CHEVRON CORP

Table V Proved Reserve Quantity Information*

Summary of Net Oil and Gas Reserves

• Reserve quantities include natural gas projected to be consumed in operations of 2,462, 2,655 and 2,737 billions of cubic feet and equivalent synthetic oil projected to be consumed in operations of 0, 27, and 28 millions of barrels as of December 31, 2024, 2023 and 2022, respectively.

Reserves Governance The company has adopted a comprehensive reserves and resources classification system modeled after a system developed and approved by a number of organizations, including the Society of Petroleum Engineers, the World Petroleum Congress and the American Association of Petroleum Geologists. The company classifies discovered recoverable hydrocarbons into six categories based on their status at the time of reporting – three deemed commercial and three potentially recoverable. Within the commercial classification are proved reserves and two categories of unproved reserves: probable and possible. The potentially recoverable categories are also referred to as contingent resources. For reserves estimates to be classified as proved, they must meet all SEC and company standards.

Proved oil and gas reserves are the estimated quantities that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in the future from known reservoirs under existing economic conditions, operating methods and government regulations. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.

Proved reserves are classified as either developed or undeveloped. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are the quantities expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.

Proved reserves are estimated by company asset teams composed of earth scientists and engineers. As part of the internal control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired by the Manager of Global Reserves, an organization that is separate from the business units that estimate reserves. The Manager of Global Reserves has more than 35 years of experience working in the oil and gas industry and holds both undergraduate and graduate degrees in geoscience. His experience includes various technical and management roles in providing reserve and resource estimates in support of major capital and exploration projects, and more than 10 years of overseeing oil and gas reserves processes. He has been named a Distinguished Lecturer by the American Association of Petroleum Geologists and is an active member of the American Association of Petroleum Geologists, the SEPM Society of Sedimentary Geologists and the Society of Petroleum Engineers.

All RAC members are degreed professionals, each with more than 10 years of experience in various aspects of reserves estimation relating to reservoir engineering, petroleum engineering, earth science or finance. The members are knowledgeable in SEC guidelines for proved reserves classification and receive annual training on the preparation of reserves estimates.

The RAC has the following primary responsibilities: establish the policies and processes used within the business units to estimate reserves; provide independent reviews and oversight of the business units’ recommended reserves estimates and changes; confirm that proved reserves are recognized in accordance with SEC guidelines; determine that reserve quantities are calculated using consistent and appropriate standards, procedures and technology; and maintain the Chevron Corporation Reserves Manual, which provides standardized procedures used corporatewide for classifying and reporting hydrocarbon reserves.

During the year, the RAC is represented in meetings with each of the company’s business units to review and discuss reserve changes recommended by the various asset teams. Major changes are also reviewed with the company’s senior leadership team including the Chief Executive Officer and the Chief Financial Officer. The company’s annual reserves activity is also reviewed with the company’s Audit Committee and Board of Directors. If major changes to reserves were to occur between the annual reviews, those matters would also be discussed with the Board.

RAC sub-teams also conduct in-depth reviews during the year of many of the fields that have large proved reserves quantities. These reviews include an examination of the proved reserve records and documentation of their compliance with the Chevron Corporation Reserves Manual.

Technologies Used in Establishing Proved Reserves Additions In 2024, additions to Chevron’s proved reserves were based on a wide range of geologic and engineering technologies. Information generated from wells, such as well logs, wire line sampling, production and pressure testing, fluid analysis, and core analysis, was integrated with seismic data, regional geologic studies, and information from analogous reservoirs to provide “reasonably certain” proved reserves estimates. Both proprietary and commercially available analytic tools, including reservoir simulation, geologic modeling and seismic processing, have been used in the interpretation of the subsurface data. These technologies have been utilized extensively by the company in the past, and the company believes that they provide a high degree of confidence in establishing reliable and consistent reserves estimates.

Proved Undeveloped Reserves

Noteworthy changes in proved undeveloped reserves are shown in the table below and discussed below.

In 2024, revisions in the United States were primarily from the Denver-Julesburg (DJ) basin yielding a decrease of 98 million BOE mainly due to reservoir performance and portfolio optimization. A net decrease of 33 million BOE in the Midland and Delaware basins was due to reservoir performance.

In 2024, extensions and discoveries of 316 million BOE in the United States were primarily due to planned development of new locations in shale and tight assets in the DJ basin of 171 million BOE, the Midland and Delaware basins of 123 million BOE, and deepwater assets in the Gulf of America of 22 million BOE. In Other Americas, 58 million BOE of extensions and discoveries were from shale and tight assets in Argentina.

In 2024, purchases of 70 million BOE in the United States are primarily from newly identified proved undeveloped well locations associated with the acquisition of PDC.

The difference in 2024 extensions and discoveries of 161 million BOE, between the net quantities of proved reserves of 551 million BOE as reflected on pages 112 to 114 and net quantities of proved undeveloped reserves of 390 million BOE, is primarily due to proved extensions and discoveries that were not recognized as proved undeveloped reserves in the prior year and were recognized directly as proved developed reserves in 2024.

Transfers to proved developed reserves in 2024 include 464 million BOE in the United States, from 256 million BOE in the Midland and Delaware basins, 126 million BOE in the DJ basin, and 82 million BOE in the Gulf of America. Other significant transfers to proved developed were 329 million BOE in Kazakhstan, primarily at TCO, and 75 million BOE in Angola, primarily at Angola LNG. A combined 81 million BOE of transfers to proved developed were recorded in Argentina, Canada, Australia, Nigeria, China, and other international locations. These transfers are the consequence of development expenditures on completing wells and facilities.

During 2024, the company’s investments totaled approximately $8.2 billion in oil and gas producing activities, and about $0.1 billion in non-oil and gas producing activities, to advance the development of proved undeveloped reserves. The United States accounted for about $5.5 billion primarily related to various development activities in the Midland and Delaware basins, the Gulf of America and the DJ basin. In Africa, about $0.8 billion was expended on various offshore development and natural gas projects in Nigeria and Angola. An additional $0.5 billion was spent on development activities in Australia. Development activities in other international locations were primarily responsible for about $1.4 billion of expenditures. The company’s equity affiliates investments in oil and gas producing activities to advance development of proved undeveloped reserves in 2024 was $1.3 billion primarily related to development projects for TCO in Kazakhstan.

Reserves that remain proved undeveloped for five or more years are a result of several factors that affect optimal project development and execution. These factors may include the complex nature of the development project in adverse and remote locations, physical limitations of infrastructure or plant capacities that dictate project timing, compression projects that are pending reservoir pressure declines, and contractual limitations that dictate production levels.

At year-end 2024, the company held approximately 624 million BOE of proved undeveloped reserves that have remained undeveloped for five years or more. The majority of these reserves are in locations where the company has a proven track record of developing major projects. In Australia, approximately 223 million BOE remain undeveloped for five years or more related to the Gorgon and Wheatstone Projects. Further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with operating constraints, reservoir depletion and infrastructure optimization. In Africa, approximately 138 million BOE have remained undeveloped for five years or more, due to facility constraints at various fields and infrastructure associated with the Escravos gas projects in Nigeria. Affiliates account for about 237 million BOE of proved undeveloped reserves with about 197 million BOE that have remained undeveloped for five years or more related to TCO. At TCO, further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with reservoir depletion and facility constraints.

Annually, the company assesses whether any changes have occurred in facts or circumstances, such as changes to development plans, regulations, or government policies, that would warrant a revision to reserve estimates. In 2024, lower natural gas prices in North America were primarily responsible for the negative impact to the economic limits of oil and gas properties, resulting in a proved reserve decrease of approximately 58 million BOE. The year-end reserves quantities have been updated for these circumstances and significant changes are discussed in the appropriate reserves sections herein. Over the past three years, the ratio of proved undeveloped reserves to total proved reserves has ranged between 28 percent and 35 percent.

Proved Reserve Quantities For the three-year period ended December 31, 2024, the pattern of net reserve changes shown in the following tables is not necessarily indicative of future trends. Apart from acquisitions, the company’s ability to add proved reserves can be affected by events and circumstances that are outside the company’s control, such as delays in government permitting, partner approvals of development plans, changes in oil and gas prices, OPEC constraints, geopolitical uncertainties, civil unrest, events of war or military conflicts.

At December 31, 2024, proved reserves for the company were 9.8 billion BOE. The company’s estimated net proved reserves of liquids, including crude oil, condensate and synthetic oil for the years 2022, 2023 and 2024, are shown in the table on page 112. The company’s estimated net proved reserves of natural gas liquids (NGLs) are shown on page 113, and the company’s estimated net proved reserves of natural gas are shown on page 114.

Noteworthy changes in crude oil, condensate and synthetic oil proved reserves for 2022 through 2024 are discussed below and shown in the table on the following page:

Revisions In 2022, entitlement effects primarily contributed to a decrease of 49 million barrels of synthetic oil at the Athabasca Oil Sands project in Canada. In TCO, entitlement effects and changes in operating assumptions were primarily responsible for the 35 million barrels decrease in Kazakhstan.

In 2023, the 257 million barrels decrease in United States was primarily in the Midland and Delaware basins and California. Reservoir performance led to the decrease of 101 million barrels, and portfolio optimization led to a decrease of 59 million barrels in the Midland and Delaware basins. A reduction in planned development activities led to a decrease of 58 million barrels in California. In Other Americas, entitlement effects primarily contributed to an increase of 42 million barrels of synthetic oil at the Athabasca Oil Sands project in Canada. In Asia, reservoir performance, mainly in the Partitioned Zone between Saudi Arabia and Kuwait (the Partitioned Zone), was responsible for the 48 million barrels increase. Reservoir performance in Nigeria was mainly responsible for the 37 million barrels increase in Africa.

In 2024, the 37 million barrels increase in Asia was due to reservoir performance, primarily in the Partitioned Zone.

Extensions and Discoveries In 2022, extensions and discoveries in the Midland, Delaware and DJ basins, and approval of the Ballymore Project in the Gulf of America, were primarily responsible for the 264 million barrels increase in the United States. In Other Americas, the 32 million barrels of extensions and discoveries were from Argentina and Canada.

In 2023, extensions and discoveries of 124 million barrels in the Midland and Delaware basins were primarily responsible for the 170 million barrels increase in the United States. In Other Americas, the 55 million barrels of extensions and discoveries increase was mainly from shale and tight assets in Argentina.

In 2024, extensions and discoveries of 119 million barrels in the Midland and Delaware basins, and 45 million barrels in the DJ basin, were primarily responsible for the 185 million barrels increase in the United States. In Other Americas, the 52 million barrels of extensions and discoveries increase was mainly from shale and tight assets in Argentina.

Purchases In 2022, the company exercised its option to acquire additional land acreage in the Athabasca Oil Sands project in Canada contributing 168 million barrels in synthetic oil. The extension of deepwater licenses in Nigeria and the Republic of Congo contributed 36 million barrels in Africa.

In 2023, the acquisition of PDC in the DJ and Delaware basins was primarily responsible for the 207 million barrels increase in the United States.

In 2024, the renewal of the Agbami field deepwater license in Nigeria increased reserves by 51 million barrels.

Sales In 2024, sales of 593 million barrels in synthetic oil were from the Athabasca oil sand assets in Canada and the 46 million barrels in Other Americas were from the divestment of shale and tight assets in Canada.

Net Proved Reserves of Crude Oil, Condensate and Synthetic Oil

1 Ending reserve balances in North America were 132, 188 and 185 and in South America were 155, 136 and 110 in 2024, 2023 and 2022, respectively.

2 Reserves associated with Canada.

3 Reserves associated with Africa.

4 Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to page E-8 for the definition of a PSC). PSC-related reserve quantities are 8 percent, 6 percent and 6 percent for consolidated companies for 2024, 2023 and 2022, respectively.

5 Reserve quantities include synthetic oil projected to be consumed in operations of 0, 27, and 28 millions of barrels as of December 31, 2024, 2023 and 2022, respectively.

Noteworthy changes in NGLs proved reserves for 2022 through 2024 are discussed below and shown in the table on the following page:

Revisions In 2023, the 110 million barrels decrease in the United States was primarily in the Midland and Delaware basins with a decrease of 49 million barrels due to portfolio optimization and a decrease of 29 million barrels due to reservoir performance.

In 2024, the 41 million barrels decrease in the United States was primarily from a decrease of 65 million barrels in the DJ basin, which was partially offset by an increase of 31 million barrels from the Gulf of America.

Extensions and Discoveries In 2022, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 163 million barrels increase in the United States.

In 2023, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 92 million barrels increase in the United States.

In 2024, extensions and discoveries in the Midland and Delaware basins of 72 million barrels, and in the DJ basin of 52 million barrels, were responsible for the 124 million barrels increase in the United States.

Purchases In 2023, the acquisition of PDC in the DJ and Delaware basins was primarily responsible for the 262 million barrels increase in the United States.

Sales In 2022, sales of 35 million barrels in the United States were primarily from the divestment of the Eagle Ford shale assets and some properties in the Midland and Delaware basins.

Net Proved Reserves of Natural Gas Liquids

1 Reserves associated with North America.

2 Reserves associated with Africa.

3 Year-end reserve quantities related to PSC are not material for 2024, 2023 and 2022, respectively.

Noteworthy changes in natural gas proved reserves for 2022 through 2024 are discussed below and shown in the table on the following page:

Revisions In 2022, the performance of the Leviathan and Tamar fields in Israel and the Bibiyana and Jalalabad fields in Bangladesh were mainly responsible for the 1.8 TCF increase in Asia. In Australia, the 377 BCF decrease was mainly due to updated reservoir characterization of the Wheatstone field. In TCO, entitlement effects and changes in operating assumptions were primarily responsible for the 285 BCF decrease.

In 2023, portfolio optimization decrease of 276 BCF and a reservoir performance decrease of 186 BCF in the Midland and Delaware basins along with a reduction in planned development activities leading to a decrease of 485 BCF in the Haynesville shale formation of east Texas, were mainly responsible for the 1.2 TCF decrease in the United States. In Asia, final investment decision on a new gas pipeline project in Israel and reservoir performance in Bangladesh were mainly responsible for the 481 BCF increase.

In 2024, a decrease of 425 BCF in the DJ basin, primarily related to reservoir performance, was mainly responsible for the 572 BCF decrease in the United States. The 504 BCF increase in Australia was mainly due to reservoir performance of the Jansz Io field.

Extensions and Discoveries In 2022, extensions and discoveries of 1.6 TCF in the United States were primarily in the Midland and Delaware basins.

In 2023, extensions and discoveries of 660 BCF in the United States were primarily in the Midland and Delaware basins.

In 2024, extensions and discoveries of 912 BCF in the United States were primarily in the DJ basin with 476 BCF, and the Midland and Delaware basins with 432 BCF.

Purchases In 2023, the acquisition of PDC in the DJ basin was primarily responsible for the 2.2 TCF in the United States.

In 2024, the 177 BCF in the United States was primarily associated with the acquisition of PDC in the DJ basin.

Sales In 2022, sales of 243 BCF in the United States were primarily in the Eagle Ford shale and Midland and Delaware basins.

In 2024, sales of 260 BCF in Other Americas were from the divestment of shale and tight assets in Canada.

Net Proved Reserves of Natural Gas

1 Ending reserve balances in North America and South America were 49, 363 and 407 and 265, 211 and 138 in 2024, 2023 and 2022, respectively.

2 Reserves associated with Africa.

3 Total “as sold” volumes were 2,768, 2,609 and 2,600 for 2024, 2023 and 2022, respectively.

4 Includes reserve quantities related to PSC. PSC-related reserve quantities were 6 percent, 7 percent and 8 percent for consolidated companies for 2024, 2023 and 2022, respectively.

5 Reserve quantities include natural gas projected to be consumed in operations of 2,462, 2,655 and 2,737 billions of cubic feet as of December 31, 2024, 2023 and 2022, respectively.

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.