90 ($68 after tax) and $85 ($65 after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance shares and restricted stock units for 2025, 2024 and 2023 was $399 ($303 after tax), $510 ($388 after tax) and $(100) ($(76) after tax), respectively. No significant stock-based compensation cost was capitalized at December 31, 2025, or December 31, 2024.
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Cash received in payment for option exercises under all share-based payment arrangements for 2025, 2024 and 2023 was $374, $356 and $263, respectively. Actual tax benefits realized for the tax deductions from option exercises were $29, $24 and $20 for 2025, 2024 and 2023, respectively.
Cash paid to settle performance shares, restricted stock units and stock appreciation rights was $405, $395 and $566 for 2025, 2024 and 2023, 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, share-settled performance shares and other share-settled awards that do not require full payment in cash or property for shares underlying such awards by the award recipient. Contractual terms of equity awards vary between three years for the performance shares and special restricted stock units with cliff vesting at the end of the contractual period, five years for standard restricted stock units with cliff vesting at the end of the contractual period and 10 years for the stock options and stock appreciation rights with graded vesting provisions by which one-third of each award vests around each of the first, second and third anniversaries of the date of grant. Commencing for grants issued in January 2023 and after, standard restricted stock units vest ratably on an annual basis over a 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 2025, 2024 and 2023 were measured on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions:
Year ended December 31
202520242023
Expected term in years1
6.56.56.4
Volatility2
33.0 %33.0 %32.5 %
Risk-free interest rate based on zero coupon U.S. treasury note
4.34 %3.98 %3.43 %
Dividend yield4.5 %4.1 %3.5 %
Weighted-average fair value per option granted$37.60 $38.00 $45.82 
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 2025 is presented below:
Shares (Thousands)Weighted-Average
 Exercise Price		Averaged Remaining Contractual Term (Years)Aggregate Intrinsic Value
Outstanding at January 1, 202523,168 $122.62 
Granted3,879 $130.05 
Exercised(3,801)$98.52 
Forfeited(1,082)$209.13 
Outstanding at December 31, 202522,164 $123.78 5.10$704 
Exercisable at December 31, 202518,050 $116.44 4.32$703 
The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2025, 2024 and 2023 was $227, $190 and $167, respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.
As of December 31, 2025, there was $379 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 1.7 years.
At January 1, 2025, the number of LTIP performance shares outstanding was equivalent to 3,859,439 shares. During 2025, 1,502,047 performance shares were granted, 1,379,521 shares vested with cash proceeds distributed to recipients and 347,810 shares were forfeited. At December 31, 2025, there were 3,634,155 performance shares outstanding, of which 1,681,470 are payable in cash and 1,952,685 are payable in shares. The fair value of the liability recorded for these instruments payable in cash was $65 and was measured largely using the Monte Carlo simulation method.
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At January 1, 2025, the number of restricted stock units outstanding was equivalent to 5,399,798 shares. During 2025, 1,905,275 restricted stock units were granted, 1,449,539 units vested with cash proceeds distributed to recipients and 424,979 units were forfeited. At December 31, 2025, there were 5,430,555 restricted stock units outstanding, of which 2,711,265 are payable in cash and 2,719,290 are payable in shares. The fair value of the liability recorded for the vested portion of these instruments payable in cash was $342, valued at the stock price as of December 31, 2025. In addition, outstanding stock appreciation rights that were granted under the LTIP totaled 412,784 equivalent shares as of December 31, 2025. The fair value of the liability recorded for the vested portion of these instruments was $18.
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 post-employment 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 2025 and 2024 follows:
Pension Benefits
20252024Other Benefits
U.S.Int’l.U.S.Int’l.20252024
Change in Benefit Obligation
Benefit obligation at January 1$10,140 $3,289 $10,392 $3,605 $1,880 $2,017 
Service cost365 55 357 54 30 34 
Interest cost505 207 465 191 99 98 
Plan participants’ contributions— 2 — 2 57 54 
Plan amendments— 6 — 18 (29)30 
Actuarial (gain) loss402 230 (382)(274)100 (144)
Foreign currency exchange rate changes— 63 — (88)5 (6)
Benefits paid(1,314)(280)(692)(217)(204)(202)
Actual expenses/taxes— (7)— (2)— — 
Divestitures/Acquisitions1,505 493 — — 28 — 
Curtailment101 (34)— — 15 (1)
Special termination costs26 — — — — — 
Benefit obligation at December 3111,730 4,024 10,140 3,289 1,981 1,880 
Change in Plan Assets
Fair value of plan assets at January 19,537 3,061 9,137 3,398 — — 
Actual return on plan assets1,159 395 338 (133)— — 
Foreign currency exchange rate changes— 31 — (77)— — 
Employer contributions473 115 754 90 147 148 
Plan participants’ contributions— 2 — 2 57 54 
Benefits paid(1,314)(280)(692)(217)(204)(202)
Actual expenses— (7)— (2)— — 
Divestitures/Acquisitions1,932 580 — — — — 
Fair value of plan assets at December 3111,787 3,897 9,537 3,061 — — 
Funded status at December 31$57 $(127)$(603)$(228)$(1,981)$(1,880)
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Amounts recognized on the Consolidated Balance Sheet for the company’s pension and OPEB plans at December 31, 2025 and 2024, include:
Pension Benefits
20252024Other Benefits
U.S.Int’l.U.S.Int’l.20252024
Deferred charges and other assets$1,519 $832 $607 $655 $— $— 
Accrued liabilities(367)(67)(146)(71)(162)(149)
Noncurrent employee benefit plans(1,095)(892)(1,064)(812)(1,819)(1,731)
Net amount recognized at December 31$57 $(127)$(603)$(228)$(1,981)$(1,880)
For the year ended December 31, 2025, the increase in benefit obligations was primarily due to the acquisition of Hess. For the year ended December 31, 2024, the decrease in benefit obligations was primarily due to actuarial gains caused by higher discount rates used to value the obligations.
Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $3,171 and $3,376 at the end of 2025 and 2024, respectively. These amounts consisted of:
Pension Benefits
20252024Other Benefits
U.S.Int’l.U.S.Int’l.20252024
Net actuarial (gain) loss$2,463 $891 $2,796 $849 $(266)$(401)
Prior service (credits) costs29 91 33 133 (37)(34)
Total recognized at December 31$2,492 $982 $2,829 $982 $(303)$(435)
The accumulated benefit obligations for all U.S. and international pension plans were $10,668 and $3,757, respectively, at December 31, 2025, and $9,053 and $3,066, respectively, at December 31, 2024.
Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2025 and 2024, was:
Pension Benefits
20252024
U.S.Int’l.U.S.Int’l.
Projected benefit obligations$1,461 $929 $1,214 $884 
Accumulated benefit obligations1,341 762 1,145 744 
Fair value of plan assets— — 7 1 
The components of net periodic benefit cost and amounts recognized in the Consolidated Statement of Comprehensive Income for 2025, 2024 and 2023 are shown in the table below:
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Pension Benefits
202520242023Other Benefits
U.S.Int’l.U.S.Int’l.U.S.Int’l.202520242023
Net Periodic Benefit Cost
Service cost$365 $55 $357 $54 $342 $58 $30 $34 $33 
Interest cost505 207 465 191 448 193 99 98 97 
Expected return on plan assets(736)(205)(597)(196)(557)(204)— — — 
Amortization of prior service costs (credits)4 12 4 11 4 8 (23)(25)(25)
Recognized actuarial (gains) losses130 43 243 18 199 8 (15)(15)(19)
Settlement losses (gains)181 (4)— 1 56 — — — — 
Curtailment losses (gains)101 (7)— — — 2 (3)(1)— 
Special termination benefits26 — — — — 2 — — — 
Acquisition/Divestiture losses (gains)— — — — — (2)— — — 
Total net periodic benefit cost576 101 472 79 492 65 88 91 86 
Changes Recognized in Comprehensive Income
Net actuarial (gain) loss during period(22)83 (122)45 270 172 119 (151)108 
Amortization of actuarial (gain) loss(310)(40)(243)(19)(255)(8)15 15 19 
Prior service (credits) costs during period— (30)— 18 — 28 (29)30 1 
Amortization of prior service (costs) credits(4)(12)(4)(11)(4)(8)26 25 25 
Total changes recognized in other
comprehensive income
(336)1 (369)33 11 184 131 (81)153 
Recognized in Net Periodic Benefit Cost and Other Comprehensive Income
$240 $102 $103 $112 $503 $249 $219 $10 $239 
Assumptions The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31:
Pension Benefits
202520242023Other Benefits
U.S.Int’l.U.S.Int’l.U.S.Int’l.202520242023
Assumptions used to determine benefit obligations:
Discount rate5.5 %6.2 %5.7 %6.0 %5.0 %5.5 %5.4 %5.7 %5.1 %
Rate of compensation increase4.5 %4.0 %4.5 %3.9 %4.5 %3.9 %N/AN/AN/A
Cash balance interest crediting rate4.7 %N/AN/AN/AN/AN/AN/AN/AN/A
Assumptions used to determine net periodic benefit cost:
Discount rate for service cost5.7 %6.0 %5.0 %5.5 %5.2 %5.8 %5.8 %5.2 %5.4 %
Discount rate for interest cost5.1 %6.0 %4.8 %5.5 %5.0 %5.8 %5.4 %5.1 %5.2 %
Expected return on plan assets7.1 %6.2 %7.0 %5.9 %7.0 %6.1 %N/AN/AN/A
Rate of compensation increase4.5 %3.9 %4.5 %3.9 %4.5 %4.2 %N/AN/AN/A
Cash balance interest crediting rate4.8 %N/AN/AN/AN/AN/AN/AN/AN/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 2025, the company used an expected long-term rate of return of 7.1 percent for U.S. pension plan assets, which account for 76 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 5.5 percent,
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5.7 percent, and 5.0 percent for 2025, 2024, and 2023, respectively, for the main U.S. pension plan and 5.3 percent, 5.6 percent, and 5.0 percent for 2025, 2024, and 2023, respectively, for the main U.S. OPEB plans.
Other Benefit Assumptions For the measurement of accumulated post-employment benefit obligation at December 31, 2025, for the main U.S. OPEB plan, the assumed health care cost-trend rates start with 7.9 percent in 2026 and gradually decline to 4.5 percent for 2035 and beyond. For this measurement at December 31, 2024, the assumed health care cost-trend rates started with 8.4 percent in 2025 and gradually declined to 4.5 percent for 2034 and beyond.
Plan Assets and Investment Strategy
The fair value measurements of the company’s pension plans for 2025 and 2024 are as follows:
U.S.Int’l.
TotalLevel 1Level 2Level 3NAVTotal Level 1Level 2Level 3NAV
At December 31, 2024
Equities
U.S.1
$1,866 $1,866 $— $— $— $180 $180 $— $— $— 
International1,208 1,197 — 11 — 107 97 — 10 — 
Collective Trusts/Mutual Funds2
1,191 4 — — 1,187 98 6 13 — 79 
Fixed Income
Government132 — 132 — — 167 99 68 — — 
Corporate1,042 — 1,042 — — 403 2 401 — — 
Bank Loans10 — 10 — — — — — — — 
Mortgage/Asset Backed1 — 1 — — 4 — 4 — — 
Collective Trusts/Mutual Funds2
2,342 — — — 2,342 1,594 2 10 — 1,582 
Mixed Funds3
— — — — — 76 — 76 — — 
Real Assets4
1,383 — — — 1,383 105 — 16 — 89 
Alternative Investments5
— — — — — 9 — 9 — — 
Cash and Cash Equivalents289 13 — — 276 108 90 — — 18 
Other6
73 (3)13 63 — 209 — 12 68 129 
Total at December 31, 2024$9,537 $3,077 $1,198 $74 $5,188 $3,060 $476 $609 $78 $1,897 
At December 31, 2025
Equities
U.S.1
$2,077 $2,077 $— $— $— $177 $177 $— $— $— 
International1,168 1,152 — 16 — 122 109 — 13 — 
Collective Trusts/Mutual Funds2
833 6 — — 827 100 5 18 — 77 
Fixed Income
Government672 — 672 — — 200 132 68 — — 
Corporate2,040 — 2,040 — — 532 1 531 — — 
Bank Loans22 — 22 — — — — — — — 
Mortgage/Asset Backed129 — 129 — — 5 — 5 — — 
Collective Trusts/Mutual Funds2
2,523 — — — 2,523 1,753 3 11 — 1,739 
Mixed Funds3
— — — — — 89 — 89 — — 
Real Assets4
1,594 — — — 1,594 118 — 22 — 96 
Alternative Investments5
423 — — — 423 14 — 8 — 6 
Cash and Cash Equivalents273 66 — — 207 93 90 — — 3 
Other6
33 (55)21 67 — 694 5 12 528 149 
Total at December 31, 2025$11,787 $3,246 $2,884 $83 $5,574 $3,897 $522 $764 $541 $2,070 
1 There were no investments in the company’s common stock at December 31, 2025 or December 31, 2024.
2 Collective Trusts/Mutual Funds for U.S. plans are entirely index funds; for International plans, they are mostly unit trust and index funds.
3 Mixed funds are composed of funds that invest in both equity and fixed-income instruments in order to diversify and lower risk.
4 Includes Real Estate and Infrastructure. The year-end valuations of U.S. Real Assets are based on third-party appraisals that occur at least once a year for each property in the portfolio.
5 Includes Private Equity.
6 The “Other” asset class includes net payables for securities purchased but not yet settled (Level 1); dividends and interest- and tax-related receivables (Level 2); insurance contracts (Level 3); and investments in private-equity limited partnerships (NAV).
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The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below:
Equity
U.S.Int’l.Real EstateOtherTotal
Total at December 31, 2023$1 $— $— $137 $138 
Actual Return on Plan Assets:
Assets held at the reporting date(1)11 — — 10 
Assets sold during the period— 2 — 9 11 
Purchases, Sales and Settlements— 2 — (9)(7)
Transfers in and/or out of Level 3— 6 — (6)— 
Total at December 31, 2024$— $21 $— $131 $152 
Actual Return on Plan Assets:
Assets held at the reporting date— 8 — — 8 
Assets sold during the period— — — 10 10 
Purchases, Sales and Settlements— — — 454 454 
Transfers in and/or out of Level 3— — — — — 
Total at December 31, 2025$— $29 $— $595 $624 
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 30–60 percent, Fixed Income 30–50 percent, Real Assets 5–25 percent, Private Equity 0–5 percent and Cash 0–10 percent. For the U.K. pension plan, the U.K. Plan Trustee has established the following asset allocation guidelines: Equities 5–15 percent, Fixed Income 63–93 percent, Real Estate 5–15 percent, and Cash 0–7 percent. 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 2025, the company contributed $473 and $115 to its U.S. and international pension plans, respectively. In 2026, the company expects contributions to be approximately $525 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 $162 in 2026; $147 was paid in 2025.
The following benefit payments, which include estimated future service, are expected to be paid by the company in the next 10 years:
Pension BenefitsOther
U.S.Int’l.Benefits
2026$1,900 $242 $162 
2027932 263 158 
2028850 281 154 
2029843 276 151 
2030834 284 149 
2031-20354,237 1,506 726 
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 $323, $330 and $320 in 2025, 2024 and 2023, respectively.
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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 2025, 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 $1,300, $965 and $809 in 2025, 2024 and 2023, 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 provided certain guarantees in the ordinary course of business, including financial and performance guarantees related to equity affiliates. Chevron has no material guarantees outstanding.
Indemnifications The company often includes standard indemnification provisions in its arrangements with its partners, suppliers and vendors in the ordinary course of business, the terms of which range in duration and sometimes are not limited. 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: 2026 – $1,330; 2027 – $1,554; 2028 – $1,807; 2029 – $1,806; 2030 – $1,700; after 2030 – $11,080. The aggregate amount of required payments for other unconditional purchase obligations are: 2026 – $204; 2027 – $215; 2028 – $155; 2029 – $16; 2030 – $16; after 2030 – $31. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were $1,104 in 2025, $1,354 in 2024 and $1,420 in 2023.
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.
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
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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, 2025, was $1,059. Included in this balance was $274 related to remediation activities at sites for which the company has 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 2025 environmental reserves balance of $785, $397 is related to the company’s U.S. downstream operations, $39 to its international downstream operations, and $349 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 2025 had a recorded liability that was material to the company’s results of operations, consolidated financial position or liquidity.
Refer to Note 25 Asset Retirement Obligations for a discussion of the company’s asset retirement obligations.
Decommissioning Obligations for Previously Divested Assets Some assets are divested along with their related liabilities, such as decommissioning obligations. In certain instances, such transferred obligations have returned and may continue to return to the company. For example, in fourth quarter 2023, the company recognized charges for decommissioning obligations from certain previously divested assets in the Gulf of America. To the extent the current owners of the company’s previously divested assets default on their decommissioning obligations, regulators may require that Chevron assume such obligations. The company could have additional significant obligations revert, primarily in the United States. The company is not currently aware of any such obligations that are reasonably possible to be material. The liability balance at the end of 2024 was $2,478, $297 was spent in 2025, and the balance at the end of 2025 was $2,190.
Other Contingencies The company and its affiliates 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.
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.
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. The ARO liability is initially recognized at its fair value with an increase to the related asset. Subsequent accretion of the liability and depreciation of the asset is recorded over time. The company evaluates its ARO estimates regularly or when there is significant new information about costs, timing, and duration of asset retirement activity.
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 reviews of its downstream long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation.
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The following table indicates the changes to the company’s before-tax asset retirement obligations in 2025, 2024 and 2023:
202520242023
Balance at January 1$12,667 $13,833 $12,701 
Liabilities assumed in acquisition1,682 — 220 
Liabilities incurred186 83 183 
Liabilities settled(1,109)(2,083)(1,471)
Reduction due to asset sales(458)(171)(94)
Accretion expense617 588 593 
Revisions in estimated cash flows1,403 417 1,701 
Balance at December 31$14,988 $12,667 $13,833 
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 $14,988 balance at the end of 2025 was $13,919.
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 $12,314 and $14,227 at December 31, 2025 and 2024, 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 2025 included after-tax gains of approximately $400 relating to the sale of certain properties. Of this amount, approximately $360 and $40 related to upstream and downstream, respectively. Earnings in 2024 included after-tax gains of approximately $246 relating to the sale of certain properties, of which approximately $231 and $15 related to upstream and downstream assets, respectively. Earnings in 2023 included after-tax gains of approximately $143 relating to the sale of certain properties, of which approximately $110 and $33 related to upstream and downstream assets, respectively.
Earnings in 2025 included after-tax charges of approximately $355 for Hess severance and transition costs ($245 in U.S. Upstream, $70 in International Upstream, $40 in All Other), $300 for legal reserves ($170 in U.S. Downstream, $130 in U.S. Upstream) and $223 for pension settlement and curtailment costs. Earnings in 2024 included after-tax charges of approximately $715 for severance ($208 in All Other, $188 in U.S. Downstream, $183 in U.S. Upstream, $119 in International Upstream, $17 in International Downstream) and $400 for impairments ($185 in International Downstream, $125 in International Upstream, $90 in U.S. Downstream). Earnings in 2023 included after-tax charges of approximately $1,950 for decommissioning obligations from previously divested oil and gas production assets in the U.S. Upstream Gulf of America, $1,765 for U.S. Upstream impairments, mainly in California, and several tax items with a net benefit of $655 in International Upstream.
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Other financial information is as follows:
Year ended December 31
202520242023
Total financing interest and debt costs$1,392 $773 $617 
Less: Capitalized interest175 179 148 
Interest and debt expense$1,217 $594 $469 
Research and development expenses$427 $353 $320 
Excess of replacement cost over the carrying value of inventories (LIFO method)
$4,808 $5,997 $6,455 
LIFO profits (losses) on inventory drawdowns included in earnings$(38)$(111)$14 
Foreign currency effects*
$(469)$520 $(224)
* Includes $(3), $45 and $(11) in 2025, 2024 and 2023, respectively, for the company’s share of equity affiliates’ foreign currency effects.
The company has $4,568 in goodwill on the Consolidated Balance Sheet, of which $4,216 is in the upstream segment primarily related to the 2005 acquisition of Unocal and $352 is in the downstream segment related to the 2022 acquisition of Renewable Energy Group, Inc. The company tested this goodwill for impairment during 2025, and no impairment was required.
Note 28
Financial Instruments - Credit Losses
Chevron’s expected credit loss allowance balance was $392 and $611 at December 31, 2025, and December 31, 2024, 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 $15,986 at December 31, 2025, 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 $3,516 at December 31, 2025, 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 $83 and zero at December 31, 2025, and December 31, 2024, respectively, are included within “Investments and advances” on the Consolidated Balance Sheet.
Note 29
Acquisition of Hess Corporation
On July 18, 2025, the company acquired Hess Corporation (Hess), an independent oil and gas exploration and production company. Hess’s principal upstream operations are in the United States, Guyana and Malaysia. Hess’s operations also include an approximately 38 percent ownership interest in Hess Midstream LP (HESM), with operations primarily in the Bakken shale in the Williston Basin area of North Dakota.
The aggregate purchase price of Hess was approximately $48 billion, including 15.38 million shares of Hess common stock purchased in open market transactions in the first quarter of 2025 and 301.25 million shares of Chevron common stock issued as closing consideration in July. As part of the transaction, the company assumed debt with an aggregate outstanding principal value of $8.8 billion. The shares issued represented approximately 15 percent of the shares of Chevron common stock outstanding immediately after the transaction closed on July 18, 2025.
The acquisition was accounted for as a business combination under ASC 805, which requires assets acquired and liabilities assumed to be measured at their acquisition date fair value. Provisional fair value measurements were made for acquired assets and liabilities, and adjustments to those measurements may be made in subsequent periods, up to one year from the
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date of acquisition, as information necessary to complete the analysis is obtained. Oil and gas properties were valued using a discounted cash flow model that incorporated assumptions for commodity prices, future production volumes, operating costs, development costs, and risk-adjusted discount rates. The fair value of the noncontrolling interest was determined based on the quoted market price of HESM on the acquisition date. Debt assumed in the acquisition was valued based on observable market prices for Hess’s debt. As a result of measuring the assets acquired and the liabilities assumed at fair value, there was no goodwill or bargain purchase recognized.
At July 18, 2025
(Billions of dollars)
Current assets$3.4 
Properties, plant and equipment
73.5 
Other assets2.6 
Total assets acquired79.5 
Current liabilities3.1 
Long-term debt(1)
10.0 
Deferred income taxes11.0 
Other liabilities2.4 
Total liabilities assumed26.5 
Noncontrolling interest(2)
5.0 
Net assets acquired / purchase price$48.0 
(1) Includes finance leases
(2) Related to HESM

The long-term debt assumed in the transaction is detailed in the table below:
Hess CorporationPrincipal
4.300% due 2027
$1,000 
7.875% due 2029
467 
7.300% due 2031
631 
7.125% due 2033
540 
6.000% due 2040
750 
5.600% due 2041
1,250 
5.800% due 2047
500 
  Total Hess Corporation Debt$5,138 
Hess Midstream Operations LP
5.125% due 2028
$550 
5.875% due 2028
800 
6.500% due 2029
600 
4.250% due 2030
750 
5.500% due 2030
400 
Term loan and credit facility borrowings646 
  Total Hess Midstream Operations LP Debt$3,746 
Unamortized discounts and debt issuance costs(61)
  Total Long-Term Debt Assumed$8,823 
Fair market value adjustment for debt acquired in the acquisition247 
  Fair Market Value of Long-Term Debt Assumed$9,070 
The following table presents revenue and earnings for Hess since the acquisition date (July 18, 2025), for the year ended December 31, 2025.
Year Ended December 31,
2025
Sales and other operating revenue$5,957 
Net Income (Loss) Attributable to Chevron Corporation$193 
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The following unaudited pro forma information presents the results of operations as if the acquisition of Hess had occurred January 1, 2024:
Year Ended December 31,
20252024
Sales and other operating revenue$189,416 $204,300 
Net Income (Loss) Attributable to Chevron Corporation$12,464 $19,003 
The unaudited pro forma information uses estimates and assumptions based on information available at the time. Management believes the estimates and assumptions to be reasonable; however, actual results may differ significantly from this pro forma financial information. The pro forma information does not reflect any synergistic savings that might be achieved from combining the operations and is not intended to reflect the actual results that would have occurred had the companies actually been combined during the periods presented. The pro forma results reflect pro forma adjustments primarily related to conforming Hess’ accounting policies to Chevron’s, additional depreciation expense related to the fair value adjustment of the acquired property, plant and equipment, elimination of intercompany transactions and applicable income tax impacts.
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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
Table I - Costs Incurred in Exploration, Property Acquisitions and Development1
Consolidated CompaniesAffiliated Companies
Other
Millions of dollarsU.S.AmericasAfricaAsiaAustraliaEuropeTotalTCOOther
Year Ended December 31, 2025
Exploration
Wells$127 $161 $109 $32 $82 $— $511 $— $— 
Geological and geophysical115 140 162 19 2 — 438 — — 
Other75 71 92 21 28 — 287 — — 
Total exploration317 372 363 72 112 — 1,236 — — 
Property acquisitions2,3
Proved 19,947 22,987 — 838 — — 43,772 — — 
Unproved1,783 28,141 15 — — — 29,939 — — 
Total property acquisitions21,730 51,128 15 838 — — 73,711 — — 
Development4
8,532 2,402 1,390 1,180 963 71 14,538 577 21 
Total Costs Incurred5
$30,579 $53,902 $1,768 $2,090 $1,075 $71 $89,485 $577 $21 
Year Ended December 31, 2024
Exploration
Wells$193 $2 $155 $94 $4 $— $448 $— $— 
Geological and geophysical173 81 47 23 3 — 327 — — 
Other62 62 70 15 30 — 239 — — 
Total exploration428 145 272 132 37 — 1,014 — — 
Property acquisitions2
Proved - Other11 — 95 — — — 106 — — 
Unproved - Other69 38 22 — — — 129 — — 
Total property acquisitions80 38 117 — — — 235 — — 
Development4
9,334 1,261 895 774 1,015 54 13,333 1,480 7 
Total Costs Incurred5
$9,842 $1,444 $1,284 $906 $1,052 $54 $14,582 $1,480 $7 
Year Ended December 31, 2023
Exploration
Wells$280 $92 $36 $111 $11 $— $530 $— $— 
Geological and geophysical84 49 83 — — — 216 — — 
Other50 104 57 15 32 4 262 — — 
Total exploration414 245 176 126 43 4 1,008 — — 
Property acquisitions2
Proved - Other10,123 — — — — — 10,123 — — 
Unproved - Other504 1 — 3 — — 508 — — 
Total property acquisitions10,627 1 — 3 — — 10,631 — — 
Development4
9,645 986 784 619 822 64 12,920 2,278 86 
Total Costs Incurred5
$20,686 $1,232 $960 $748 $865 $68 $24,559 $2,278 $86 
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 Majority of proved and unproved property acquisitions represent assets acquired from Hess Corporation.
4 Includes $89, $59 and $208 of costs incurred on major capital projects prior to assignment of proved reserves for consolidated companies in 2025, 2024, and 2023, respectively.
5 Reconciliation of consolidated companies total cost incurred to Upstream Capex - $ billions:
202520242023
Total cost incurred by Consolidated Companies$89.5 $14.6 $24.6 
  Acquisitions(73.5)— (10.5)(2025: Hess Corporation; 2023: PDC Energy, Inc.)
  Expensed exploration costs (0.7)(0.6)(0.5)(Geological and geophysical and other exploration costs)
  Non-oil and gas activities1.8 0.6 1.4 (Primarily LNG and transportation activities)
  ARO reduction/(build)(1.2)(0.3)(1.3)
Upstream Capex$15.9 $14.3 $13.7 
Reference page 49 Upstream Capex
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estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows. The amounts for consolidated companies are organized by geographic areas including the United States, Other Americas, Africa, Asia, Australia and Europe. Amounts for affiliated companies include Chevron’s equity interests in Tengizchevroil (TCO) in the Republic of Kazakhstan and in other affiliates, principally in Angola. 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 CompaniesAffiliated Companies
Other
Millions of dollarsU.S.AmericasAfricaAsiaAustraliaEuropeTotalTCOOther
At December 31, 2025
Unproved properties$4,183 $27,415 $290 $534 $1,881 $— $34,303 $108 $— 
Proved properties and
related producing assets
137,610 38,756 41,133 30,262 24,401 2,376 274,538 39,515 1,637 
Support equipment4,129 1,444 1,607 788 19,135 — 27,103 853 — 
Deferred exploratory wells91 144 206 177 1,067 74 1,759 — — 
Other uncompleted projects5,238 6,411 1,541 1,392 2,666 29 17,277 970 
Gross Capitalized Costs151,251 74,170 44,777 33,153 49,150 2,479 354,980 41,446 1,637 
Unproved properties valuation133 1,150 224 534 3 — 2,044 84 — 
Proved producing properties – Depreciation and depletion
77,504 12,574 36,580 19,126 15,441 1,083 162,308 15,989 1,206 
Support equipment depreciation1,260 213 1,265 634 7,214 — 10,586 600 — 
Accumulated provisions78,897 13,937 38,069 20,294 22,658 1,083 174,938 16,673 1,206 
Net Capitalized Costs$72,354 $60,233 $6,708 $12,859 $26,492 $1,396 $180,042 $24,773 $431 
At December 31, 2024
Unproved properties$2,473 $1,545 $287 $536 $1,882 $— $6,723 $108 $— 
Proved properties and
related producing assets
109,147 15,739 48,391 29,265 24,310 2,283 229,135 35,374 1,612 
Support equipment2,075 213 1,565 698 19,134 — 23,685 733 — 
Deferred exploratory wells17 69 204 179 1,119 74 1,662 — — 
Other uncompleted projects8,918 650 1,756 1,040 1,814 69 14,247 4,634 — 
Gross Capitalized Costs122,630 18,216 52,203 31,718 48,259 2,426 275,452 40,849 1,612 
Unproved properties valuation119 1,119 213 533 5 — 1,989 80 — 
Proved producing properties – Depreciation and depletion
69,545 10,314 41,485 18,251 14,038 956 154,589 11,441 1,014 
Support equipment depreciation1,265 152 1,231 556 6,375 — 9,579 535 — 
Accumulated provisions70,929 11,585 42,929 19,340 20,418 956 166,157 12,056 1,014 
Net Capitalized Costs$51,701 $6,631 $9,274 $12,378 $27,841 $1,470 $109,295 $28,793 $598 
At December 31, 2023
Unproved properties$2,541 $1,666 $265 $536 $1,882 $— $6,890 $108 $— 
Proved properties and
related producing assets
100,680 23,867 47,635 30,387 23,842 2,228 228,639 23,139 1,609 
Support equipment2,121 191 1,555 688 19,118 — 23,673 673 — 
Deferred exploratory wells— 73 205 178 1,119 74 1,649 — — 
Other uncompleted projects10,872 734 1,271 1,121 1,469 52 15,519 15,438 130 
Gross Capitalized Costs116,214 26,531 50,931 32,910 47,430 2,354 276,370 39,358 1,739 
Unproved properties valuation168 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 depreciation1,295 155 1,202 529 5,478 — 8,659 478 — 
Accumulated provisions66,518 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 

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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 2025, 2024 and 2023 are shown in the following table. Net income (loss) from exploration and production activities as reported on page 82 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 82.
Consolidated CompaniesAffiliated Companies
Other
Millions of dollarsU.S.AmericasAfricaAsiaAustraliaEuropeTotalTCOOther
Year Ended December 31, 2025
Revenues from net production
Sales$9,302 $3,478 $423 $3,409 $4,630 $284 $21,526 $8,362 $895 
Transfers16,783 1,832 3,880 1,796 3,970 — 28,261 — — 
Total26,085 5,310 4,303 5,205 8,600 284 49,787 8,362 895 
Production expenses excluding taxes(6,983)(828)(1,464)(1,058)(523)(79)(10,935)(636)(68)
Taxes other than on income(1,452)(52)(190)(20)(211)(3)(1,928)(1,378)— 
Proved producing properties:
Depreciation and depletion(9,324)(2,339)(1,206)(1,206)(2,195)(145)(16,415)(4,621)(179)
Accretion expense2
(236)(33)(120)(60)(108)(7)(564)(8)(4)
Exploration expenses(169)(359)(379)(57)(131)(3)(1,098)— — 
Unproved properties valuation(57)(36)(23)— — — (116)— — 
Other income (loss)3
350 (161)125 129 62 (82)423 53 (206)
Results before income taxes8,214 1,502 1,046 2,933 5,494 (35)19,154 1,772 438 
Income tax (expense) benefit(1,825)(480)(305)(1,641)(1,816)(52)(6,119)(535)22 
Results of Producing Operations$6,389 $1,022 $741 $1,292 $3,678 $(87)$13,035 $1,237 $460 
Year Ended December 31, 2024
Revenues from net production
Sales$6,657 $799 $622 $3,376 $5,856 $319 $17,629 $7,240 $700 
Transfers18,043 3,110 5,227 2,101 4,237 — 32,718 — — 
Total24,700 3,909 5,849 5,477 10,093 319 50,347 7,240 700 
Production expenses excluding taxes(5,472)(928)(1,662)(939)(540)(74)(9,615)(696)(46)
Taxes other than on income(1,445)(67)(165)(24)(209)(3)(1,913)(1,117)— 
Proved producing properties:
Depreciation and depletion(7,231)(981)(1,616)(1,236)(2,547)(103)(13,714)(1,222)(154)
Accretion expense2
(205)(26)(127)(63)(104)(8)(533)(5)(3)
Exploration expenses(352)(141)(308)(233)(33)(1)(1,068)— — 
Unproved properties valuation(68)(31)(30)(1)— — (130)— — 
Other income (loss)3
247 1,556 534 139 (8)(4)2,464 (80)(150)
Results before income taxes10,174 3,291 2,475 3,120 6,652 126 25,838 4,120 347 
Income tax (expense) benefit(2,238)(954)(1,240)(1,684)(2,010)(95)(8,221)(1,238)12 
Results of Producing Operations$7,936 $2,337 $1,235 $1,436 $4,642 $31 $17,617 $2,882 $359 
1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
2 Represents accretion of ARO liability. Refer to Note 25 Asset Retirement Obligations.
3 Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses.

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Table III - Results of Operations for Oil and Gas Producing Activities1, continued
Consolidated CompaniesAffiliated Companies
Other
Millions of dollarsU.S.AmericasAfricaAsiaAustraliaEuropeTotalTCOOther
Year Ended December 31, 2023
Revenues from net production
Sales$6,658 $724 $515 $3,309 $6,780 $368 $18,354 $6,831 $891 
Transfers15,948 3,243 5,979 2,151 4,753 — 32,074 — — 
Total22,606 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 taxes5,433 1,420 3,043 3,152 7,984 176 21,208 4,684 486 
Income tax (expense) benefit(1,195)(389)(832)(1,576)(2,776)(196)(6,964)(1,408)24 
Results of Producing Operations$4,238 $1,031 $2,211 $1,576 $5,208 $(20)$14,244 $3,276 $510 
1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
2 Represents accretion of ARO liability. Refer to Note 25 Asset Retirement Obligations.
3 Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses. 2023 also includes a loss related to decommissioning obligations from certain previously divested oil and gas production assets in the Gulf of America.
Table IV - Results of Operations for Oil and Gas Producing Activities - Unit Prices and Costs1
Consolidated CompaniesAffiliated Companies
Other
U.S.AmericasAfricaAsiaAustraliaEuropeTotalTCOOther
Year Ended December 31, 2025
Average sales prices
Crude, per barrel$62.25 $64.02 $66.30 $64.06 $65.08 $70.49 $63.22 $56.88 $— 
Natural gas liquids, per barrel18.80 — 21.74 — — — 18.91 12.00 43.32 
Natural gas, per thousand cubic feet2.04 1.71 4.91 4.41 8.85 10.15 4.86 0.89 8.28 
Average production costs, per barrel2
10.35 10.93 18.71 7.78 3.32 19.24 9.71 3.80 3.47 
Year Ended December 31, 2024
Average sales prices
Crude, per barrel$73.47 $70.06 $75.69 $71.22 $74.20 $77.47 $73.27 $67.02 $— 
Natural gas liquids, per barrel19.88 26.53 32.13 — 59.48 — 20.51 12.09 47.61 
Natural gas, per thousand cubic feet1.03 1.03 4.14 4.21 10.24 9.10 4.99 1.57 7.75 
Average production costs, per barrel2
9.4114.2818.076.803.3716.439.235.442.89
Year Ended December 31, 2023
Average sales prices
Crude, per barrel$74.36 $72.85 $72.86 $70.05 $78.93 $83.00 $73.76 $66.44 $— 
Natural gas liquids, per barrel20.01 29.00 27.80 — 51.00 — 20.79 9.43 45.33 
Natural gas, per thousand cubic feet1.65 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 
1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
2 Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel.









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Table V Proved Reserve Quantity Information*
Summary of Net Oil and Gas Reserves
202520242023
Liquids in Millions of Barrels
Natural Gas in Billions of Cubic FeetCrude Oil
Condensate		SyntheticOilNGLNatural
Gas		Crude Oil
Condensate		SyntheticOilNGLNatural
Gas		Crude Oil
Condensate		SyntheticOilNGLNatural
Gas
Proved Developed
 Consolidated Companies
U.S.1,502 — 854 5,521 1,207 — 615 4,420 1,221 — 611 4,543 
Other Americas430 — — 287 181 — — 168 195 598 7 298 
Africa325 — 49 1,249 392 — 67 1,491 367 — 70 1,632 
Asia263 — — 6,196 246 — — 6,560 240 — — 6,974 
Australia66 — 1 5,886 72 — 1 6,517 85 — 2 6,951 
Europe19 — — 7 23 — — 10 25 — — 9 
 Total Consolidated2,605 — 904 19,146 2,121 — 683 19,166 2,133 598 690 20,407 
 Affiliated Companies
TCO714 — 61 895 663 — 70 1,118 478 — 67 1,062 
Other2 — 14 696 2 — 12 670 3 — 13 323 
 Total Consolidated and Affiliated Companies3,321 — 979 20,737 2,786 — 765 20,954 2,614 598 770 21,792 
Proved Undeveloped
 Consolidated Companies
U.S.553 — 351 2,520 639 — 373 2,730 721 — 413 3,139 
Other Americas315 — — 240 106 — — 146 129 — 8 276 
Africa50 — 16 689 63 — 19 703 78 — 27 625 
Asia42 — — 1,728 52 — — 1,351 61 — — 1,419 
Australia27 — — 3,314 20 — — 2,422 22 — — 2,444 
Europe16 — — 5 26 — — 8 28 — — 8 
 Total Consolidated1,003 — 367 8,496 906 — 392 7,360 1,039 — 448 7,911 
 Affiliated Companies
TCO45 — 2 — 224 — 2 20 526 — 11 233 
Other— — — 12 — — — 41 — — — 445 
 Total Consolidated and Affiliated Companies1,048 — 369 8,508 1,130 — 394 7,421 1,565 — 459 8,589 
Total Proved Reserves4,369 — 1,348 29,245 3,916 — 1,159 28,375 4,179 598 1,229 30,381 
* Reserve quantities include natural gas projected to be consumed in operations of 2,634, 2,462 and 2,655 billions of cubic feet and equivalent synthetic oil projected to be consumed in operations of 0, 0, and 27 millions of barrels as of December 31, 2025, 2024 and 2023, 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.
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Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.
Proved reserves are estimated by company asset teams composed of earth scientists and engineers. As part of the internal control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired by the Manager of Reserves and Storage, an organization that is separate from the business organizations that estimate reserves. The Manager of Reserves and Storage has more than 35 years of experience working in the oil and gas industry and holds both undergraduate and graduate degrees in geoscience. His experience includes various technical and management roles in providing reserve and resource estimates in support of major capital and exploration projects, and more than 10 years of overseeing oil and gas reserves processes. 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 organizations 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 organizations and regions to review and discuss reserve changes recommended by the various asset teams. Major changes are also reviewed with the company’s senior leadership team including the Chief Executive Officer and the Chief Financial Officer. The company’s annual reserves activity is also reviewed with the company’s Board Audit Committee and Board of Directors. If major changes to reserves were to occur between the annual reviews, those matters would also be discussed with the Board.
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.
The acquisition of Hess Corporation (Hess) was completed on July 18, 2025. Given the timing of the acquisition, Chevron has continued to rely on legacy Hess reserves staff and processes for reviewing reserves with input and guidance from the Chevron RAC. The processes include internal reviews and an external audit. Accordingly, the company continued to retain DeGolyer and MacNaughton, an independent petroleum engineering consulting firm, to complete an audit of the legacy Hess proved reserves at December 31, 2025 (representing approximately 13 percent of Chevron’s total proved reserves). Based upon their evaluation, DeGolyer and MacNaughton issued an unqualified audit opinion, and their report is attached as Exhibit 99.2 to this Annual Report on Form 10-K.
Technologies Used in Establishing Proved Reserves Additions In 2025, additions to Chevron’s proved reserves were based on a wide range of geologic and engineering technologies. Information generated from subsurface data and geoscience and engineering analysis was used in both proprietary and commercially available analytic tools, including reservoir simulation, geologic modeling and seismic processing, to provide “reasonably certain” proved reserves estimates. These technologies have been utilized extensively by the company in the past, and the company believes that they provide a high degree of confidence in establishing reliable and consistent reserves estimates.
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Proved Undeveloped Reserves
Noteworthy changes in proved undeveloped reserves are shown in the table below and discussed below.
Proved Undeveloped Reserves (Millions of BOE)
2025
Quantity at January 12,761 
Revisions19 
Improved recovery2 
Extension and discoveries440 
Purchases417 
Sales(4)
Transfers to proved developed(800)
Quantity at December 312,835 
In 2025, revisions include an increase of 55 million BOE in Israel, primarily at the Leviathan field, based on production performance-driven reservoir model changes that resulted in a re-allocation of proved developed and proved undeveloped reserves estimates. In Australia, there was an increase of 40 million BOE, largely attributable to positive reservoir performance at Jansz Io. The net decrease of 34 million BOE in the United States was primarily from the Denver-Julesburg (DJ) Basin with a decrease of 49 million BOE mainly due to portfolio optimization, partially offset by positive revisions in the Midland and Delaware basins. In Argentina, a negative revision of 33 million BOE was primarily attributable to shale and tight portfolio optimization.
In 2025, extensions and discoveries in the United States totaled 214 million BOE, primarily attributable to planned development of new locations in shale and tight assets in the Midland and Delaware basins (136 million BOE) and in the DJ Basin (73 million BOE). In Australia, additions of 128 million BOE resulted from the sanctioning of the Gorgon Stage 3 project. In Other Americas, extensions and discoveries totaled 95 million BOE, primarily attributable to the Hammerhead project sanctioned in Guyana (52 million BOE) and to additions from shale and tight assets in Argentina (40 million BOE).
In 2025, purchases of 221 million BOE in the United States are primarily attributable to the acquisition of Hess assets in North Dakota. In Other Americas, purchases of 193 million BOE are attributable to the acquisition of Hess interests in the Stabroek block in Guyana.
The difference in 2025 extensions and discoveries of 167 million BOE, between the net quantities of proved reserves of 607 million BOE as reflected on pages 116 through 118 and net quantities of proved undeveloped reserves of 440 million BOE, is primarily due to proved extensions and discoveries that were not recognized as proved undeveloped reserves in the prior year and were recognized directly as proved developed reserves in 2025.
Transfers to proved developed reserves in 2025 include 544 million BOE in the United States, from the Midland and Delaware basins (279 million BOE), Gulf of America (153 million BOE), and DJ Basin (112 million BOE). Other significant transfers to proved developed were 170 million BOE in Kazakhstan, largely driven by the startup of the Future Growth Project at TCO. A combined 86 million BOE of transfers to proved developed were recorded in Argentina, the Partitioned Zone, Australia, Nigeria, Angola, Canada, and other international locations. These transfers are the consequence of development expenditures on completing wells and facilities.
During 2025, the company’s investments totaled approximately $7.1 billion in oil and gas producing activities, and about $0.1 billion in non-oil and gas producing activities, to advance the development of proved undeveloped reserves. The United States accounted for about $4.3 billion primarily related to various development activities in the Midland and Delaware basins, the Gulf of America and the DJ Basin. In Africa, about $1.0 billion was expended on various offshore development and natural gas projects in Nigeria and Angola. An additional $0.6 billion was spent on development activities in Australia. Development activities in other international locations were primarily responsible for about $1.2 billion of expenditures. The company’s equity affiliates investments in oil and gas producing activities to advance development of proved undeveloped reserves in 2025 was $0.5 billion primarily related to development projects for TCO in Kazakhstan.
Reserves that remain proved undeveloped for five or more years are a result of several factors that affect optimal project development and execution. These factors may include the complex nature of the development project in adverse and remote locations, physical limitations of infrastructure or plant capacities that dictate project timing, compression projects that are pending reservoir pressure declines, and contractual limitations that dictate production levels.
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At year-end 2025, the company held approximately 396 million BOE of proved undeveloped reserves that have remained undeveloped for five years or more. The majority of these reserves are in locations where the company has a proven track record of developing major projects. In Australia, approximately 205 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, due to facility constraints at various fields and infrastructure associated with the Escravos gas projects in Nigeria.
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 2025, the positive impacts of higher natural gas prices in North America and of lower oil prices in production sharing contracts more than offset the negative impact of lower oil prices in tax and royalty assets, resulting in a proved reserve increase of approximately 57 million BOE. The year-end reserves quantities have been updated for these circumstances and significant changes are discussed in the appropriate reserves sections herein. Over the past three years, the ratio of proved undeveloped reserves to total proved reserves has ranged between 27 percent and 31 percent.
Proved Reserve Quantities For the three-year period ended December 31, 2025, the pattern of net reserve changes shown in the following tables is not necessarily indicative of future trends. Apart from acquisitions, the company’s ability to add proved reserves can be affected by events and circumstances that are outside the company’s control, such as delays in government permitting, partner approvals of development plans, changes in oil and gas prices, OPEC constraints, geopolitical uncertainties, civil unrest, events of war or military conflicts.
At December 31, 2025, proved reserves for the company were 10.6 billion BOE. The company’s estimated net proved reserves of liquids, including crude oil, condensate and synthetic oil for the years 2023, 2024 and 2025, are shown in the table on page 116. The company’s estimated net proved reserves of natural gas liquids (NGLs) are shown on page 117, and the company’s estimated net proved reserves of natural gas are shown on page 118.
Noteworthy changes in crude oil, condensate and synthetic oil proved reserves for 2023 through 2025 are discussed below and shown in the table on the following page:
Revisions In 2023, the 257 million barrels decrease in United States was primarily in the Midland and Delaware basins and California. Reservoir performance led to the decrease of 101 million barrels, and portfolio optimization led to a decrease of 59 million barrels in the Midland and Delaware basins. A reduction in planned development activities led to a decrease of 58 million barrels in California. In Other Americas, entitlement effects primarily contributed to an increase of 42 million barrels of synthetic oil at the Athabasca Oil Sands project in Canada. In Asia, reservoir performance, mainly in the Partitioned Zone between Saudi Arabia and Kuwait (the Partitioned Zone), was responsible for the 48 million barrels increase. Reservoir performance in Nigeria was mainly responsible for the 37 million barrels increase in Africa.
In 2024, the 37 million barrels increase in Asia was due to reservoir performance, primarily in the Partitioned Zone.
In 2025, the 46 million barrels increase in Asia was due to reservoir performance, primarily in the Partitioned Zone.
Extensions and Discoveries In 2023, extensions and discoveries of 124 million barrels in the Midland and Delaware basins were primarily responsible for the 170 million barrels increase in the United States. In Other Americas, the 55 million barrels of extensions and discoveries increase was mainly from shale and tight assets in Argentina.
In 2024, extensions and discoveries of 119 million barrels in the Midland and Delaware basins, and 45 million barrels in the DJ Basin, were primarily responsible for the 185 million barrels increase in the United States. In Other Americas, the 52 million barrels of extensions and discoveries increase was mainly from shale and tight assets in Argentina.
In 2025, extensions and discoveries of 121 million barrels in the Midland and Delaware basins were primarily responsible for the 148 million barrels increase in the United States. In Other Americas, the 89 million barrels of extensions and discoveries increase was primarily from the sanctioning of the Hammerhead project in Guyana (50 million barrels) and shale and tight assets in Argentina (35 million barrels).

Purchases In 2023, the acquisition of PDC in the DJ and Delaware basins was primarily responsible for the 207 million barrels increase in the United States.
In 2024, the renewal of the Agbami field deepwater license in Nigeria increased reserves by 51 million barrels.
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In 2025, the acquisition of Hess interests in the Stabroek block in Guyana was responsible for the 473 million barrels in Other Americas. The acquisition of Hess assets in North Dakota (362 million barrels) and the Gulf of America (29 million barrels) was mainly responsible for the 392 million barrels in the United States.
Sales In 2024, sales of 593 million barrels in synthetic oil were from the Athabasca oil sand assets in Canada and the 46 million barrels in Other Americas were from the divestment of shale and tight assets in Canada.
In 2025, sales of 35 million barrels in Africa were from the divestment of assets in the Republic of Congo.
Net Proved Reserves of Crude Oil, Condensate and Synthetic Oil
Consolidated CompaniesAffiliated CompaniesTotal
Consolidated
OtherSyntheticSyntheticand Affiliated
Millions of barrelsU.S.
Americas1
AfricaAsiaAustraliaEurope
Oil 2,5
TotalTCOOil
Other3
Companies
Reserves at January 1, 20232,073 295 454 293 121 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 recovery9 — 2 — — — — 11 — — — 11 
Extensions and discoveries170 55 — — — — — 225 — — — 225 
Purchases207 — 24 — — — — 231 — — — 231 
Sales(1)— — — — — — (1)— — — (1)
Production(259)(35)(72)(40)(15)(4)(18)(443)(102)— (1)(546)
Reserves at December 31, 2023 4, 5
1,942 324 445 301 107 53 598 3,770 1,004 — 3 4,777 
Changes attributable to:
Revisions2 (7)21 37 — — (4)49 (13)— — 36 
Improved recovery9 1 1 — — — — 11 — — — 11 
Extensions and discoveries185 52 4 — — — — 241 — — — 241 
Purchases21 — 51 — — — 16 88 — — — 88 
Sales(27)(46)— — — — (593)(666)— — — (666)
Production(286)(37)(67)(40)(15)(4)(17)(466)(104)— (1)(571)
Reserves at December 31, 2024 4, 5
1,846 287 455 298 92 49 — 3,027 887 — 2 3,916 
Changes attributable to:
Revisions1 (28)3 46 6 (10)— 18 16 — 1 35 
Improved recovery— 3 — — — — — 3 1 — — 4 
Extensions and discoveries148 89 2 — 8 — — 247 — — — 247 
Purchases392 473 3 3 — — — 871 — — — 871 
Sales(1)— (35)(1)— — — (37)— — — (37)
Production(331)(79)(53)(41)(13)(4)— (521)(145)— (1)(667)
Reserves at December 31, 2025 4, 5
2,055 745 375 305 93 35 — 3,608 759 — 2 4,369 
1 Ending reserve balances in North America were 125, 132 and 188 and in South America were 620, 155 and 136 in 2025, 2024 and 2023, respectively.
2 Reserves associated with Canada.
3 Reserves associated with Africa.
4 Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to page E-8 for the definition of a PSC). PSC-related reserve quantities are 18 percent, 8 percent and 6 percent for consolidated companies for 2025, 2024 and 2023, respectively.
5 Reserve quantities include synthetic oil projected to be consumed in operations of 0, 0, and 27 millions of barrels as of December 31, 2025, 2024 and 2023, respectively.

Noteworthy changes in NGLs proved reserves for 2023 through 2025 are discussed below and shown in the table on the following page:
Revisions In 2023, the 110 million barrels decrease in the United States was primarily in the Midland and Delaware basins with a decrease of 49 million barrels due to portfolio optimization and a decrease of 29 million barrels due to reservoir performance.
In 2024, the 41 million barrels decrease in the United States was primarily from a decrease of 65 million barrels in the DJ basin, which was partially offset by an increase of 31 million barrels from the Gulf of America.
Extensions and Discoveries In 2023, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 92 million barrels increase in the United States.
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In 2024, extensions and discoveries in the Midland and Delaware basins (72 million barrels), and in the DJ Basin (52 million barrels), were responsible for the 124 million barrels increase in the United States.
In 2025, extensions and discoveries in the Midland and Delaware basins of 81 million barrels were primarily responsible for the 103 million barrels increase in the United States.
Purchases In 2023, the acquisition of PDC in the DJ and Delaware basins was primarily responsible for the 262 million barrels increase in the United States.
In 2025, acquisition of Hess assets in North Dakota was primarily responsible for the 273 million barrels in the United States
Net Proved Reserves of Natural Gas Liquids
Consolidated CompaniesAffiliated CompaniesTotal
Consolidated
Otherand Affiliated
Millions of barrelsU.S.
Americas1
AfricaAsiaAustraliaEuropeTotalTCO
Other2
Companies
Reserves at January 1, 2023885 17 97 — 3 — 1,002 73 13 1,088 
Changes attributable to:
Revisions(110)— (6)— — — (116)12 2 (102)
Extensions and discoveries92 — — — — — 92 — — 92 
Purchases262 — 11 — — — 273 — — 273 
Sales— — — — — — — — — — 
Production(105)(2)(5)— (1)— (113)(7)(2)(122)
Reserves at December 31, 20233
1,024 15 97 — 2 — 1,138 78 13 1,229 
Changes attributable to:
Revisions(41)— (7)— — — (48)1 1 (46)
Extensions and discoveries124 — — — — — 124 — — 124 
Purchases20 — — — — — 20 — — 20 
Sales(3)(13)— — — — (16)— — (16)
Production(136)(2)(4)— (1)— (143)(7)(2)(152)
Reserves at December 31, 20243
988 — 86 — 1 — 1,075 72 12 1,159 
Changes attributable to:
Revisions3 — (15)— — — (12)(1)4 (9)
Extensions and discoveries103 — — — — — 103 — — 103 
Purchases273 — — — — — 273 — — 273 
Sales(3)— (1)— — — (4)— — (4)
Production(159)— (5)— — — (164)(8)(2)(174)
Reserves at December 31, 20253
1,205 — 65 — 1 — 1,271 63 14 1,348 
1 Reserves associated with North America.
2 Reserves associated with Africa.
3 Year-end reserve quantities related to PSC are not material for 2025, 2024 and 2023, respectively.
Noteworthy changes in natural gas proved reserves for 2023 through 2025 are discussed below and shown in the table on the following page:
Revisions In 2023, portfolio optimization decrease of 276 BCF and a reservoir performance decrease of 186 BCF in the Midland and Delaware basins along with a reduction in planned development activities leading to a decrease of 485 BCF in the Haynesville shale formation of East Texas, were mainly responsible for the 1.2 TCF decrease in the United States. In Asia, final investment decision on a new gas pipeline project in Israel and reservoir performance in Bangladesh were mainly responsible for the 481 BCF increase.
In 2024, a decrease of 425 BCF in the DJ Basin, primarily related to reservoir performance, was mainly responsible for the 572 BCF decrease in the United States. The 504 BCF increase in Australia was mainly due to reservoir performance of the Jansz Io field.
In 2025, an increase of 497 BCF in Australia was mainly attributable to reservoir performance of the Gorgon and Jansz Io fields. In Asia, the 479 BCF increase was primarily driven by reservoir performance in Bangladesh (285 BCF), and Thailand (112 BCF). The 227 BCF increase in the United States was primarily attributable to portfolio optimization in the Midland and Delaware basins.
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Extensions and Discoveries In 2023, extensions and discoveries of 660 BCF in the United States were primarily in the Midland and Delaware basins.
In 2024, extensions and discoveries of 912 BCF in the United States were primarily in the DJ Basin (476 BCF), and the Midland and Delaware basins (432 BCF).
In 2025, extensions and discoveries of 734 BCF in the United States were mainly in the Midland and Delaware basins (532 BCF), and the DJ Basin (199 BCF). The 715 BCF in Australia was primarily driven by the sanctioning of the Gorgon Stage 3 project.
Purchases In 2023, the acquisition of PDC in the DJ Basin was primarily responsible for the 2.2 TCF in the United States.
In 2024, the 177 BCF in the United States was primarily associated with the acquisition of PDC in the DJ Basin.
In 2025, the 1.1 TCF in the United States was primarily attributable to the acquisition of Hess assets in North Dakota. The acquisition of Hess interests in the Stabroek block in Guyana was the primary driver for the 213 BCF in Other Americas. The 210 BCF in Asia was primarily from the acquisition of Hess assets in Malaysia.
Sales In 2024, sales of 260 BCF in Other Americas were from the divestment of shale and tight assets in Canada.
Net Proved Reserves of Natural Gas
Consolidated CompaniesAffiliated CompaniesTotal
Consolidated
Otherand Affiliated
Billions of cubic feet (BCF)U.S.
Americas1
AfricaAsiaAustraliaEuropeTotalTCO
Other2
Companies
Reserves at January 1, 20236,831 545 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 recovery2 — — — — — 2 — — 2 
Extensions and discoveries660 83 — — — — 743 — — 743 
Purchases2,161 — 97 — — — 2,258 — — 2,258 
Sales(3)— — — — — (3)— — (3)
Production3
(771)(53)(176)(625)(978)(4)(2,607)(134)(86)(2,827)
Reserves at December 31, 2023 4, 5
7,682 574 2,257 8,393 9,395 17 28,318 1,295 768 30,381 
Changes attributable to:
Revisions(572)(54)(19)118 504 3 (20)(21)30 (11)
Improved recovery2 — — — — — 2 — — 2 
Extensions and discoveries912 119 83 — — — 1,114 — — 1,114 
Purchases177 — 32 — — — 209 — — 209 
Sales(70)(260)— — — — (330)— — (330)
Production3
(981)(65)(159)(600)(960)(2)(2,767)(136)(87)(2,990)
Reserves at December 31, 2024 4, 5
7,150 314 2,194 7,911 8,939 18 26,526 1,138 711 28,375 
Changes attributable to:
Revisions227 (56)(83)479 497 (3)1,061 (108)109 1,062 
Improved recovery— — — — — — — — — — 
Extensions and discoveries734 90 5 — 715 — 1,544 — — 1,544 
Purchases1,119 213 — 210 — — 1,542 — — 1,542 
Sales(59)— (24)(87)— — (170)— — (170)
Production3
(1,130)(34)(154)(589)(951)(3)(2,861)(135)(112)(3,108)
Reserves at December 31, 2025 4, 5
8,041 527 1,938 7,924 9,200 12 27,642 895 708 29,245 
1 Ending reserve balances in North America and South America were 45, 49 and 363 and 482, 265 and 211 in 2025, 2024 and 2023, respectively.
2 Reserves associated with Africa.
3 Total “as sold” volumes were 2,872, 2,768 and 2,609 for 2025, 2024 and 2023, respectively.
4 Includes reserve quantities related to PSC. PSC-related reserve quantities were 7 percent, 6 percent and 7 percent for consolidated companies for 2025, 2024 and 2023, respectively.
5 Reserve quantities include natural gas projected to be consumed in operations of 2,634, 2,462 and 2,655 billions of cubic feet as of December 31, 2025, 2024 and 2023, respectively.

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Table VI - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves
The standardized measure of discounted future net cash flows is calculated in accordance with SEC and FASB requirements. This includes using the unweighted arithmetic average of the first-day-of-the-month oil and gas prices for the 12-month period prior to the end of the reporting period, estimated future development and production costs assuming the continuation of existing economic conditions, estimated costs for asset retirement obligations (includes costs to retire existing wells and facilities in addition to those future wells and facilities necessary to produce proved undeveloped reserves), and estimated future income taxes based on appropriate statutory tax rates. Discounted future net cash flows are calculated using 10 percent mid-period discount factors. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. The valuation requires assumptions as to the timing and amount of future development and production costs, which could change over time as new information becomes available. The calculations are made as of December 31 each year and do not represent management’s estimate of the company’s future cash flows or value of its oil and gas reserves. In the following table, the caption “Standardized Measure Net Cash Flows” refers to the standardized measure of discounted future net cash flows.

Consolidated CompaniesAffiliated CompaniesTotal
Consolidated
Otherand Affiliated
Millions of dollarsU.S.AmericasAfricaAsiaAustraliaEuropeTotalTCOOtherCompanies
At December 31, 2025
Future cash inflows from production$169,215 $51,576 $31,211 $55,752 $81,208 $2,430 $391,392 $47,004 $5,814 $444,210 
Future production costs(76,479)(14,341)(18,366)(13,968)(11,588)(1,121)(135,863)(13,942)(584)(150,389)
Future development costs(14,702)(8,301)(3,303)(2,278)(6,639)(502)(35,725)(995)(81)(36,801)
Future income taxes(14,732)(7,983)(5,187)(23,444)(24,437)(339)(76,122)(9,620)(1,802)(87,544)
Undiscounted future net cash flows63,302 20,951 4,355 16,062 38,544 468 143,682 22,447 3,347 169,476 
10 percent midyear annual discount for timing of estimated cash flows
(21,371)(6,722)(973)(7,374)(14,357)(141)(50,938)(5,596)(1,120)(57,654)
Standardized Measure
Net Cash Flows
$41,931 $14,229 $3,382 $8,688 $24,187 $327 $92,744 $16,851 $2,227 $111,822 
At December 31, 2024
Future cash inflows from production$163,846 $21,827 $43,539 $58,245 $84,026 $3,999 $375,482 $65,221 $5,308 $446,011 
Future production costs(52,680)(5,896)(17,996)(13,355)(10,964)(1,188)(102,079)(19,945)(392)(122,416)
Future development costs(15,377)(2,131)(3,554)(2,290)(6,333)(420)(30,105)(1,560)(30)(31,695)
Future income taxes(18,919)(4,443)(12,345)(25,354)(25,891)(1,004)(87,956)(13,115)(1,710)(102,781)
Undiscounted future net cash flows76,870 9,357 9,644 17,246 40,838 1,387 155,342 30,601 3,176 189,119 
10 percent midyear annual discount for timing of estimated cash flows
(28,615)(3,492)(3,573)(8,157)(15,114)(503)(59,454)(8,722)(1,003)(69,179)
Standardized Measure
Net Cash Flows
$48,255 $5,865 $6,071 $9,089 $25,724 $884 $95,888 $21,879 $2,173 $119,940 
At December 31, 2023
Future cash inflows from production$181,152 $65,265 $42,786 $62,094 $99,003 $4,395 $454,695 $74,758 $7,324 $536,777 
Future production costs(48,784)(22,549)(16,502)(13,000)(11,534)(1,194)(113,563)(21,467)(484)(135,514)
Future development costs(16,938)(3,538)(4,474)(2,845)(5,804)(438)(34,037)(3,617)(67)(37,721)
Future income taxes(21,089)(10,337)(12,446)(27,415)(24,499)(1,160)(96,946)(14,902)(2,371)(114,219)
Undiscounted future net cash flows94,341 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 

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Table VII - Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves
The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities, 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 dollarsConsolidated CompaniesAffiliated CompaniesAffiliated Companies
Present Value at January 1, 2023$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 incurred11,381 2,281 13,662 
Purchases of reserves9,628 — 9,628 
Sales of reserves(51)— (51)
Extensions, discoveries and improved recovery less related costs7,262 — 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 discount23,306 5,722 29,028 
Net change in income tax 30,070 7,142 37,212 
Net Change for 2023(51,715)(15,215)(66,930)
Present Value at December 31, 2023$118,757 $26,251 $145,008 
Sales and transfers of oil and gas produced net of production costs(38,457)(6,242)(44,699)
Development costs incurred12,809 1,487 14,296 
Purchases of reserves1,607 — 1,607 
Sales of reserves(8,904)— (8,904)
Extensions, discoveries and improved recovery less related costs7,328 — 7,328 
Revisions of previous quantity estimates2,897 (154)2,743 
Net changes in prices, development and production costs(17,755)(1,898)(19,653)
Accretion of discount15,867 3,601 19,468 
Net change in income tax 1,739 1,007 2,746 
Net Change for 2024(22,869)(2,199)(25,068)
Present Value at December 31, 2024$95,888 $24,052 $119,940 
Sales and transfers of oil and gas produced net of production costs(38,786)(7,310)(46,096)
Development costs incurred13,035 597 13,632 
Purchases of reserves18,711 — 18,711 
Sales of reserves(1,181)— (1,181)
Extensions, discoveries and improved recovery less related costs8,368 — 8,368 
Revisions of previous quantity estimates6,688 1,466 8,154 
Net changes in prices, development and production costs(28,416)(5,040)(33,456)
Accretion of discount13,511 3,187 16,698 
Net change in income tax4,926 2,126 7,052 
Net Change for 2025(3,144)(4,974)(8,118)
Present Value at December 31, 2025$92,744 $19,078 $111,822 

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PART IV
Item 15. Exhibit and Financial Statement Schedules
(a)The following documents are filed as part of this report:
(1) Financial Statements:
Page(s)
62
65
66
67
68
69
70 through 107
 
(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, 2025.
(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 Dollars202520242023
Employee Termination Benefits
Balance at January 1$990 $6 $11 
Additions (reductions) charged to expense191 987 (2)
Payments(498)(3)(3)
Balance at December 31 $683 $990 $6 
Expected Credit Losses
Beginning allowance balance for expected credit losses$611 $641 $1,008 
Current period provision(83)(30)(367)
Write-offs charged against the allowance, if any(136)— — 
Balance at December 31 $392 $611 $641 
Deferred Income Tax Valuation Allowance*
Balance at January 1$21,313 $20,416 $19,532 
Additions to deferred income tax expense6,210 1,881 2,348 
Reduction of deferred income tax expense(662)(984)(1,464)
Balance at December 31 $26,861 $21,313 $20,416 
* See also Note 17 Taxes.
Item 16. Form 10-K Summary
Not applicable.
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EXHIBIT INDEX
Exhibit No.
Description
2.1
Agreement and Plan of Merger, dated as of October 22, 2023 among Chevron Corporation, Yankee Merger Sub Inc., and Hess Corporation, filed as Exhibit 2.1 to Chevron Corporation’s Current Report on Form 8-K filed October 23, 2023, and incorporated herein by reference.
3.1
Restated Certificate of Incorporation of Chevron Corporation, dated May 28, 2025, filed as Exhibit 3.1 to Chevron Corporation’s Current Report on Form 8-K filed May 30, 2025, and incorporated herein by reference.
3.2
By-Laws of Chevron Corporation, as amended and restated December 3, 2025, filed as Exhibit 3.2 to Chevron Corporation’s Current Report on Form 8-K filed December 5, 2025, and incorporated herein by reference.
4.1
Indenture, dated as of June 15, 1995, filed as Exhibit 4.1 to Chevron Corporation’s Amendment Number 1 to Registration Statement on Form S-3 filed June 14, 1995, and incorporated herein by reference.
4.2
Indenture, dated as of May 11, 2020, between Chevron Corporation and Deutsche Bank Trust Company Americas, as trustee, filed as Exhibit 4.1 to Chevron Corporation’s Current Report on Form 8-K filed May 12, 2020, and incorporated herein by reference.
4.3
Indenture, dated as of August 12, 2020, among Chevron U.S.A. Inc., Chevron Corporation, as guarantor, and Deutsche Bank Trust Company Americas, as trustee, filed as Exhibit 4.1 to Chevron Corporation’s Current Report on Form 8-K filed August 13, 2020, and incorporated herein by reference.
4.4
Confidential Stockholder Voting Policy of Chevron Corporation, filed as Exhibit 4.2 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.
4.5
Description of Securities Registered under Section 12 of the Exchange Act, filed as Exhibit 4.4 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2019, and incorporated herein by reference.
4.6
Fifth Supplemental Indenture, dated as of December 9, 2025, among Chevron U.S.A. Inc., Chevron Corporation, as guarantor, and Deutsche Bank Trust Company Americas, as trustee, filed as Exhibit 4.2 to Chevron Corporation’s Current Report on Form 8-K filed December 9, 2025, and incorporated herein by reference.
4.7
Form of Floating Rate Notes Due 2075 (contained in Exhibit 4.6 hereto).
10.1+
Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.1 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.
10.2+
Amendment Number One to the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, and incorporated herein by reference.
10.3+
Amendment Number Two to the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.3 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2024, and incorporated herein by reference.
10.4+
Form of Retainer Stock Option Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.17 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2009, and incorporated herein by reference.
10.5+
Form of Stock Units Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.19 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.
10.6+*
Chevron Incentive Plan, amended and restated effective January 1, 2026.
10.7+*
Summary of Chevron Incentive Plan Award Criteria.
10.8+
Long-Term Incentive Plan of Chevron Corporation, amended and restated effective October 2, 2023, filed as Exhibit 10.5 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2023, and incorporated herein by reference.
10.9+
Form of Non-Qualified Stock Option Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.8 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2014, and incorporated herein by reference.
10.10+
Form of Non-Qualified Stock Option Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed January 30, 2017, and incorporated herein by reference.
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Exhibit No. Description
10.11+
Form of Non-Qualified Stock Option Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed February 2, 2018, and incorporated herein by reference.
10.12+
Form of Standard Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.3 to Chevron Corporation’s Current Report on Form 8-K filed February 3, 2020, and incorporated herein by reference.
10.13+
Form of Non-Qualified Stock Option Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.2 to Chevron Corporation’s Current Report on Form 8-K filed February 3, 2020, and incorporated herein by reference.
10.14+
Chevron Corporation Deferred Compensation Plan for Management Employees, filed as Exhibit 10.5 to Chevron Corporation’s Current Report on Form 8-K filed December 13, 2005, and incorporated herein by reference.
10.15+*
Chevron Corporation Deferred Compensation Plan for Management Employees II, amended and restated effective January 1, 2026.
10.16+*
10.17+*
Chevron Corporation ESIP Restoration Plan, amended and restated effective January 1, 2026.
10.18+
Agreement between Chevron Corporation and R. Hewitt Pate, dated February 21, 2012, filed as Exhibit 10.16 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2011, and incorporated herein by reference.
10.19+
Agreement between Chevron Corporation and R. Hewitt Pate, dated December 13, 2018, filed as Exhibit 10.19 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2023, and incorporated herein by reference.
10.20+
Amended and Restated Aircraft Time-Sharing Agreement, dated as of November 16, 2024, between Chevron U.S.A. Inc. and Michael K. Wirth, filed as Exhibit 10.21 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2024, and incorporated herein by reference.
10.21+
Aircraft Time-Sharing Agreement, dated as of February 24, 2015, between Hess Corporation and John B. Hess, filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2025, and incorporated herein by reference.
10.22+*
Aircraft Time-Sharing Agreement, dated as of December 9, 2025, between JBH Ventures, LLC and Chevron Corporation.
10.23
Transition Services Agreement, dated as of July 14, 2025, between Chevron U.S.A. Inc. and HFO Holdings LLC, filed as Exhibit 10.2 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2025, and incorporated herein by reference.
10.24
Amendment One to Transition Services Agreement, dated as of August 27, 2025, between Chevron U.S.A. Inc. and HFO Holdings LLC, filed as Exhibit 10.3 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2025, and incorporated herein by reference.
10.25
Membership Interest Purchase Agreement, dated as of September 10, 2025, between Hess Corporation and JBH Ventures, LLC, filed as Exhibit 10.4 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2025, and incorporated herein by reference.
10.26*
Membership Interest Purchase Agreement (Membership Interest in HLOGO LLC), dated as of December 17, 2025, between Hess Corporation and John B. Hess.
10.27*
Membership Interest Purchase Agreement (Membership Interest in Hess Toy Truck LLC), dated as of December 17, 2025, between Hess Corporation and John B. Hess.
10.28+*
2022 Long-Term Incentive Plan of Chevron Corporation, amended and restated effective January 1, 2026.
10.29+
Form of Performance Share Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.
10.30+
Form of Standard Restricted Stock Unit Award Agreement (share settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.2 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.
10.31+
Form of Non-Qualified Stock Options Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.6 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.
123

Table of Contents


Exhibit No.Description
10.32+
Form of Stock Appreciation Right Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.7 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.
10.33+
Form of Performance Share Award Agreement (share settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed February 2, 2024, and incorporated herein by reference.
10.34+
Form of Standard Restricted Stock Unit Award Agreement (share settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.3 to Chevron Corporation’s Current Report on Form 8-K filed February 2, 2024, and incorporated herein by reference.
10.35+
Form of Non-Qualified Stock Options Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.7 to Chevron Corporation’s Current Report on Form 8-K filed February 2, 2024, and incorporated herein by reference.
10.36+
Form of Non-Qualified Stock Options Award Agreement (cashless) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.8 to Chevron Corporation’s Current Report on Form 8-K filed February 2, 2024, and incorporated herein by reference.
10.37+
Form of Stock Appreciation Right Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.9 to Chevron Corporation’s Current Report on Form 8-K filed February 2, 2024, and incorporated herein by reference.
10.38+*
Form of Performance Share Award Agreement (share settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation.
10.39+*
Form of Performance Share Award Agreement (cash settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation.
10.40+*
Form of Standard Restricted Stock Unit Award Agreement (share settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation.
10.41+*
Form of Standard Restricted Stock Unit Award Agreement (cash settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation.
19*
Insider Trading Policies and Procedures.
21.1*
Subsidiaries of Chevron Corporation (page E-1).
22.1*
Subsidiary Issuer of Guaranteed Securities.
23.1*
Consent of PricewaterhouseCoopers LLP (page E-2).
23.2*
Consent of DeGolyer and MacNaughton.
24.1*
Power of Attorney for certain directors of Chevron Corporation, authorizing the signing of the Annual Report on Form 10-K on their behalf.
31.1*
Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Executive Officer (page E-3).
31.2*
Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Financial Officer (page E-4).
  32.1**
Rule 13a-14(b)/15d-14(b) Certification by the company’s Chief Executive Officer (page E-5).
  32.2**
Rule 13a-14(b)/15d-14(b) Certification by the company’s Chief Financial Officer (page E-6).
97.1+
Chevron Corporation Dodd-Frank Clawback Policy, filed as Exhibit 97.1 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2023, and incorporated herein by reference.
99.1*
Definitions of Selected Energy and Financial Terms (pages E-7 through E-11).
99.2*
Report of DeGolyer and MacNaughton.
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.
124


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 24th day of February, 2026.
 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 24th day of February, 2026.
 
Principal Executive Officer
(and Director)
/s/ MICHAEL K. WIRTH
Michael K. Wirth, Chairman of the
Board and Chief Executive Officer
Principal Financial Officer
/s/ EIMEAR P. BONNER
Eimear P. Bonner, Chief Financial Officer
Principal Accounting Officer
/s/ ALANA K. KNOWLES
Alana K. Knowles, 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
ENRIQUE HERNANDEZ, JR.*
Enrique Hernandez, Jr.
JOHN B. HESS*
John B. Hess
MARILLYN A. HEWSON*
Marillyn A. Hewson
THOMAS W. HORTON*
Thomas W. Horton
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
125

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