Management’s Discussion and Analysis of
Financial Condition and Results of Operations
Key Financial Results
Earnings by Major Operating Area
Business Environment and Outlook
Noteworthy Developments
Results of Operations
Consolidated Statement of Income
Selected Operating Data
Liquidity and Capital Resources
Financial Ratios and Metrics
Financial and Derivative Instrument Market Risk
Transactions With Related Parties
Litigation and Other Contingencies
Environmental Matters
Critical Accounting Estimates and Assumptions
New Accounting Standards
Quarterly Results
Consolidated Financial Statements
Reports of Management
Report of Independent Registered Public Accounting Firm (PCAOB ID: 238 )
Consolidated Statement of Income
Consolidated Statement of Comprehensive Income
Consolidated Balance Sheet
Consolidated Statement of Cash Flows
Consolidated Statement of Equity
Notes to the Consolidated Financial Statements
Note 1
Summary of Significant Accounting Policies
Note 2
Changes in Accumulated Other
Comprehensive Losses
Note 3
Information Relating to the Consolidated Statement of Cash Flows
Note 4
New Accounting Standards
Note 5
Lease Commitments
Note 6
Summarized Financial Data - Chevron U.S.A. Inc.
Note 7
Summarized Financial Data - Tengizchevroil LLP
Note 8
Restructuring and Reorganization Costs
Note 9
Fair Value Measurements
Note 10
Financial and Derivative Instruments
Note 11
Assets Held for Sale
Note 12
Equity
Note 13
Earnings Per Sha re
Note 14
Operating Segments and Geographic Data
Note 15
Investments and Advances
Note 16
Litigation
Note 17
Taxes
Note 18
Properties, Plant and Equipment
Note 19
Short-Term Debt
Note 20
Long-Term Debt
Note 21
Accounting for Suspended Exploratory Wells
Note 22
Stock Options and Other Share-Based Compensation
Note 23
Employee Benefit Plans
Note 24
Other Contingencies and Commitments
Note 25
Asset Retirement Obligations
Note 26
Revenue
Note 27
Other Financial Information
Note 28
Financial Instruments - Credit Losses
Note 29
Acquisition of Hess Corporation
Supplemental Information on Oil and Gas Producing Activities
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Key Financial Results
Millions of dollars, except per-share amounts
Net Income (Loss) Attributable to Chevron Corporation
Per Share Amounts:
Net Income (Loss) Attributable to Chevron Corporation
– Basic
– Diluted
Dividends
Sales and Other Operating Revenues
Return on:
Capital Employed
Stockholders’ Equity
Earnings by Major Operating Area
Millions of dollars
Upstream
United States
International
Total Upstream
Downstream
United States
International
Total Downstream
All Other
Net Income (Loss) Attributable to Chevron Corporation 1,2
1 Includes foreign currency effects:
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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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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• Oil production GHG intensity of 24 kilograms (kg) carbon dioxide equivalent per barrel of oil-equivalent (CO 2 e/boe),
• Gas production GHG intensity of 24 kg CO 2 e/boe,
• Methane intensity of 2 kg CO 2 e/boe, and
• Flaring GHG intensity of 3 kg CO 2 e/boe.
The company also targets 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 (CO 2 e) 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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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.
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 and the time between initial exploration and the beginning of production.
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Net crude oil production
Thousands of barrels per day
Affiliates
Europe
Australia
Asia
Africa
Other Americas
United States
Net natural gas liquids production
Thousands of barrels per day
Affiliates
Europe
Australia
Asia
Africa
Other Americas
United States
Net natural gas production
Millions of cubic feet per day
Affiliates
Europe
Australia
Asia
Africa
Other Americas
United States
Net proved reserves by geographic area
Billions of BOE*
Affiliates
Europe
Australia
Asia
Africa
Other Americas
United States
*barrels of oil-equivalent
Net proved reserves by product
Billions of BOE*
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
United States
International
Worldwide Downstream earnings
Billions of dollars
United States
International
U.S. refined product sales
Thousands of barrels per day
Other
Fuel oil
Diesel/Gas oil
Jet fuel
Gasoline
International refined product sales*
Thousands of barrels per day
Other
Fuel oil
Diesel/Gas oil
Jet fuel
Gasoline
*includes equity share in affiliates
U.S. Upstream
Unit *
Earnings
Net Oil-Equivalent Production
MBOED
Liquids Production
MBD
Natural Gas Production
MMCFD
Liquids Realization
$/BBL
Natural Gas Realization
$/MCF
* 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
Unit 2
Earnings 1
Net Oil-Equivalent Production
MBOED
Liquids Production
MBD
Natural Gas Production
MMCFD
Liquids Realization
$/BBL
Natural Gas Realization
$/MCF
1 Includes foreign currency effects:
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 *
Earnings
Refinery Crude Unit Inputs
MBD
Refined Product Sales
MBD
* 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
Earnings 1
Refinery Crude Unit Inputs
MBD
Refined Product Sales
MBD
1 Includes foreign currency effects:
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
Unit
Net charges *
* Includes foreign currency effects:
All Other consists of worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology companies.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents
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 dollars
Sales and other operating revenues
Sales and other operat ing 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 dollars
Income (loss) from equity affiliates
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 dollars
Other income (loss)
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 dollars
Purchased crude oil and products
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 dollars
Operating, selling, general and administrative expenses
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 dollars
Exploration expense
Exploration expenses in 2025 were relatively flat compared to last year.
Millions of dollars
Depreciation, depletion and amortization
Depreciation, depletion and amortization expenses increased in 2025 primarily due to higher production and higher rates.
Millions of dollars
Taxes other than on income
Taxes other than on income increased in 2025 primarily due to higher excise taxes related to downstream activities.
Millions of dollars
Interest and debt expense
Interest and debt expenses increased in 2025 mainly due to higher debt balances, including debt assumed from the acquisition of Hess.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents
Millions of dollars
Other components of net periodic benefit costs
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 dollars
Income tax expense (benefit)
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 .
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents
Selected Operating Data 1,2
Unit
U.S. Upstream
Net Crude Oil and Natural Gas Liquids (NGLs) Production
MBD
Net Natural Gas Production 3
MMCFD
Net Oil-Equivalent Production
MBOED
Sales of Natural Gas 4
MMCFD
Sales of Natural Gas Liquids
MBD
Revenues from Net Production
Crude
$/BBL
NGLs
$/BBL
Liquids (weighted average of Crude and NGLs)
$/BBL
Natural Gas
$/MCF
International Upstream
Net Crude Oil and NGLs Production 5
MBD
Net Natural Gas Production 3
MMCFD
Net Oil-Equivalent Production 5
MBOED
Sales of Natural Gas
MMCFD
Sales of Natural Gas Liquids
MBD
Revenues from Liftings
Crude
$/BBL
NGLs
$/BBL
Liquids (weighted average of Crude and NGLs)
$/BBL
Natural Gas
$/MCF
Worldwide Upstream
Net Oil-Equivalent Production 5
United States
MBOED
International
MBOED
Total
MBOED
U.S. Downstream
Gasoline Sales 6
MBD
Other Refined Product Sales
MBD
Total Refined Product Sales
MBD
Sales of Natural Gas 4
MMCFD
Sales of Natural Gas Liquids
MBD
Refinery Crude Unit Inputs 8
MBD
International Downstream
Gasoline Sales 6
MBD
Other Refined Product Sales
MBD
Total Refined Product Sales 7
MBD
Sales of Natural Gas 4
MMCFD
Sales of Natural Gas Liquids
MBD
Refinery Crude Unit Inputs 8
MBD
1 Includes company share of equity affiliates.
2 MBD – thousands of barrels per day; MMCFD – millions of cubic feet per day; MBOED – thousands of barrels of oil-equivalents per day; Bbl – barrel; MCF – thousands of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil; MBOED - thousands of barrels of oil-equivalent per day.
3 Includes natural gas consumed in operations:
United States
MMCFD
International
MMCFD
4 Downstream sales of Natural Gas separately identified from Upstream.
5 Includes net production of synthetic oil:
Canada
MBD
6 Includes branded and unbranded gasoline.
7 Includes sales of affiliates:
MBD
8 Includes crude oil and other inputs.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents
Liquidity and Capital Resources
Sources and Uses of Cash The strength of the company’s balance sheet enables it to fund any timing differences throughout the year between cash inflows and outflows.
Cash, Cash Equivalents and Marketable Securities Total balances were $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).
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents
Cash from operating activities compared with capital expenditures and cash returned to shareholders
Billions of dollars
Hess stock purchase
Stock repurchases
Capital expenditures
Dividends
Cash from operating activities
Capital expenditures by segment
Billions of dollars
All Other
Downstream
Upstream
Affiliate capital expenditures
Billions of dollars
Downstream
Upstream
Debt at year-end
Billions of dollars
Total debt
Net debt*
*Refer to page 52 for calculations of debt and debt ratios
Debt coverage ratios
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,
(Millions of dollars) (unaudited)
Sales and other operating revenues
Sales and other operating revenues - related party
Total costs and other deductions
Total costs and other deductions - related party
Net income (loss)
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents
At December 31,
(Millions of dollars) (unaudited)
Current assets
Current assets - related party
Other assets
Current liabilities
Current liabilities - related party
Other liabilities
Total net equity (deficit)
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
Capex
Millions of dollars
Int’l.
Total
Int’l.
Total
Int’l.
Total
Upstream
Downstream
All Other
Capex
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:
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents
Year ended December 31
Affiliate Capex
Millions of dollars
Int’l.
Total
Int’l.
Total
Int’l.
Total
Upstream
Downstream
All Other
Affiliate Capex
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.”
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents
Financial Ratios and Metrics
The following represent several metrics the company believes are useful measures to monitor the financial health of the company and its performance over time:
Current Ratio Current assets divided by current liabilities, which indicates the company’s ability to repay its short-term liabilities with short-term assets. The current ratio in all periods is adversely affected by the fact that Chevron’s inventories are valued on a last-in, first-out basis. At year-end 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 dollars
Current assets
Current liabilities
Current Ratio
Interest Coverage Ratio Income before income tax expense, plus interest and debt expense and amortization of capitalized interest, less net income attributable to noncontrolling interests, divided by before-tax interest costs. This ratio indicates the company’s ability to pay interest on outstanding debt.
Year ended December 31
Millions of dollars
Income (Loss) Before Income Tax Expense
Plus: Interest and debt expense
Plus: Before-tax amortization of capitalized interest
Less: Net income attributable to noncontrolling interests
Subtotal for calculation
Total financing interest and debt costs
Interest Coverage Ratio
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 dollars
Net cash provided by operating activities
Less: Capital expenditures
Free Cash Flow
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 dollars
Net cash provided by operating activities
Less: Capital expenditures
Free Cash Flow
Less: Net decrease (increase) in operating working capital
Plus: Proceeds and deposits related to asset sales and returns of investment
Plus: Net repayment (borrowing) of loans by equity affiliates
Adjusted Free Cash Flow
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents
Debt Ratio Total debt as a percentage of total debt plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage.
At December 31
Millions of dollars
Short-term debt
Long-term debt
Total debt
Total Chevron Corporation Stockholders’ Equity
Total debt plus total Chevron Corporation Stockholders’ Equity
Debt Ratio
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 dollars
Short-term debt
Long-term debt
Total debt
Less: Cash and cash equivalents
Less: Time deposits
Less: Marketable securities
Total net debt
Total Chevron Corporation Stockholders’ Equity
Total net debt plus total Chevron Corporation Stockholders’ Equity
Net Debt Ratio
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 dollars
Short-term debt
Long-term debt
Total debt
Net cash provided by operating activities (CFFO)
Debt-to-CFFO
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 dollars
Short-term debt
Long-term debt
Total debt
Less: Cash and cash equivalents
Less: Time deposits
Less: Marketable securities
Total net debt
Net cash provided by operating activities (CFFO)
Net Debt-to-CFFO
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents
Capital Employed The sum of Chevron Corporation Stockholders’ Equity, total debt and noncontrolling interests, which represents the net investment in the business.
At December 31
Millions of dollars
Chevron Corporation Stockholders’ Equity
Plus: Short-term debt
Plus: Long-term debt
Plus: Noncontrolling interest
Capital Employed at December 31
Return on Average Capital Employed (ROCE) Net income attributable to Chevron (adjusted for after-tax interest expense and noncontrolling interest) divided by average capital employed. Average capital employed is computed by averaging the sum of capital employed at the beginning and end of the year. ROCE is a ratio intended to measure annual earnings as a percentage of historical investments in the business.
Year ended December 31
Millions of dollars
Net income attributable to Chevron
Plus: After-tax interest and debt expense
Plus: Noncontrolling interest
Net income after adjustments
Average capital employed
Return on Average Capital Employed
Return on Stockholders ’ Equity (ROSE) Net income attributable to Chevron divided by average Chevron Corporation Stockholders’ Equity. Average stockholders’ equity is computed by averaging the sum of stockholders’ equity at the beginning and end of the year. ROSE is a ratio intended to measure earnings as a percentage of shareholder investments.
Year ended December 31
Millions of dollars
Net income attributable to Chevron
Chevron Corporation Stockholders’ Equity at December 31
Average Chevron Corporation Stockholders’ Equity
Return on Average Stockholders’ Equity
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.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents
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
Balance at January 1
Net additions
Expenditures
Balance at December 31
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.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Table of Contents
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 on a held-and-used basis could possibly become if a decision is made to sell such assets. That is, the assets would be 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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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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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.
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Quarterly Results
Unaudited
Millions of dollars, except per-share amounts
Revenues and Other Income
Sales and other operating revenues
Income from equity affiliates
Other income (loss)
Total Revenues and Other Income
Costs and Other Deductions
Purchased crude oil and products
Operating expenses
Selling, general and administrative expenses
Exploration expenses
Depreciation, depletion and amortization
Taxes other than on income
Interest and debt expense
Other components of net periodic benefit costs
Total Costs and Other Deductions
Income (Loss) Before Income Tax Expense
Income Tax Expense (Benefit)
Net Income (Loss)
Less: Net income (loss) attributable to noncontrolling interests
Net Income (Loss) Attributable to Chevron Corporation
Per Share of Common Stock
Net Income (Loss) Attributable to Chevron Corporation
– Basic
– Diluted
Dividends per share
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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. Wirth
Eimear P. Bonner
Alana K. Knowles
Chairman of the Board
Chief Financial Officer
Controller
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
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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.
Consolidated Statement of Income
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Millions of dollars, except per-share amounts
Year ended December 31
Revenues and Other Income
Sales and other operating revenues
Income (loss) from equity affiliates
Other income (loss)
Total Revenues and Other Income
Costs and Other Deductions
Purchased crude oil and products
Operating expenses
Selling, general and administrative expenses
Exploration expenses
Depreciation, depletion and amortization
Taxes other than on income
Interest and debt expense
Other components of net periodic benefit costs
Total Costs and Other Deductions
Income (Loss) Before Income Tax Expense
Income Tax Expense (Benefit)
Net Income (Loss)
Less: Net income (loss) attributable to noncontrolling interests
Net Income (Loss) Attributable to Chevron Corporation
Per Share of Common Stock
Net Income (Loss) Attributable to Chevron Corporation
- Basic
- Diluted
See accompanying Notes to the Consolidated Financial Statements.
Consolidated Statement of Comprehensive Income
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Millions of dollars
Year ended December 31
Net Income (Loss)
Currency translation adjustment
Unrealized net change arising during period
Unrealized holding gain (loss) on securities
Net gain (loss) arising during period
Derivatives
Net derivatives gain (loss) on hedge transactions
Reclassification to net income
Income tax benefit (cost) on derivatives transactions
Total
Defined benefit plans
Actuarial gain (loss)
Amortization to net income of net actuarial loss and settlements
Actuarial gain (loss) arising during period
Prior service credits (cost)
Amortization to net income of net prior service costs and curtailments
Prior service (costs) credits arising during period
Defined benefit plans sponsored by equity affiliates - benefit (cost)
Income tax benefit (cost) on defined benefit plans
Total
Other Comprehensive Gain (Loss), Net of Tax
Comprehensive Income (Loss)
Comprehensive loss (income) attributable to noncontrolling interests
Comprehensive Income (Loss) Attributable to Chevron Corporation
See accompanying Notes to the Consolidated Financial Statements.
Consolidated Balance Sheet
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Millions of dollars, except per-share amounts
At December 31
Assets
Cash and cash equivalents
Time deposits
Marketable securities
Accounts and notes receivable (less allowance: 2025 - $ 176 ; 2024 - $ 259 )
Inventories:
Crude oil and products
Chemicals
Materials, supplies and other
Total inventories
Prepaid expenses and other current assets
Total Current Assets
Long-term receivables, net (less allowances: 2025 - $ 216 ; 2024 - $ 352 )
Investments and advances
Properties, plant and equipment, at cost
Less: Accumulated depreciation, depletion and amortization
Properties, plant and equipment, net
Deferred charges and other assets
Goodwill
Assets held for sale
Total Assets
Liabilities and Equity
Short-term debt
Accounts payable
Accrued liabilities
Federal and other taxes on income
Other taxes payable
Total Current Liabilities
Long-term debt 1
Deferred credits and other noncurrent obligations
Noncurrent deferred income taxes
Noncurrent employee benefit plans
Total Liabilities 2
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)
Capital in excess of par value
Retained earnings
Accumulated other comprehensive losses
Deferred compensation and benefit plan trust
Treasury stock, at cost (2025 - 448,260,458 shares; 2024 - 673,664,306 shares)
Total Chevron Corporation Stockholders’ Equity
Noncontrolling interests
Total Equity
Total Liabilities and Equity
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.
Consolidated Statement of Cash Flows
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Millions of dollars
Year ended December 31
Operating Activities
Net Income (Loss)
Adjustments
Depreciation, depletion and amortization
Dry hole expense
Distributions more (less) than income from equity affiliates
Net before-tax gains on asset retirements and sales
Net foreign currency effects
Deferred income tax provision
Net decrease (increase) in operating working capital
Decrease (increase) in long-term receivables
Net decrease (increase) in other deferred charges
Cash contributions to employee pension plans
Other
Net Cash Provided by Operating Activities
Investing Activities
Acquisition of businesses, net of cash received
Acquisition of Hess Corporation common stock
Capital expenditures
Proceeds and deposits related to asset sales and returns of investment
Net maturities of (investments in) time deposits
Net sales (purchases) of marketable securities
Net repayment (borrowing) of loans by equity affiliates
Net Cash Used for Investing Activities
Financing Activities
Net borrowings (repayments) of short-term obligations
Proceeds from issuances of long-term debt
Repayments of long-term debt and other financing obligations
Cash dividends - common stock
Net contributions from (distributions to) noncontrolling interests
Net sales (purchases) of treasury shares
Net Cash Provided by (Used for) Financing Activities
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash
Net Change in Cash, Cash Equivalents and Restricted Cash
Cash, Cash Equivalents and Restricted Cash at January 1
Cash, Cash Equivalents and Restricted Cash at December 31
See accompanying Notes to the Consolidated Financial Statements.
Consolidated Statement of Equity
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Acc. Other
Treasury
Chevron Corp.
Common
Retained
Comprehensive
Stock
Stockholders’
Noncontrolling
Total
Stock 1
Earnings
Income (Loss)
( at cost )
Equity
Interests
Equity
Balance at December 31, 2022
Treasury stock transactions
PDC Energy, Inc. acquisition
Net income (loss)
Cash dividends ($ 6.04 per share)
Stock dividends
Other comprehensive income
Purchases of treasury shares
Issuances of treasury shares
Other changes, net
Balance at December 31, 2023
Treasury stock transactions
Net income (loss)
Cash dividends ($ 6.52 per share)
Stock dividends
Other comprehensive income
Purchases of treasury shares
Issuances of treasury shares
Other changes, net
Balance at December 31, 2024
Treasury stock transactions
Hess Corporation acquisition
Net income (loss)
Cash dividends ($ 6.84 per share)
Stock dividends
Other comprehensive income
Purchases of treasury shares 2
Issuances of treasury shares
Other changes, net
Balance at December 31, 2025
Common Stock Share Activity
Issued 3
Treasury
Outstanding
Balance at December 31, 2022
Purchases
Issuances
Balance at December 31, 2023
Purchases
Issuances
Balance at December 31, 2024
Purchases
Issuances
Balance at December 31, 2025
1 Beginning and ending balances for all periods include capital in excess of par, common stock issued at par for $ 1,832 , and $( 240 ) associated with Chevron’s Benefit Plan Trust. Changes reflect capital in excess of par.
2 Includes excise tax on share repurchases.
3 Beginning and ending total issued share balances include 14,168,000 shares associated with Chevron’s Benefit Plan Trust.
See accompanying Notes to the Consolidated Financial Statements.
Notes to the Consolidated Financial Statements
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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
Notes to the Consolidated Financial Statements
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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
Notes to the Consolidated Financial Statements
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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
Notes to the Consolidated Financial Statements
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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 Adjustments
Unrealized Holding Gains (Losses) on Securities
Derivatives
Defined Benefit Plans
Total
Balance at December 31, 2022
Components of Other Comprehensive Income (Loss) 1 :
Before Reclassifications
Reclassifications 2, 3
Net Other Comprehensive Income (Loss)
Balance at December 31, 2023
Components of Other Comprehensive Income (Loss) 1 :
Before Reclassifications
Reclassifications 2, 3
Net Other Comprehensive Income (Loss)
Balance at December 31, 2024
Components of Other Comprehensive Income (Loss) 1 :
Before Reclassifications
Reclassifications 2, 3
Net Other Comprehensive Income (Loss)
Balance at December 31, 2025
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.
Notes to the Consolidated Financial Statements
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Note 3
Information Relating to the Consolidated Statement of Cash Flows
Year ended December 31
Distributions more (less) than income from equity affiliates includes the following:
Distributions from equity affiliates
(Income) loss from equity affiliates
Distributions more (less) than income from equity affiliates
Net decrease (increase) in operating working capital was composed of the following:
Decrease (increase) in accounts and notes receivable
Decrease (increase) in inventories
Decrease (increase) in prepaid expenses and other current assets
Increase (decrease) in accounts payable and accrued liabilities
Increase (decrease) in income and other taxes payable
Net decrease (increase) in operating working capital
Net cash provided by operating activities includes the following cash payments:
Interest on debt (net of capitalized interest)
Income taxes
Proceeds and deposits related to asset sales and returns of investment consisted of the following gross amounts:
Proceeds and deposits related to asset sales
Returns of investment from equity affiliates
Proceeds and deposits related to asset sales and returns of investment
Net maturities (investments) of time deposits consisted of the following gross amounts:
Investments in time deposits
Maturities of time deposits
Net maturities of (investments in) time deposits
Net sales (purchases) of marketable securities consisted of the following gross amounts:
Marketable securities purchased
Marketable securities sold
Net sales (purchases) of marketable securities
Net repayment (borrowing) of loans by equity affiliates:
Borrowing of loans by equity affiliates
Repayment of loans by equity affiliates
Net repayment (borrowing) of loans by equity affiliates
Net borrowings (repayments) of short-term obligations consisted of the following gross and net amounts:
Repayments of short-term obligations
Proceeds from issuances of short-term debt obligations
Net borrowings (repayments) of short-term obligations with three months or less maturity
Net borrowings (repayments) of short-term obligations
Net sales (purchases) of treasury shares consists of the following gross and net amounts:
Shares issued for share-based compensation plans
Shares purchased under share repurchase and deferred compensation plans
Share repurchase excise tax payments
Net sales (purchases) of treasury shares
Net contributions from (distributions to) noncontrolling interests consisted of the following gross and net amounts:
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Net contributions from (distributions to) noncontrolling interests
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.
Notes to the Consolidated Financial Statements
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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
Additions to properties, plant and equipment *
Additions to investments
Current-year dry hole expenditures
Payments for other assets and liabilities, net
Capital expenditures
* 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
Cash and cash equivalents
Restricted cash included in “Prepaid expenses and other current assets”
Restricted cash included in “Deferred charges and other assets”
Total cash, cash equivalents and restricted cash
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.
Notes to the Consolidated Financial Statements
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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, 2025
At December 31, 2024
Operating
Leases
Finance
Leases
Operating
Leases
Finance
Leases
Deferred charges and other assets
Properties, plant and equipment, net
Right-of-use assets*
Accrued liabilities
Short-term debt
Current lease liabilities
Deferred credits and other noncurrent obligations
Long-term debt
Noncurrent lease liabilities
Total lease liabilities
Weighted-average remaining lease term (in years)
Weighted-average discount rate
* 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
Operating lease costs*
Finance lease costs
Total lease costs
* Includes variable and short-term lease costs.
Cash paid for amounts included in the measurement of lease liabilities was as follows:
Year-ended December 31
Operating cash flows from operating leases
Investing cash flows from operating leases
Operating cash flows from finance leases
Financing cash flows from finance leases
At December 31, 2025, the estimated future undiscounted cash flows for operating and finance leases were as follows:
At December 31, 2025
Operating Leases
Finance
Leases
Year
Thereafter
Total
Less: Amounts representing interest
Total lease liabilities
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
Notes to the Consolidated Financial Statements
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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
Sales and other operating revenues
Total costs and other deductions
Net income (loss) attributable to CUSA
At December 31
Current assets
Other assets
Current liabilities
Other liabilities
Total CUSA net equity
Memo: Total debt
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
Sales and other operating revenues
Costs and other deductions
Net income attributable to TCO
At December 31
Current assets
Other assets
Current liabilities
Other liabilities
Total TCO net equity
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
Accruals/Adjustments
Payments
Balance at December 31, 2025
Notes to the Consolidated Financial Statements
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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, 2025
At December 31, 2024
Total
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Marketable securities
Derivatives - not designated
Derivatives - designated
Total assets at fair value
Derivatives - not designated
Derivatives - designated
Total liabilities at fair value
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
At December 31
At December 31
Before-Tax Loss
Before-Tax Loss
Total
Level 1
Level 2
Level 3
Year 2025
Total
Level 1
Level 2
Level 3
Year 2024
Properties, plant and equipment, net (held and used)
Properties, plant and equipment, net (held for sale)
Investments and advances
Total nonrecurring assets at fair value
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
Notes to the Consolidated Financial Statements
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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 Contract
Balance Sheet Classification
Commodity
Accounts and notes receivable
Commodity
Long-term receivables, net
Total assets at fair value
Commodity
Accounts payable
Commodity
Deferred credits and other noncurrent obligations
Total liabilities at fair value
Consolidated Statement of Income: The Effect of Derivatives
Gain/(Loss)
Year ended December 31
Type of Contract
Statement of Income Classification
Commodity
Sales and other operating revenues
Commodity
Purchased crude oil and products
Commodity
Other income (loss)
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
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
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 Recognized
Gross Amounts Offset
Net Amounts Presented
Gross Amounts Not Offset
Net Amounts
At December 31, 2025
Derivative Assets - not designated
Derivative Assets - designated
Derivative Liabilities - not designated
Derivative Liabilities - designated
At December 31, 2024
Derivative Assets - not designated
Derivative Assets - designated
Derivative Liabilities - not designated
Derivative Liabilities - designated
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 classifie d $ 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:
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
Year ended December 31
Basic EPS Calculation
Earnings available to common stockholders - Basic *
Weighted-average number of common shares outstanding
Add: Deferred awards held as stock units
Total weighted-average number of common shares outstanding
Earnings per share of common stock - Basic
Diluted EPS Calculation
Earnings available to common stockholders - Diluted *
Weighted-average number of common shares outstanding
Add: Deferred awards held as stock units
Add: Dilutive effect of employee stock-based awards
Total weighted-average number of common shares outstanding
Earnings per share of common stock - Diluted
* 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
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
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:
Upstream
Downstream
Segment Total
All Other
Total
Year Ended December 31, 2025
Int'l.
Int'l.
Sales and other operating revenues before elimination
Intersegment revenue elimination
Sales and Other Operating Revenues
Income (loss) from equity affiliates
Other income (loss) 1
Total Revenues and Other Income
Intersegment product transfers 2
Less expenses:
Purchased crude oil and products
Operating and SG&A expenses
Depreciation, depletion and amortization
Other costs and deductions 3
Total Costs and Other Deductions
Income Tax Expense (Benefit)
Less: Net income (loss) attributable to non-controlling interests
Net Income (Loss) Attributable to Chevron Corporation
Values have been adjusted for eliminations, unless otherwise specified.
1 Includes interest income of $ 257 in “All Other.”
2 Valuation of product transfers between operating segments.
3 Includes interest expense of $ 1,096 in “All Other.”
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
Upstream
Downstream
Segment Total
All Other
Total
Year ended December 31, 2024
Int'l.
Int'l.
Sales and other operating revenues before elimination
Intersegment revenue elimination
Sales and Other Operating Revenues
Income (loss) from equity affiliates
Other income (loss) 1
Total Revenues and Other Income
Intersegment product transfers 2
Less expenses:
Purchased crude oil and products
Operating and SG&A expenses
Depreciation, depletion and amortization
Other costs and deductions 3
Total Costs and Other Deductions
Income Tax Expense (Benefit)
Less: Net income (loss) attributable to non-controlling interests
Net Income (Loss) Attributable to Chevron Corporation
Values have been adjusted for eliminations, unless otherwise specified.
1 Includes interest income of $ 296 in “All Other.”
2 Valuation of product transfers between operating segments.
3 Includes interest expense of $ 539 in “All Other.”
Upstream
Downstream
Segment Total
All Other
Total
Year Ended December 31, 2023
Int'l.
Int'l.
Sales and other operating revenues before elimination
Intersegment revenue elimination
Sales and Other Operating Revenues
Income (loss) from equity affiliates
Other income (loss) 1
Total Revenues and Other Income
Intersegment product transfers 2
Less expenses:
Purchased crude oil and products
Operating and SG&A expenses
Depreciation, depletion and amortization
Other costs and deductions 3
Total Costs and Other Deductions
Income Tax Expense (Benefit)
Less: Net income (loss) attributable to non-controlling interests
Net Income (Loss) Attributable to Chevron Corporation
Values have been adjusted for eliminations, unless otherwise specified.
1 Includes interest income of $ 491 in “All Other.”
2 Valuation of product transfers between operating segments.
3 Includes interest expense of $ 432 in “All Other.”
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
Segment Assets Segment assets do not include intercompany investments or receivables. Assets at year-end 2025 and 2024 are as follows:
At December 31
Upstream
United States
International
Goodwill
Total Upstream
Downstream
United States
International
Goodwill
Total Downstream
Total Segment Assets
All Other
United States
International
Total All Other
Total Assets – United States
Total Assets – International
Goodwill
Total Assets
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 Advances
Equity in Earnings
At December 31
Year ended December 31
Upstream
Tengizchevroil
Caspian Pipeline Consortium
Angola LNG Limited
Other
Total Upstream
Downstream
Chevron Phillips Chemical Company LLC
GS Caltex Corporation
Other
Total Downstream
All Other
Other
Total equity method
Other non-equity method investments
Total investments and advances
Total United States
Total International
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
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 i ncludes $ 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.
Affiliates
Chevron Share
Year ended December 31
Total revenues
Income before income tax expense*
Net income attributable to affiliates
At December 31
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
Total affiliates’ net equity
* Chevron’s net income attributable to affiliates is recorded in the company’s before-tax consolidated earnings in accordance with U.S. Generally Accepted Accounting Principles. The total income tax expense recorded by the company’s equity affiliates in 2025 was $ 1,661 , with Chevron’s share being $ 730 .
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
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, of public trust, equitable relief for pollution, and of natural resources, enrichment, of consumer and environmental protection statutes, of competition statutes, of a federal statute, and of federal and state RICO statutes, based upon, among other things, the company’s production of oil and gas products and or relating to climate change risks associated with those products. Further such lawsuits are likely to be brought by other parties. While 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 petitions for certiorari on the of whether federal courts have jurisdiction over those cases. The U.S. Supreme Court has also certiorari to review a decision from the Hawaii Supreme Court allowing brought by the City and County of Honolulu to proceed past the . 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 of whether federal law state‑law seeking relief for 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 for (both compensatory and ), injunctive and other forms of equitable relief, including without abatement, contribution to abatement funds, of profits and equitable relief for pollution, and of natural resources, civil and liability for fees and costs of suits. Due to the unprecedented nature of the suits, the company is to estimate any range of possible liability, but given the uncertainty of there can be no assurance that the cases will not have a material effect on the company’s results of operations and financial condition. Management believes that these lawsuits are legally and factually meritless and from efforts to address the important policy issues presented by climate change and will vigorously 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 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.) ( 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 ); 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.) ( on the merits; ’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.) ( on the merits; ’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 ); City of New York v. Chevron Corp., et al. , No. 18-cv-00182 (S.D.N.Y.) ( on the merits); Pacific Coast Federation of Fishermen’s Associations, Inc. v. Chevron Corp., et al. , No. CGC-18-571285 (Cal. Super. Ct.) (voluntarily ); 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 (. 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.).
Notes to the Consolidated Financial Statements
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Millions of dollars, except per-share amounts
Louisiana
Seven coastal parishes and the State of Louisiana have filed lawsuits in Louisiana against numerous oil and gas companies seeking 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 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 on the federal jurisdiction 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 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 . To the extent the company is required to pay remediation in these cases, it may have a material effect on our financial position and results of operations. Management believes that the in these lawsuits legal and factual merit and will continue to vigorously 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. 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.).
Notes to the Consolidated Financial Statements
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Millions of dollars, except per-share amounts
Note 17
Taxes
Income Taxes
Year ended December 31
Income tax expense (benefit)
U.S. federal
Current
Deferred
State and local
Current
Deferred
Total United States
International
Current
Deferred
Total International
Total income tax expense (benefit)
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.
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
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 Income
Year ended December 31
Income (loss) before income taxes
United States
International
Total income (loss) before income taxes
U.S. Federal statutory income tax
State and local income tax, net of federal income tax effect 1
Foreign tax effects
Australia
Statutory tax rate difference
Additional non-U.S. income taxes 2
Foreign exchange
Other
Kazakhstan
Additional non-U.S. income taxes 2
Equity affiliate accounting effect 3
Other
Nigeria - primarily additional non-U.S. income taxes
Saudi Arabia - primarily statutory tax rate difference
Other foreign jurisdictions
Total foreign tax effects
Effect of cross-border tax laws - primarily surplus foreign tax credits 4
Changes in valuation allowances 4
Other adjustments 5
Total income tax expense and effective tax rate
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
Income (loss) before income taxes
United States
International
Total income (loss) before income taxes
Theoretical tax (at U.S. statutory rate of 21%)
Equity affiliate accounting effect
Effect of income taxes from international operations
State and local taxes on income, net of U.S. federal income tax benefit
Prior year tax adjustments, claims and settlements 1
Tax credits
Other U.S. 1, 2
Total income tax expense (benefit)
Effective income tax rate
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 )).
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
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 Paid
Year ended December 31
U.S. Federal 1
U.S. state and local
All other jurisdictions
Australia
Canada 2
Guyana 3
Kazakhstan 4
Nigeria
Saudi Arabia
All others
Income taxes paid
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
Deferred tax liabilities
Properties, plant and equipment
Investments and other
Total deferred tax liabilities
Deferred tax assets
Foreign tax credits
Asset retirement obligations/environmental reserves
Employee benefits
Tax credits
Tax loss carryforwards
Other accrued liabilities
Operating leases
Miscellaneous
Total deferred tax assets
Deferred tax assets valuation allowance
Total deferred income taxes, net
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.
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
At December 31, 2025 and 2024, deferred taxes were classified on the Consolidated Balance Sheet as follows:
At December 31
Deferred charges and other assets
Noncurrent deferred income taxes
Total deferred income taxes, net
Income taxes, including U.S. state and foreign withholding taxes, are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely, or where no taxable temporary differences exist that are attributable to an investment in a foreign entity. The indefinite reinvestment assertion continues to apply for the purpose of determining deferred tax liabilities for U.S. state and foreign withholding tax purpos es. 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 incu rring 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.
Balance at January 1
Foreign currency effects
Additions based on tax positions taken in current year
Additions for tax positions taken in prior years
Reductions based on tax positions taken in current year
Reductions for tax positions taken in prior years
Settlements with taxing authorities in current year
Balance at December 31
Approximately 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.
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
Taxes Other Than on Income
Year ended December 31
United States
Import duties and other levies
Property and other miscellaneous taxes
Payroll taxes
Taxes on production
Total United States
International
Import duties and other levies
Property and other miscellaneous taxes
Payroll taxes
Taxes on production
Total International
Total taxes other than on income
Note 18
Properties, Plant and Equipment 1
At December 31
Year ended December 31
Gross Investment at Cost
Net Investment
Additions at Cost 2
Depreciation Expense 3
Upstream
United States
International
Total Upstream
Downstream
United States
International
Total Downstream
All Other
United States
International
Total All Other
Total United States
Total International
Total
1 Other 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.
2 Net of dry hole expense related to prior years’ expenditures of $ 33 , $ 98 and $ 110 in 2025, 2024 and 2023, respectively.
3 Depreciation 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
Commercial paper
Notes payable to banks and others with originating terms of one year or less
Current maturities of long-term debt
Current maturities of long-term finance leases
Redeemable long-term obligations
Subtotal
Reclassified to long-term debt
Total short-term debt
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
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.
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
Note 20
Long-Term Debt
Total long-term debt including finance lease liabilities at December 31, 2025, was $ 39,781 . The company’s long-term debt outstanding at year-end 2025 and 2024 was as follows:
At December 31
Weighted Average Interest Rate (%) 1
Range of Interest Rates (%) 2
Principal
Principal
Notes due 2026
Notes due 2027
Notes due 2028
Notes due 2029
Notes due 2030
Notes and Debentures due 2031
Notes and Debentures due 2032
Notes due 2033
Notes due 2035
Notes due 2040
Notes due 2041
Notes due 2043
Notes due 2044
Notes due 2047
Notes due 2049
Notes due 2050
Notes due 2075
Debentures due 2097
Bank loans due 2026 to 2028
Term loans and credit facility borrowings
Medium-term notes, maturing from 2033 to 2038
Notes due 2025
Total including debt due within one year
Debt due within one year
Fair market value adjustment for debt acquired in the Noble and Hess acquisitions
Reclassified from short-term debt
Unamortized discounts and debt issuance costs
Finance lease liabilities 3
Total long-term debt
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.
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended December 31, 2025:
Beginning balance at January 1
Additions to capitalized exploratory well costs pending the determination of proved reserves
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
Capitalized exploratory well costs charged to expense
Other reductions*
Ending balance at December 31
* 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
Exploratory well costs capitalized for a period of one year or less
Exploratory well costs capitalized for a period greater than one year
Balance at December 31
Number of projects with exploratory well costs that have been capitalized for a period greater than one year *
* Certain projects have multiple wells or fields or both.
Of the $ 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:
Amount
Number of wells
Total
Aging based on drilling completion date of last suspended well in project:
Amount
Number of projects
Total
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.
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
Cash received in payment for option exercises under all share-based payment arrangements for 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 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
Expected term in years 1
Volatility 2
Risk-free interest rate based on zero coupon U.S. treasury note
Dividend yield
Weighted-average fair value per option granted
1 Expected term is based on historical exercise and post-vesting cancellation data.
2 Volatility rate is based on historical stock prices over an appropriate period, generally equal to the expected term.
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, 2025
Granted
Exercised
Forfeited
Outstanding at December 31, 2025
Exercisable at December 31, 2025
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.
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
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
Other Benefits
Int’l.
Int’l.
Change in Benefit Obligation
Benefit obligation at January 1
Service cost
Interest cost
Plan participants’ contributions
Plan amendments
Actuarial (gain) loss
Foreign currency exchange rate changes
Benefits paid
Actual expenses/taxes
Divestitures/Acquisitions
Curtailment
Special termination costs
Benefit obligation at December 31
Change in Plan Assets
Fair value of plan assets at January 1
Actual return on plan assets
Foreign currency exchange rate changes
Employer contributions
Plan participants’ contributions
Benefits paid
Actual expenses
Divestitures/Acquisitions
Fair value of plan assets at December 31
Funded status at December 31
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
Amounts recognized on the Consolidated Balance Sheet for the company’s pension and OPEB plans at December 31, 2025 and 2024, include:
Pension Benefits
Other Benefits
Int’l.
Int’l.
Deferred charges and other assets
Accrued liabilities
Noncurrent employee benefit plans
Net amount recognized at December 31
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
Other Benefits
Int’l.
Int’l.
Net actuarial (gain) loss
Prior service (credits) costs
Total recognized at December 31
The accumulated benefit obligations for all U.S. and international pension plans were $ 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
Int’l.
Int’l.
Projected benefit obligations
Accumulated benefit obligations
Fair value of plan assets
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:
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
Pension Benefits
Other Benefits
Int’l.
Int’l.
Int’l.
Net Periodic Benefit Cost
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service costs (credits)
Recognized actuarial (gains) losses
Settlement losses (gains)
Curtailment losses (gains)
Special termination benefits
Acquisition/Divestiture losses (gains)
Total net periodic benefit cost
Changes Recognized in Comprehensive Income
Net actuarial (gain) loss during period
Amortization of actuarial (gain) loss
Prior service (credits) costs during period
Amortization of prior service (costs) credits
Total changes recognized in other
comprehensive income
Recognized in Net Periodic Benefit Cost and Other Comprehensive Income
Assumptions The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31:
Pension Benefits
Other Benefits
Int’l.
Int’l.
Int’l.
Assumptions used to determine benefit obligations:
Discount rate
Rate of compensation increase
Cash balance interest crediting rate
Assumptions used to determine net periodic benefit cost:
Discount rate for service cost
Discount rate for interest cost
Expected return on plan assets
Rate of compensation increase
Cash balance interest crediting rate
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,
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
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:
Int’l.
Total
Level 1
Level 2
Level 3
NAV
Total
Level 1
Level 2
Level 3
NAV
At December 31, 2024
Equities
International
Collective Trusts/Mutual Funds 2
Fixed Income
Government
Corporate
Bank Loans
Mortgage/Asset Backed
Collective Trusts/Mutual Funds 2
Mixed Funds 3
Real Assets 4
Alternative Investments 5
Cash and Cash Equivalents
Other 6
Total at December 31, 2024
At December 31, 2025
Equities
International
Collective Trusts/Mutual Funds 2
Fixed Income
Government
Corporate
Bank Loans
Mortgage/Asset Backed
Collective Trusts/Mutual Funds 2
Mixed Funds 3
Real Assets 4
Alternative Investments 5
Cash and Cash Equivalents
Other 6
Total at December 31, 2025
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).
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below:
Equity
Int’l.
Real Estate
Other
Total
Total at December 31, 2023
Actual Return on Plan Assets:
Assets held at the reporting date
Assets sold during the period
Purchases, Sales and Settlements
Transfers in and/or out of Level 3
Total at December 31, 2024
Actual Return on Plan Assets:
Assets held at the reporting date
Assets sold during the period
Purchases, Sales and Settlements
Transfers in and/or out of Level 3
Total at December 31, 2025
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 Benefits
Other
Int’l.
Benefits
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.
Notes to the Consolidated Financial Statements
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Millions of dollars, except per-share amounts
Benefit Plan Trusts Prior to its acquisition by Chevron, Texaco established a benefit plan trust for funding obligations under some of its benefit plans. At year-end 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
Notes to the Consolidated Financial Statements
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Millions of dollars, except per-share amounts
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.
Notes to the Consolidated Financial Statements
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Millions of dollars, except per-share amounts
The following table indicates the changes to the company’s before-tax asset retirement obligations in 2025, 2024 and 2023:
Balance at January 1
Liabilities assumed in acquisition
Liabilities incurred
Liabilities settled
Reduction due to asset sales
Accretion expense
Revisions in estimated cash flows
Balance at December 31
In the table above, the amount associated with “Revisions in estimated cash flows” primarily reflects increased cost estimates and scope changes to decommission wells, equipment and facilities. The long-term portion of the $ 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. Earn ings 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 approximat ely $ 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 i n U.S. Upstream) and $ 223 for pension settlement and curtailment costs. Earnings in 2024 included after-tax charges of approximately $ 715 for s everance ($ 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.
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
Other financial information is as follows:
Year ended December 31
Total financing interest and debt costs
Less: Capitalized interest
Interest and debt expense
Research and development expenses
Excess of replacement cost over the carrying value of inventories (LIFO method)
LIFO profits (losses) on inventory drawdowns included in earnings
Foreign currency effects *
* Includes $( 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
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
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
Properties, plant and equipment
Other assets
Total assets acquired
Current liabilities
Long-term debt (1)
Deferred income taxes
Other liabilities
Total liabilities assumed
Noncontrolling interest (2)
Net assets acquired / purchase price
(1) Includes finance leases
(2) Related to HESM
The long-term debt assumed in the transaction is detailed in the table below:
Hess Corporation
Principal
4.300 % due 2027
7.875 % due 2029
7.300 % due 2031
7.125 % due 2033
6.000 % due 2040
5.600 % due 2041
5.800 % due 2047
Total Hess Corporation Debt
Hess Midstream Operations LP
5.125 % due 2028
5.875 % due 2028
6.500 % due 2029
4.250 % due 2030
5.500 % due 2030
Term loan and credit facility borrowings
Total Hess Midstream Operations LP Debt
Unamortized discounts and debt issuance costs
Total Long-Term Debt Assumed
Fair market value adjustment for debt acquired in the acquisition
Fair Market Value of Long-Term Debt Assumed
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,
Sales and other operating revenue
Net Income (Loss) Attributable to Chevron Corporation
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
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,
Sales and other operating revenue
Net Income (Loss) Attributable to Chevron Corporation
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.
Supplemental Information on Oil and Gas Producing Activities - Unaudited
Financial Table of Contents
In accordance with FASB and SEC disclosure requirements for oil and gas producing activities, this section provides supplemental information on oil and gas exploration and producing activities of the company in seven separate tables. Tables I through IV provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development, capitalized costs and results of operations. Tables V through VII present information on the company’s
Table I - Costs Incurred in Exploration, Property Acquisitions and Development 1
Consolidated Companies
Affiliated Companies
Other
Millions of dollars
Americas
Africa
Asia
Australia
Europe
Total
TCO
Other
Year Ended December 31, 2025
Exploration
Wells
Geological and geophysical
Other
Total exploration
Property acquisitions 2,3
Proved
Unproved
Total property acquisitions
Development 4
Total Costs Incurred 5
Year Ended December 31, 2024
Exploration
Wells
Geological and geophysical
Other
Total exploration
Property acquisitions 2
Proved - Other
Unproved - Other
Total property acquisitions
Development 4
Total Costs Incurred 5
Year Ended December 31, 2023
Exploration
Wells
Geological and geophysical
Other
Total exploration
Property acquisitions 2
Proved - Other
Unproved - Other
Total property acquisitions
Development 4
Total Costs Incurred 5
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:
Total cost incurred by Consolidated Companies
Acquisitions
(2025: Hess Corporation; 2023: PDC Energy, Inc.)
Expensed exploration costs
(Geological and geophysical and other exploration costs)
Non-oil and gas activities
(Primarily LNG and transportation activities)
ARO reduction/(build)
Upstream Capex
Reference page 49 Upstream Capex
Supplemental Information on Oil and Gas Producing Activities - Unaudited
Financial Table of Contents
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 Companies
Affiliated Companies
Other
Millions of dollars
Americas
Africa
Asia
Australia
Europe
Total
TCO
Other
At December 31, 2025
Unproved properties
Proved properties and
related producing assets
Support equipment
Deferred exploratory wells
Other uncompleted projects
Gross Capitalized Costs
Unproved properties valuation
Proved producing properties – Depreciation and depletion
Support equipment depreciation
Accumulated provisions
Net Capitalized Costs
At December 31, 2024
Unproved properties
Proved properties and
related producing assets
Support equipment
Deferred exploratory wells
Other uncompleted projects
Gross Capitalized Costs
Unproved properties valuation
Proved producing properties – Depreciation and depletion
Support equipment depreciation
Accumulated provisions
Net Capitalized Costs
At December 31, 2023
Unproved properties
Proved properties and
related producing assets
Support equipment
Deferred exploratory wells
Other uncompleted projects
Gross Capitalized Costs
Unproved properties valuation
Proved producing properties – Depreciation and depletion
Support equipment depreciation
Accumulated provisions
Net Capitalized Costs
Supplemental Information on Oil and Gas Producing Activities - Unaudited
Financial Table of Contents
Table III - Results of Operations for Oil and Gas Producing Activities 1
The company’s results of operations from oil and gas producing activities for the years 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 Companies
Affiliated Companies
Other
Millions of dollars
Americas
Africa
Asia
Australia
Europe
Total
TCO
Other
Year Ended December 31, 2025
Revenues from net production
Sales
Transfers
Total
Production expenses excluding taxes
Taxes other than on income
Proved producing properties:
Depreciation and depletion
Accretion expense 2
Exploration expenses
Unproved properties valuation
Other income (loss) 3
Results before income taxes
Income tax (expense) benefit
Results of Producing Operations
Year Ended December 31, 2024
Revenues from net production
Sales
Transfers
Total
Production expenses excluding taxes
Taxes other than on income
Proved producing properties:
Depreciation and depletion
Accretion expense 2
Exploration expenses
Unproved properties valuation
Other income (loss) 3
Results before income taxes
Income tax (expense) benefit
Results of Producing Operations
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.
Supplemental Information on Oil and Gas Producing Activities - Unaudited
Financial Table of Contents
Table III - Results of Operations for Oil and Gas Producing Activities 1 , continued
Consolidated Companies
Affiliated Companies
Other
Millions of dollars
Americas
Africa
Asia
Australia
Europe
Total
TCO
Other
Year Ended December 31, 2023
Revenues from net production
Sales
Transfers
Total
Production expenses excluding taxes
Taxes other than on income
Proved producing properties:
Depreciation and depletion
Accretion expense 2
Exploration expenses
Unproved properties valuation
Other income (loss) 3
Results before income taxes
Income tax (expense) benefit
Results of Producing Operations
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 Costs 1
Consolidated Companies
Affiliated Companies
Other
Americas
Africa
Asia
Australia
Europe
Total
TCO
Other
Year Ended December 31, 2025
Average sales prices
Crude, per barrel
Natural gas liquids, per barrel
Natural gas, per thousand cubic feet
Average production costs, per barrel 2
Year Ended December 31, 2024
Average sales prices
Crude, per barrel
Natural gas liquids, per barrel
Natural gas, per thousand cubic feet
Average production costs, per barrel 2
Year Ended December 31, 2023
Average sales prices
Crude, per barrel
Natural gas liquids, per barrel
Natural gas, per thousand cubic feet
Average production costs, per barrel 2
1 The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
2 Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel.
Supplemental Information on Oil and Gas Producing Activities - Unaudited
Financial Table of Contents
Table V Proved Reserve Quantity Information *
Summary of Net Oil and Gas Reserves
Liquids in Millions of Barrels
Natural Gas in Billions of Cubic Feet
Crude Oil
Condensate
SyntheticOil
NGL
Natural
Gas
Crude Oil
Condensate
SyntheticOil
NGL
Natural
Gas
Crude Oil
Condensate
SyntheticOil
NGL
Natural
Gas
Proved Developed
Consolidated Companies
Other Americas
Africa
Asia
Australia
Europe
Total Consolidated
Affiliated Companies
TCO
Other
Total Consolidated and Affiliated Companies
Proved Undeveloped
Consolidated Companies
Other Americas
Africa
Asia
Australia
Europe
Total Consolidated
Affiliated Companies
TCO
Other
Total Consolidated and Affiliated Companies
Total Proved Reserves
* 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.
Supplemental Information on Oil and Gas Producing Activities - Unaudited
Financial Table of Contents
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)
Quantity at January 1
Revisions
Improved recovery
Extension and discoveries
Purchases
Sales
Transfers to proved developed
Quantity at December 31
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 Companies
Affiliated Companies
Total
Consolidated
Other
Synthetic
Synthetic
and Affiliated
Millions of barrels
Americas 1
Africa
Asia
Australia
Europe
Oil 2,5
Total
TCO
Oil
Other 3
Companies
Reserves at January 1, 2023
Changes attributable to:
Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production
Reserves at December 31, 2023 4, 5
Changes attributable to:
Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production
Reserves at December 31, 2024 4, 5
Changes attributable to:
Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production
Reserves at December 31, 2025 4, 5
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 Companies
Affiliated Companies
Total
Consolidated
Other
and Affiliated
Millions of barrels
Americas 1
Africa
Asia
Australia
Europe
Total
TCO
Other 2
Companies
Reserves at January 1, 2023
Changes attributable to:
Revisions
Extensions and discoveries
Purchases
Sales
Production
Reserves at December 31, 2023 3
Changes attributable to:
Revisions
Extensions and discoveries
Purchases
Sales
Production
Reserves at December 31, 2024 3
Changes attributable to:
Revisions
Extensions and discoveries
Purchases
Sales
Production
Reserves at December 31, 2025 3
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 Companies
Affiliated Companies
Total
Consolidated
Other
and Affiliated
Billions of cubic feet (BCF)
Americas 1
Africa
Asia
Australia
Europe
Total
TCO
Other 2
Companies
Reserves at January 1, 2023
Changes attributable to:
Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production 3
Reserves at December 31, 2023 4, 5
Changes attributable to:
Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production 3
Reserves at December 31, 2024 4, 5
Changes attributable to:
Revisions
Improved recovery
Extensions and discoveries
Purchases
Sales
Production 3
Reserves at December 31, 2025 4, 5
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 Companies
Affiliated Companies
Total
Consolidated
Other
and Affiliated
Millions of dollars
Americas
Africa
Asia
Australia
Europe
Total
TCO
Other
Companies
At December 31, 2025
Future cash inflows from production
Future production costs
Future development costs
Future income taxes
Undiscounted future net cash flows
10 percent midyear annual discount for timing of estimated cash flows
Standardized Measure
Net Cash Flows
At December 31, 2024
Future cash inflows from production
Future production costs
Future development costs
Future income taxes
Undiscounted future net cash flows
10 percent midyear annual discount for timing of estimated cash flows
Standardized Measure
Net Cash Flows
At December 31, 2023
Future cash inflows from production
Future production costs
Future development costs
Future income taxes
Undiscounted future net cash flows
10 percent midyear annual discount for timing of estimated cash flows
Standardized Measure
Net Cash Flows
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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 dollars
Consolidated Companies
Affiliated Companies
Affiliated Companies
Present Value at January 1, 2023
Sales and transfers of oil and gas produced net of production costs
Development costs incurred
Purchases of reserves
Sales of reserves
Extensions, discoveries and improved recovery less related costs
Revisions of previous quantity estimates
Net changes in prices, development and production costs
Accretion of discount
Net change in income tax
Net Change for 2023
Present Value at December 31, 2023
Sales and transfers of oil and gas produced net of production costs
Development costs incurred
Purchases of reserves
Sales of reserves
Extensions, discoveries and improved recovery less related costs
Revisions of previous quantity estimates
Net changes in prices, development and production costs
Accretion of discount
Net change in income tax
Net Change for 2024
Present Value at December 31, 2024
Sales and transfers of oil and gas produced net of production costs
Development costs incurred
Purchases of reserves
Sales of reserves
Extensions, discoveries and improved recovery less related costs
Revisions of previous quantity estimates
Net changes in prices, development and production costs
Accretion of discount
Net change in income tax
Net Change for 2025
Present Value at December 31, 2025
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PART IV
