SEC EDGAR Filing

Company: CHEVRON CORP
CIK: 93410
Filing Type: 10-K
Filing Date: 2023-02-23
Period of Report: 2022-12-31
SIC Code: 2911
State of Incorporation: DE
State of Location: CA
Fiscal Year End: 1231

Filename: 93410_10K_2022_0000093410-23-000009.htm
Filing Index: https://www.sec.gov/Archives/edgar/data/93410/0000093410-23-000009-index.html
HTM Filing Link: https://www.sec.gov/Archives/edgar/data/93410/000009341023000009/cvx-20221231.htm
Complete Text Filing Link: https://www.sec.gov/Archives/edgar/data/93410/0000093410-23-000009.txt

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Item 1. Business
Item 1. Business
General Development of Business
Summary Description of Chevron
Chevron Corporation,* a Delaware corporation, manages its investments in subsidiaries and affiliates and provides administrative, financial, management and technology support to U.S. and international subsidiaries that engage in integrated energy and chemicals operations. Upstream operations consist primarily of exploring for, developing, producing and transporting crude oil and natural gas; processing, liquefaction, transportation and regasification associated with liquefied natural gas; transporting crude oil by major international oil export pipelines; transporting, storage and marketing of natural gas; and a gas-to-liquids plant. Downstream operations consist primarily of refining crude oil into petroleum products; marketing of crude oil, refined products, and lubricants; manufacturing and marketing of renewable fuels; transporting crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses and fuel and lubricant additives.
A list of the company’s significant subsidiaries is presented in Exhibit 21.1.
Overview of Petroleum Industry
Petroleum industry operations and profitability are influenced by many factors. Prices for crude oil, natural gas, liquefied natural gas, petroleum products and petrochemicals are generally determined by supply and demand. Production levels from the members of Organization of Petroleum Exporting Countries (OPEC), Russia and the United States are the major factors in determining worldwide supply. Demand for crude oil and its products and for natural gas is largely driven by the conditions of local, national and global economies, although weather patterns, the pace of energy transition and taxation relative to other energy sources also play a significant part. Laws and governmental policies, particularly in the areas of taxation, energy and the environment, affect where and how companies invest, conduct their operations, select feedstocks, and formulate their products and, in some cases, limit their profits directly.
Strong competition exists in all sectors of the petroleum and petrochemical industries in supplying the energy, fuel and chemical needs of industry and individual consumers. In the upstream business, Chevron competes with fully integrated, major global petroleum companies, as well as independent and national petroleum companies, for the acquisition of crude oil and natural gas leases and other properties and for the equipment and labor required to develop and operate those properties. In its downstream business, Chevron competes with fully integrated, major petroleum companies, as well as independent refining and marketing, transportation and chemicals entities and national petroleum companies in the refining, manufacturing, sale and marketing of fuels, lubricants, additives and petrochemicals.
Operating Environment
Refer to pages 32 through 40 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the company’s current business environment and outlook.
Chevron’s Strategic Direction
Chevron’s strategy is to leverage our strengths to safely deliver lower carbon energy to a growing world. Our primary objective is to deliver higher returns, lower carbon and superior shareholder value in any business environment. We are building on our capabilities, assets and customer relationships as we aim to lead in lower carbon intensity oil, products and natural gas, as well as advance new products and solutions that reduce the carbon emissions of major industries. We aim to grow our traditional oil and gas business, lower the carbon intensity of our operations and grow new lower carbon businesses in renewable fuels, hydrogen, carbon capture, offsets, and other emerging technologies.
Information about the company is available on the company’s website at www.chevron.com. Information contained on the company’s website is not part of this Annual Report on Form 10-K. The company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available free of charge on the company’s website soon after such reports are filed with or furnished to the U.S. Securities and Exchange Commission (SEC). The reports are also available on the SEC’s website at www.sec.gov.
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* Incorporated in Delaware in 1926 as Standard Oil Company of California, the company adopted the name Chevron Corporation in 1984 and ChevronTexaco Corporation in 2001. In 2005, ChevronTexaco Corporation changed its name to Chevron Corporation. As used in this report, the term “Chevron” and such terms as “the company,” “the corporation,” “our,” “we,” “us” and "its" may refer to Chevron Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole, but unless stated otherwise they do not include “affiliates” of Chevron - i.e., those companies accounted for by the equity method (generally owned 50 percent or less) or non-equity method investments. All of these terms are used for convenience only and are not intended as a precise description of any of the separate companies, each of which manages its own affairs.
Human Capital Management
Chevron invests in its workforce and culture, with the objective of engaging employees to develop their full potential to deliver energy solutions and enable human progress. The Chevron Way explains the company’s beliefs, vision, purpose and values. It guides how the company’s employees work and establishes a common understanding of culture and aspirations.
Chevron hires, develops, and strives to retain a diverse workforce of high-performing talent, and fosters a culture that values diversity, inclusion and employee engagement. Chevron leadership is accountable for the company’s investment in people and the company’s culture. This includes reviews of metrics addressing critical function hiring, leadership development, retention, diversity and inclusion, and employee engagement.
The following table summarizes the number of Chevron employees by gender, where data is available, and by region as of December 31, 2022.
At December 31, 2022
Female Male Gender data not available1
Total Employees
Number of Employees Percentage Number of Employees Percentage Number of Employees Percentage Number of Employees Percentage
Non-Service Station Employees
U.S. 5,343 27 % 14,609 73 % 23 - % 19,975 46 %
Other Americas 1,005 28 % 2,536 71 % 21 1 % 3,562 8 %
Africa 613 16 % 3,246 84 % 3 - % 3,862 9 %
Asia 2,420 34 % 4,675 66 % 32 - % 7,127 16 %
Australia 557 25 % 1,629 74 % 3 - % 2,189 5 %
Europe 433 28 % 1,099 71 % 11 1 % 1,543 4 %
Total Non-Service Station Employees 10,371 27 % 27,794 73 % 93 - % 38,258 87 %
Service Station Employees 2,121 38 % 1,675 30 % 1,792 32 % 5,588 13 %
Total Employees 12,492 28 % 29,469 67 % 1,885 4 % 43,846 100 %
1 Includes employees where gender data was not collected or employee chose not to disclose gender.
Hiring, Development and Retention
The company’s approach to attracting, developing and retaining a global, diverse workforce of high-performing talent is anchored in a long-term employment model that fosters an environment of personal growth and engagement. Chevron’s philosophy is to offer compelling career opportunities and a competitive total compensation and benefits package linked to individual and enterprise performance. Chevron recruits new employees in part through partnerships with universities and diversity associations. In addition, the company recruits experienced hires to provide specialized skills.
Chevron’s learning and development programs are designed to help employees achieve their full potential by building technical, operating and leadership capabilities at all levels to produce energy safely, reliably and efficiently. Chevron’s leadership regularly reviews metrics on employee training and development programs, which are continually refined to meet the needs of our evolving business. The company invests in developing leadership at every level. For example, Chevron expanded a coaching program that reaches deeper into the organization, including frontline supervisors, managers and individual contributors.
In addition, to ensure business continuity, leadership regularly reviews the talent pipeline, identifies and develops succession candidates, and builds succession plans for key positions. The Board of Directors provides oversight of CEO and executive succession planning.
Management routinely reviews the retention of its professional population, which includes executives, all levels of management, and the majority of its regular employee population. The annual voluntary attrition for this population was 4.5 percent, which is in line with rates over a five-year comparison period. The voluntary attrition rate generally excludes employee departures under enterprise-wide restructuring programs. Chevron believes its low voluntary attrition rate is in part a result of the company’s commitment to employee development, its long-term employment model, competitive pay and benefits, and its culture.
Diversity and Inclusion
Chevron believes human ingenuity has the power to solve difficult problems when diverse people, ideas and experiences come together in an inclusive environment. Chevron reinforces the values of diversity and inclusion through recruitment and talent development, equitable selection processes, community partnerships and supplier diversity. Chevron strives to build an inclusive environment through innovative programs such as the company’s MARC (Men Advocating Real Change) program launched in 2017, in partnership with the non-profit organization Catalyst, to facilitate discussions on gender equity in the workplace. MARC is active in over 35 Chevron locations on six continents around the world with over 5,000 participants since inception. Also, when hiring for a position, many selection processes now include inclusion counselors who help check against unconscious biases and provide outside perspectives.
Chevron’s leadership development also reflects Chevron’s diversity focus. In 2022, Chevron offered numerous leadership programs to promote leadership diversity, including the Global Women’s Leadership Development Program, Transformational Leadership for Multicultural Women, Executive Leadership Council (U.S. Black employees), Asia Pacific Leadership Development Program, Asian American Leadership Development Program, and Latino Leadership Development Program. In addition, Chevron has 11 employee networks (voluntary groups of employees that come together based on shared identity or interests) and a Chairman’s Inclusion Council, which provides the employee network presidents with a direct line of communication to the Chairman and Chief Executive Officer, the Chief Human Resources Officer, the Chief Diversity and Inclusion Officer, and the executive leadership team to collaborate and discuss how employee networks can reinforce Chevron’s values of diversity and inclusion.
Employee Engagement
Employee engagement is an indicator of employee well-being and commitment to the company’s values, purpose and strategies. Chevron regularly conducts employee surveys to assess the health of the company’s culture; recent surveys indicate high employee engagement. Chevron’s survey frequency enables the company to better understand employee sentiment throughout the year and gain insights into employee well-being. The company also introduced surveys to understand employee experience trends throughout the employee lifecycle.
Chevron prioritizes the health, safety and well-being of its employees. Chevron’s safety culture empowers every member of its workforce to exercise stop-work authority without repercussion to address any potential unsafe work conditions. The company has set clear expectations for leaders to deliver operational excellence by demonstrating their commitment to prioritizing the safety and health of its workforce, and the protection of communities, the environment and the company’s assets. Additionally, the company offers long-standing employee support programs such as Ombuds, an independent resource designed to equip employees with options to address and resolve workplace issues; a company hotline, where employees can report concerns to the Corporate Compliance department; and an Employee Assistance Program, a confidential consulting service that can help employees resolve a broad range of personal, family and work-related concerns. In February, Chevron received the 2023 Platinum Bell Seal for Workplace Mental Health by Mental Health America. The Bell Seal is a first-of-its-kind workplace mental health certification that recognizes employers who strive to create mentally healthy workplaces for their employees.
Description of Business and Properties
The upstream and downstream activities of the company and its equity affiliates are widely dispersed geographically, with operations and projects* in North America, South America, Europe, Africa, Asia and Australia. These activities are managed by the Oil, Products and Gas organization. Tabulations of segment sales and other operating revenues, earnings, assets, and income taxes for the three years ending December 31, 2022, and assets as of the end of 2022 and 2021 - for the United States and the company’s international geographic areas - are in Note 14 Operating Segments and Geographic Data to the Consolidated Financial Statements. Similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are in Note 15 Investments and Advances and Note 18 Property, Plant and Equipment. Refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the company’s Capital Expenditures.
Upstream
Reserves
Refer to Table V for a tabulation of the company’s proved reserves by geographic area, at the beginning of 2020 and at each year-end from 2020 through 2022. Reserves governance, technologies used in establishing proved reserves additions, and major changes to proved reserves by geographic area for the three-year period ended December 31, 2022, are summarized in the discussion for Table V. Discussion is also provided regarding the nature of, status of, and planned future activities associated with the development of proved undeveloped reserves. The company recognizes reserves for projects with various development periods, sometimes exceeding five years. The external factors that impact the duration of a project include scope and complexity, remoteness or adverse operating conditions, infrastructure constraints, and contractual limitations.
At December 31, 2022, 36 percent of the company’s net proved oil-equivalent reserves were located in the United States, 16 percent were located in Australia and 14 percent were located in Kazakhstan.
The net proved reserve balances at the end of each of the three years 2020 through 2022 are shown in the following table:
At December 31
2022 2021 2020
Crude Oil, Condensate and Synthetic Oil - Millions of barrels
Consolidated Companies 3,868 3,821 3,766
Affiliated Companies 1,129 1,254 1,553
Total Crude Oil, Condensate and Synthetic Oil 4,997 5,075 5,319
Natural Gas Liquids - Millions of barrels
Consolidated Companies 1,002 935 709
Affiliated Companies 86 103 119
Total Natural Gas Liquids 1,088 1,038 828
Natural Gas - Billions of cubic feet
Consolidated Companies 28,765 28,314 27,006
Affiliated Companies 2,099 2,594 2,916
Total Natural Gas 30,864 30,908 29,922
Oil-Equivalent - Millions of barrels1
Consolidated Companies 9,664 9,475 8,976
Affiliated Companies 1,565 1,789 2,158
Total Oil-Equivalent 11,229 11,264 11,134
1 Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil.
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* As used in this report, the term “project” may describe new upstream development activity, individual phases in a multiphase development, maintenance activities, certain existing assets, new investments in downstream and chemicals capacity, investments in emerging and sustainable energy activities, and certain other activities. All of these terms are used for convenience only and are not intended as a precise description of the term “project” as it relates to any specific governmental law or regulation.
Average Sales Prices and Production Costs per Unit of Production
Refer to Table IV for the company’s average sales price per barrel of crude (including crude oil and condensate) and natural gas liquids and per thousand cubic feet of natural gas produced, and the average production cost per oil-equivalent barrel for 2022, 2021 and 2020.
Gross and Net Productive Wells
The following table summarizes gross and net productive wells at year-end 2022 for the company and its affiliates:
At December 31, 2022
Productive Oil Wells1
Productive Gas Wells1
Gross Net Gross Net
United States 34,834 27,364 2,078 1,712
Other Americas 1,144 708 266 176
Africa 1,623 635 46 17
Asia 1,764 779 1,431 436
Australia 532 299 109 29
Europe 38 7 - -
Total Consolidated Companies 39,935 29,792 3,930 2,370
Affiliates2
1,677 607 - -
Total Including Affiliates 41,612 30,399 3,930 2,370
Multiple completion wells included above 715 411 147 115
1 Gross wells represent the total number of wells in which Chevron has an ownership interest. Net wells represent the sum of Chevron’s ownership interest in gross wells.
2 Includes gross 1,427 and net 482 productive oil wells for interests accounted for by the non-equity method.
Production Outlook
The company estimates its average worldwide oil-equivalent production in 2023, assuming a Brent crude oil price of $80 per barrel, to be flat to up three percent compared to 2022. This estimate is subject to many factors and uncertainties, as described beginning on page 36. Refer to the Review of Ongoing Exploration and Production Activities in Key Areas for a discussion of the company’s major crude oil and natural gas development projects.
Acreage
At December 31, 2022, the company owned or had under lease or similar agreements undeveloped and developed crude oil and natural gas properties throughout the world. The geographical distribution of the company’s acreage is shown in the following table:
Undeveloped2
Developed Developed and Undeveloped
Thousands of acres1
Gross Net Gross Net Gross Net
United States 3,784 3,277 3,909 2,565 7,693 5,842
Other Americas 19,322 11,109 1,088 239 20,410 11,348
Africa 10,286 5,695 1,884 793 12,170 6,488
Asia 16,850 6,795 1,105 430 17,955 7,225
Australia 2,853 1,933 2,069 815 4,922 2,748
Europe 103 20 15 3 118 23
Total Consolidated Companies 53,198 28,829 10,070 4,845 63,268 33,674
Affiliates3
695 286 109 50 804 336
Total Including Affiliates 53,893 29,115 10,179 4,895 64,072 34,010
1 Gross acres represent the total number of acres in which Chevron has an ownership interest. Net acres represent the sum of Chevron’s ownership interest in gross acres.
2 The gross undeveloped acres that will expire in 2023, 2024 and 2025 if production is not established by certain required dates are 4,387, 996, and 1,412, respectively.
3 Includes gross 405 and net 141 undeveloped and gross 19 and net 5 developed acreage for interests accounted for by the non-equity method.
Net Production of Crude Oil, Natural Gas Liquids and Natural Gas
The following table summarizes the net production of crude oil, natural gas liquids and natural gas for 2022 and 2021 by the company and its affiliates. Worldwide oil-equivalent production of 3 million barrels per day in 2022 was down approximately 3 percent from 2021. International production decreased 7 percent in 2022 primarily due to the end of concessions in Thailand and Indonesia, while U.S. production increased 4 percent compared to 2021, mainly in the Permian Basin. Refer to the Results of Operations section for a detailed discussion of the factors explaining the changes in production for liquids (including crude oil, condensate, natural gas liquids and synthetic oil) and natural gas, and refer to Table V for information on annual production by geographical region.
Components of Oil-Equivalent
Oil-Equivalent Crude Oil Natural Gas Liquids Natural Gas
Thousands of barrels per day (MBPD) (MBPD)1
(MBPD)2
(MBPD) (MMCFPD)
Millions of cubic feet per day (MMCFPD) 2022 2021 2022 2021 2022 2021 2022 2021
United States 1,181 1,139 650 643 238 215 1,758 1,689
Other Americas
Argentina
40 33 35 28 - - 34 31
Brazil
- 3 - 3 - - - -
Canada3
139 161 109 129 7 7 135 150
Total Other Americas 179 197 144 160 7 7 169 181
Africa
Angola
70 78 57 65 4 5 49 52
Equatorial Guinea 56 52 12 12 7 6 223 204
Nigeria
152 165 101 118 6 6 266 246
Republic of Congo
31 39 28 36 1 1 11 13
Total Africa 309 334 198 231 18 18 549 515
Asia
Bangladesh
118 112 2 2 - - 696 655
China
28 30 10 12 - - 109 104
Indonesia4
3 67 1 62 - - 18 30
Israel 101 91 1 1 - - 602 541
Kazakhstan
40 41 24 24 - - 96 103
Kurdistan Region of Iraq 1 2 1 2 - - - -
Myanmar
17 15 - - - - 94 92
Partitioned Zone 60 58 58 56 - - 7 7
Thailand4
67 163 18 41 - - 298 736
Total Asia 435 579 115 200 - - 1,920 2,268
Australia
Australia 482 449 42 43 - - 2,643 2,434
Total Australia 482 449 42 43 - - 2,643 2,434
Europe
United Kingdom 14 14 13 13 - - 9 6
Total Europe 14 14 13 13 - - 9 6
Total Consolidated Companies 2,600 2,712 1,162 1,290 263 240 7,048 7,093
Affiliates5
399 387 278 263 16 21 629 616
Total Including Affiliates6
2,999 3,099 1,440 1,553 279 261 7,677 7,709
1 Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil.
2 Includes crude oil, condensate and synthetic oil.
3 Includes synthetic oil:
45 55 45 55 - - - -
4 Chevron concessions expired in 2021 (Indonesia) and 2022 (Thailand).
5 Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil in Kazakhstan and Angola LNG in Angola.
6 Volumes include natural gas consumed in operations of 570 million and 592 million cubic feet per day in 2022 and 2021, respectively. Total “as sold” natural gas volumes were 7,107 million and 7,117 million cubic feet per day for 2022 and 2021, respectively.
Delivery Commitments
The company sells crude oil and natural gas from its producing operations under a variety of contractual obligations. Most contracts generally commit the company to sell quantities based on production from specified properties, but some natural gas and crude oil sales contracts specify delivery of fixed and determinable quantities.
In the United States, the company is contractually committed to deliver approximately 7 million barrels of crude oil and 729 billion cubic feet of natural gas to third parties from 2023 through 2025. The company believes it can satisfy these contracts through a combination of equity production from the company’s proved developed U.S. reserves and third-party purchases. These commitments are primarily based on contracts with indexed pricing terms.
Outside the United States, the company is contractually committed to deliver a total of 2.8 trillion cubic feet of natural gas to third parties from 2023 through 2025 from operations in Australia and Israel. The Australia sales contracts contain variable pricing formulas that generally reference the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery. The sales contracts for Israel contain formulas that generally reflect an initial base price subject to price indexation, Brent-linked or other, over the life of the contract. The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed reserves in these countries.
Development Activities
Refer to Table I for details associated with the company’s development expenditures and costs of proved property acquisitions for 2022, 2021 and 2020.
The following table summarizes the company’s net interest in productive and dry development wells completed in each of the past three years, and the status of the company’s development wells drilling at December 31, 2022. A “development well” is a well drilled within the known area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Wells Drilling* Net Wells Completed
at 12/31/22 2022 2021 2020
Gross Net Prod. Dry Prod. Dry Prod. Dry
United States 185 98 454 2 319 2 539 2
Other Americas 7 5 35 - 54 - 27 -
Africa 3 1 6 - 4 - 5 -
Asia 23 8 32 1 35 - 94 2
Australia - - 1 - - - - -
Europe - - 1 - 1 - 1 -
Total Consolidated Companies 218 112 529 3 413 2 666 4
Affiliates 13 1 6 - 8 - 13 -
Total Including Affiliates 231 113 535 3 421 2 679 4
* Gross wells represent the total number of wells in which Chevron has an ownership interest. Net wells represent the sum of Chevron’s ownership interest in gross wells.
Exploration Activities
Refer to Table I for detail on the company’s exploration expenditures and costs of unproved property acquisitions for 2022, 2021 and 2020.
The following table summarizes the company’s net interests in productive and dry exploratory wells completed in each of the last three years, and the number of exploratory wells drilling at December 31, 2022. “Exploratory wells” are wells drilled to find and produce crude oil or natural gas in unknown areas and include delineation and appraisal wells, which are wells drilled to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir or to extend a known reservoir.
Wells Drilling* Net Wells Completed
at 12/31/22 2022 2021 2020
Gross Net Prod. Dry Prod. Dry Prod. Dry
United States 1 - 3 2 2 2 4 1
Other Americas 1 - 1 1 - - 2 2
Africa - - 1 - - - - -
Asia 3 2 2 - - - - -
Australia - - - - - - - -
Europe - - - - - - - -
Total Consolidated Companies 5 2 7 3 2 2 6 3
Affiliates - - - - - - - -
Total Including Affiliates 5 2 7 3 2 2 6 3
* Gross wells represent the total number of wells in which Chevron has an ownership interest. Net wells represent the sum of Chevron’s ownership interest in gross wells.
Review of Ongoing Exploration and Production Activities in Key Areas
Chevron has exploration and production activities in many of the world’s major hydrocarbon basins. Chevron’s 2022 key upstream activities, some of which are also discussed in the section Management’s Discussion and Analysis of Financial Condition and Results of Operations, are presented below. The comments include references to “total production” and “net production,” which are defined under “Production” in Exhibit 99.1.
The discussion that follows references the status of proved reserves recognition for significant long-lead-time projects not on production as well as for projects recently placed on production. Reserves are not discussed for exploration activities or recent discoveries that have not advanced to a project stage, or for mature areas of production that do not have individual projects requiring significant levels of capital or exploratory investment.
United States
Upstream activities in the United States are primarily located in Texas, New Mexico, Colorado, California, and the Gulf of Mexico. Acreage for the United States can be found in the Acreage table. Net daily oil-equivalent production in the United States can be found in the Net Production of Crude Oil, Natural Gas Liquids and Natural Gas table.
As one of the largest producers in the Permian Basin, Chevron continues to capitalize on its advantaged portfolio in west Texas and southeast New Mexico with an outlook of one million barrels of net oil equivalent production per day by 2025. The asset is comprised of stacked formations enabling production from multiple geologic zones from single surface locations and staging the development for optimized capacity utilization of facilities and infrastructure. The company has implemented a factory development strategy utilizing multi-well pads to drill a series of horizontal wells that are subsequently completed concurrently using hydraulic fracture stimulation. This manufacturing-style process, combined with advantaged acreage holdings and technological advancements, have enabled capital expenditure productivity improvements. Continued operational efficiencies and diversified land assets via non-operated joint ventures and royalty positions have also contributed to higher returns throughout the Permian portfolio. In addition to ongoing emission reduction and water handling initiatives, construction of a 50 percent joint venture solar power project in New Mexico to supply renewable energy for our oil and gas operations was completed and is expected to be operational in the first half of 2023. In 2022, Chevron’s net daily unconventional production in the Permian Basin averaged 327,000 barrels of crude oil, 184,000 barrels of natural gas liquids (NGLs) and 1.2 billion cubic feet of natural gas.
Chevron divested its assets in the Eagle Ford Shale in Texas in March 2022.
In Colorado, development in the Denver-Julesburg (DJ) Basin is primarily focused on Chevron’s Mustang and Wells Ranch areas where the company’s comprehensive drilling plans allow for efficient resource development. In 2022, Chevron’s net daily production in the DJ Basin averaged 53,000 barrels of crude oil, 37,000 barrels of NGLs and 325 million cubic feet of natural gas.
Chevron also has operations in Colorado’s Piceance Basin, as well as an acreage position in Wyoming.
In 2022, 53 wells in Texas and 29 wells in Colorado achieved Project Canary’s highest certification rating on operational and environmental performance, allowing Chevron to market responsibly sourced natural gas.
In 2022, Chevron was one of the largest crude oil producers in California with a net daily oil equivalent production of 87,800 barrels. The California operations support Chevron’s efforts to progress its lower carbon technologies with investments in geothermal and carbon capture pilots. These include the Baseload Capital pilot to utilize waste heat from existing oilfield operations and the Svante pilot to capture carbon dioxide from combustion of natural gas. These pilots leverage innovative technologies and have the potential to scale across our operations. The Baseload Capital and Svante pilots became operational in the third and fourth quarters of 2022, respectively.
During 2022, net daily production in the Gulf of Mexico averaged 172,000 barrels of crude oil, 12,000 barrels of NGLs and 101 million cubic feet of natural gas. Chevron is engaged in various operated and nonoperated exploration, development and production activities in the deepwater Gulf of Mexico. Chevron also holds nonoperated interests in several shelf fields.
The deepwater Jack and St. Malo fields are being jointly developed with a host floating production unit located between the two fields. Chevron has a 50 percent interest in the Jack Field and a 51 percent interest in the St. Malo Field. Both fields are company operated. The company has a 40.6 percent interest in the production host facility, which is designed to accommodate production from the Jack/St. Malo development and third-party tiebacks. Additional development opportunities for the Jack and St. Malo fields progressed in 2022. The St. Malo Stage 4 waterflood project includes two new production wells, three injector wells, and topsides water injection equipment at the St. Malo Field. First water
injection is expected in 2024. Additional Jack development in 2022 consisted of a single well tieback and related subsea infrastructure installation. The Stage 4 multiphase subsea pump project replaces the single-phase subsea pumps in both the Jack and St. Malo fields. Multiphase pump module installation commenced in 2022. Proved reserves have been recognized for the multiphase subsea pump project. The Jack and St. Malo fields have an estimated remaining production life of more than 20 years.
The company has a 15.6 percent nonoperated working interest in the deepwater Mad Dog Field. First oil from the Mad Dog 2 Project is expected to commence in 2023. Proved reserves have been recognized for the Mad Dog 2 Project.
Chevron has a 60 percent-owned and operated interest in the Big Foot project, located in the deepwater Walker Ridge area. Development drilling activities are ongoing, with an additional production well that came online in 2022. The project has an estimated remaining production life of more than 30 years.
The company has a 58 percent-owned and operated interest in the deepwater Tahiti Field. The Tahiti Field has an estimated remaining production life of more than 20 years.
Chevron has a 25 percent nonoperated working interest in the Stampede Field, which is located in the Green Canyon area. The Stampede Field has an estimated remaining production life of 25 years.
Chevron has owned and operated interests of 62.9 to 75.4 percent in the unit areas containing the Anchor field. Stage 1 of the Anchor development consists of a seven-well subsea development and a semi-submersible floating production unit. The company successfully drilled the first development well to a total measured depth of 33,500 feet in 2022. Proved reserves have been recognized for Anchor, with first production expected in 2024.
Chevron has a 60 percent-owned and operated interest in the Ballymore Field located in the Mississippi Canyon, which is being developed as a subsea tieback to the existing Blind Faith facility. Chevron reached a final investment decision for Ballymore in May 2022. This project includes three production wells, with first oil expected in 2025. Proved reserves have been recognized for this project.
The company has a 40 percent nonoperated working interest in the Whale discovery located in the Perdido area. First production is expected for Whale in 2024 and proved reserves have been recognized for this project.
During 2022, the company participated in six exploration wells in the deepwater U.S. Gulf of Mexico. Chevron was also formally awarded 34 leases during 2022 as a result of U.S. Gulf of Mexico lease sale 257.
In May 2022, Chevron acquired a 50 percent interest in the Bayou Bend Carbon Capture and Sequestration hub in the Gulf of Mexico, covering over 40,000 acres.
Other Americas
“Other Americas” includes Argentina, Brazil, Canada, Colombia, Mexico, Suriname and Venezuela. Acreage for “Other Americas” can be found in the Acreage table. Net daily oil-equivalent production from these countries can be found in the Net Production of Crude Oil, Natural Gas Liquids and Natural Gas table.
Argentina Chevron has a 50 percent nonoperated interest in the Loma Campana and Narambuena concessions in the Vaca Muerta Shale. At Loma Compana, 49 horizontal wells were drilled in 2022, with 46 wells in total put on production. This concession expires in 2048, and the Narambuena concession expires in 2027.
Chevron also owns and operates a 100 percent interest in the El Trapial Field with both conventional waterflood and Vaca Muerta unconventional shale production. The conventional field concession expires in 2032.
In April 2022, Chevron was granted a new unconventional concession where it will operate the East area of the El Trapial Field in the Vaca Muerta shale formation, with a three-year pilot where it is expected to drill and complete five wells. Drilling operations began in August 2022 with three horizontal wells drilled in 2022. The unconventional concession expires in 2057.
Brazil Chevron holds between 30 and 50 percent of both operated and nonoperated interests in 11 blocks within the Campos and Santos Basins. Chevron is in the process of relinquishing the Saturno block in the Santos Basin, in which it holds a 45 percent nonoperated working interest. Chevron participated in two exploration wells in 2022.
Canada Upstream interests in Canada are concentrated in Alberta and the offshore Atlantic region of Newfoundland and Labrador. The company also has interests in the Northeast British Columbia and the Beaufort Sea region of the Northwest Territories.
The company has a 20 percent nonoperated working interest in the Athabasca Oil Sands Project (AOSP) and associated Quest carbon capture and storage project in Alberta. Oil sands are mined from both the Muskeg River and the Jackpine mines, and bitumen is extracted from the oil sands and upgraded into synthetic oil. Carbon dioxide (CO2) emissions from the upgrader are reduced by carbon capture and storage facilities.
Chevron has a 70 percent-owned and operated interest in most of its Duvernay shale acreage. By the end of 2022, a total of 243 wells have been tied into production facilities.
Chevron has a 26.9 percent nonoperated working interest in the Hibernia Field and a 24.1 percent nonoperated working interest in the unitized Hibernia Southern Extension areas offshore Atlantic Canada. The company has a 29.6 percent nonoperated working interest in the heavy oil Hebron Field, also offshore Atlantic Canada, which has an expected remaining economic life of 25 years.
The company has a 25 percent nonoperated working interest in blocks EL 1168 and EL 1148 located in offshore Atlantic Canada.
Colombia Chevron has a 40 percent-owned and operated interest in the offshore Colombia-3 and Guajira Offshore-3 Blocks.
Mexico The company has a 37.5 percent-owned and operated interest in Block 22 in the Cuenca Salina area in the deepwater Gulf of Mexico. The company also holds a 40 percent nonoperated interest in Blocks 20, 21 and 23. Chevron participated in one exploration well in 2022. Chevron, as operator of the joint venture, is in the process of relinquishing Block 3 in the Perdido area of the Gulf of Mexico, in which it holds a 33.3 percent-owned and operated interest.
Suriname Chevron has a 40 percent owned and operated working interest in Block 5. Chevron also holds a 33.3 percent nonoperated working interest in deepwater Block 42 where one exploration well was drilled during 2022. In April 2022, Chevron signed a production sharing contract (PSC) for the shallow water Block 7 with an 80 percent owned and operated working interest.
Venezuela Chevron’s interests in Venezuela are located in western Venezuela, the Orinoco Belt and offshore Venezuela. As of December 31, 2022, no proved reserves are recognized for these interests. In 2022, the company conducted activities in Venezuela consistent with the authorization provided pursuant to general licenses issued by the United States government. In November 2022, the Department of Treasury’s Office of Foreign Assets Control issued a six-month self-renewing general license authorizing the company to lift production from its four nonoperated affiliate joint ventures in Venezuela for delivery to the United States.
Chevron has a 39.2 percent interest in Petroboscan, which operates the Boscan Field in western Venezuela under an agreement expiring in 2026. Chevron has a 30 percent interest in Petropiar, which operates the heavy oil Huyapari Field under an agreement expiring in 2033. Chevron also holds a 25.2 percent interest in Petroindependiente, which operates the LL-652 Field in Lake Maracaibo under a contract expiring in 2026, and a 35.8 percent interest in Petroindependencia, which includes the Carabobo 3 heavy oil project located in three blocks in the Orinoco Belt. The Petroindependencia contract expires in 2035.
Chevron also operates and holds a 60 percent interest in the Loran gas field offshore Venezuela. This is part of a cross- border field that includes the Manatee field in Trinidad and Tobago. This license expires in 2039.
Africa
In Africa, the company is engaged in upstream activities in Angola, the Republic of Congo, Cameroon, Egypt, Equatorial Guinea, Namibia and Nigeria. Acreage for Africa can be found in the Acreage table. Net daily oil-equivalent production from these countries can be found in the Net Production of Crude Oil, Natural Gas Liquids and Natural Gas table.
Angola The company operates and holds a 39.2 percent interest in Block 0, a concession adjacent to the Cabinda coastline. The Block 0 partners and National Concessionaire signed an extension for an additional 20 years in December 2021. This extension to 2050 is subject to legislative approvals.
Chevron also operates and holds a 31 percent interest in a PSC for deepwater Block 14 which expires in 2028.
Chevron has a 36.4 percent interest in Angola LNG Limited, which operates an onshore natural gas liquefaction plant in Soyo, Angola. The plant has the capacity to process 1.1 billion cubic feet of natural gas per day. This is the world’s first liquefied natural gas (LNG) plant supplied with associated gas, where the natural gas is a byproduct of crude oil production. Feedstock for the plant originates from multiple fields and operators.
The Block 0 Sanha Lean Gas Connection Project (SLGC) execution continues and is expected to be completed in 2024. SLGC is a new platform that ties the existing complex to new connecting pipelines for gathering and exporting gas from Blocks 0 and 14 to Angola LNG.
In October 2022, first oil was announced for Lifua A in Block 0, which is the first stage of waterflood development in the Lifua field using a low-cost, short cycle solution that leverages existing infrastructure. In November 2022, South N’Dola, located in Area B of Block 0, reached final investment decision and will apply the same low-cost, short cycle solution as Lifua A.
In July 2022, a final investment decision was announced on the Quiluma and Maboqueiro (Q&M) development, part of the New Gas Consortium Project (NGC) in which Chevron has a 31 percent nonoperated working interest. NGC is an offshore gas concession in which the Q&M fields will be the first to be developed. The Q&M scope includes two wellhead platforms and an onshore gas treatment plant with connections to the Angola LNG plant. Proved reserves have not been recognized for this project.
Angola-Republic of Congo Joint Development Area Chevron operates and holds a 31.3 percent interest in the Lianzi Unitization Zone, which is located in an area shared equally by Angola and the Republic of Congo. This interest expires in 2031.
Republic of Congo Chevron has a 31.5 percent nonoperated working interest in the offshore Haute Mer permit area. The permits for Nkossa, Nsoko and Moho-Bilondo were extended in 2022 and now expire in 2040. Reserves have been recognized for the lease extension.
Cameroon Chevron owns and operates the YoYo Block in the Douala Basin. Preliminary development plans include a possible joint development between YoYo and the Yolanda field in Equatorial Guinea.
Egypt In the Mediterranean Sea, Chevron holds a 90 percent-owned and operated interest in North Sidi Barrani (Block 2) and North El Dabaa (Block 4) and a 45 percent interest in the Nargis block, as well as a 27 percent nonoperated working interest in both North Marina (Block 6) and North Cleopatra (Block 7). In 2022, the company successfully drilled its first exploration well and announced a significant gas discovery at the Nargis Offshore area. The well encountered approximately 200 net feet of high-quality gas-bearing sandstone. In the Red Sea, the company holds a 45 percent-owned and operated interest in Block 1.
Equatorial Guinea Chevron has a 38 percent-owned and operated interest in the Aseng oil field and the Yolanda natural gas field in Block I and a 45 percent-owned and operated interest in the Alen natural gas and condensate field in Block O. Chevron holds an 80 percent-owned and operated interest in Block EG-09, offshore Equatorial Guinea, in the Douala Basin located south of the Alen and Aseng fields.
The company also holds a 32 percent nonoperated interest in the natural gas and condensate Alba field, a 28 percent nonoperated interest in the Alba LPG Plant and a 45 percent interest in the Atlantic Methanol Production Company.
Namibia In September 2022, Chevron acquired an 80 percent-owned and operated interest in PEL90 (Block 2813B) in the Orange Basin, offshore Namibia.
Nigeria Chevron operates and holds a 40 percent interest in six concessions, five operated and one nonoperated in the onshore and near-offshore regions of the Niger Delta. The company also holds acreage positions in three operated and six nonoperated deepwater blocks, with working interests ranging from 20 to 100 percent. Chevron participated in one exploration well in 2022.
Chevron is the operator of the Escravos Gas Plant (EGP) with a total processing capacity of 680 million cubic feet per day of natural gas and liquefied petroleum gas and condensate export capacity of 58,000 barrels per day. The company operates the 33,000-barrel-per-day Escravos Gas to Liquids facility. In addition, the company holds a 36.9 percent interest in the West African Gas Pipeline Company Limited affiliate, which supplies Nigerian natural gas to customers in Benin, Togo and Ghana.
Chevron operates and holds a 67.3 percent interest in the Agbami field, located in deepwater Oil Mining Lease (OML) 127 and OML 128. OML127 expires in 2024 and OML128 was extended in 2022 from 2024 to 2042. Additionally, Chevron holds a 30 percent nonoperated working interest in the Usan field in OML 138. The lease that contains the Usan field was extended in 2022 from 2023 to 2042. Reserves have been recognized for the extensions of OML 128 and OML 138.
In deepwater exploration, Chevron operates and holds a 55 percent interest, in the deepwater Nsiko discoveries in OML 140. Chevron also holds a 27 percent interest in OML 139 and OML 154 and the company continues to work with the
operator to evaluate development options for the multiple discoveries in the Usan area, including the Owowo field, which straddles OML 139 and OML 154. The development plan for the Owowo field involves a subsea tie-back to the existing Usan floating, production, storage, and offloading vessel.
Also, in the deepwater area, the Aparo field in OML 132 and OML 140 and the third-party-owned Bonga SW field in OML 118 share a common geologic structure and would be developed jointly. Chevron holds a 16.6 percent nonoperated working interest in the unitized area. The development plan involves subsea wells tied back to a floating production, storage and offloading vessel. At the end of 2022, no proved reserves were recognized for this project.
In May 2022, Chevron divested its 40 percent operated interest in OML 86 and OML 88.
Asia
In Asia, the company is engaged in upstream activities in Bangladesh, China, Cyprus, Indonesia, Israel, Kazakhstan, Kurdistan Region of Iraq, Myanmar, the Partitioned Zone between Saudi Arabia and Kuwait, Russia, and Thailand. Acreage for Asia can be found in the Acreage table. Net daily oil-equivalent production for these countries can be found in the Net Production of Crude Oil, Natural Gas Liquids and Natural Gas table.
Bangladesh Chevron Bangladesh operates and holds 100 percent interest in Block 12 (Bibiyana field) and Blocks 13 and 14 (Jalalabad and Moulavi Bazar fields) under two PSCs. The rights to produce from Jalalabad expires in 2034, from Moulavi Bazar in 2038 and from Bibiyana in 2034. In October 2022, Chevron Bangladesh signed a supplemental agreement to Block 12 PSC extending the Bibiyana production area.
China Chevron has nonoperated working interests in several areas in China. The company has a 49 percent nonoperated working interest in the Chuandongbei project, including the Loujiazhai and Gunziping natural gas fields located onshore in the Sichuan Basin. The company also has nonoperated working interests of 32.7 percent in Block 16/19 in the Pearl River Mouth Basin and 24.5 percent in the Qinhuangdao (QHD) 32-6 Block in the Bohai Bay. The PSCs for Block 16/19 and QHD 32-6 expire in 2028 and 2024, respectively.
Cyprus The company holds a 35 percent-owned and operated interest in the Aphrodite gas field in Block 12. Chevron operates the field with the government of Cyprus and has a license that expires in 2044.
Indonesia Chevron has working interests through various PSCs in Indonesia. In offshore eastern Kalimantan, the company operates and holds a 62 percent interest in two PSCs in the Kutei Basin (Rapak and Ganal) and operates and holds a 72 percent interest in the Makassar Strait (West Seno field) temporary cooperation contract. The contracts for offshore eastern Kalimantan expire in December 2027 (Rapak and West Seno fields) and February 2028 (Ganal).
Chevron has concluded that the Indonesia Deepwater Development (IDD) Project held by the Kutei Basin PSCs does not compete in its portfolio and is evaluating alternatives for the company’s participating interest in these PSCs.
Israel Chevron holds a 39.7 percent-owned and operated interest in the Leviathan field, which operates under a concession that expires in 2044. The company also holds a 25 percent-owned and operated interest in the Tamar gas field, which operates under a concession that expires in 2038. In 2022, Chevron reached final investment decision for Phase 1 of the Tamar Optimization Project to expand the company’s offshore facilities. Opportunities to further monetize the existing gas resources are being assessed for both the Tamar and Leviathan fields.
Kazakhstan Chevron has a 50 percent interest in the Tengizchevroil (TCO) affiliate and an 18 percent nonoperated working interest in the Karachaganak field.
TCO is developing the Tengiz and Korolev crude oil fields in western Kazakhstan under a concession agreement that expires in 2033. Most of TCO’s 2022 crude oil production was exported through the Caspian Pipeline Consortium (CPC) pipeline.
In 2022, construction on the Future Growth Project and Wellhead Pressure Management Project (FGP/ WPMP) was largely completed. In addition, the FGP well program, consisting of 55 new wells, was completed in July 2022. WPMP is expected to begin start up by year-end 2023 with conversions of field gathering stations to low pressure continuing for about 12 months. FGP is expected to commence operations by mid-2024 with production expected to ramp up through year end. Proved reserves have been recognized for the FGP/WPMP.
The Karachaganak field is located in northwest Kazakhstan, and operations are conducted under a PSC that expires in 2038. Most of the exported liquids were transported through the CPC pipeline during 2022. Development continued on the
Karachaganak Expansion project (KEP) Stage 1A and a final investment decision was reached to commence KEP Stage 1B in late 2022. Proved reserves have been recognized for both projects.
Kazakhstan/Russia Chevron has a 15 percent interest in the CPC. Progress continued on the debottlenecking project, which is expected to further increase capacity. During 2022, CPC transported an average of 1.2 million barrels of crude oil per day, composed of 1.1 million barrels per day from Kazakhstan and 0.1 million barrels per day from Russia.
Kurdistan Region of Iraq The company holds a 50 percent nonoperated working interest in the Sarta PSC, which expires in 2047, and a 40 percent nonoperated working interest in the Qara Dagh PSC. Chevron participated in two exploration wells in 2022.
Myanmar Chevron has a 41.1 percent nonoperated working interest in a PSC for the production of natural gas from the Yadana, Badamyar and Sein fields, within Blocks M5 and M6, in the Andaman Sea. The PSC expires in 2028. The company also has a 41.1 percent nonoperated working interest in a pipeline company that transports natural gas to the Myanmar-Thailand border for delivery to power plants in Thailand.
In 2022, Chevron signed an agreement to sell the company’s interest in all Myanmar assets and exit the country, with an expected closing date in the second half of 2023.
Partitioned Zone Chevron holds a concession to operate the Kingdom of Saudi Arabia’s 50 percent interest in the hydrocarbon resources in the onshore area of the Partitioned Zone between Saudi Arabia and Kuwait. The concession expires in 2046. Current activities focus on base business optimization and production enhancement opportunities.
Thailand Chevron holds operated interests in the Pattani Basin, located in the Gulf of Thailand, with ownership ranging from 35 percent to 71.2 percent. Concessions for producing areas within this basin expire between 2028 and 2035. Chevron has a 35 percent-owned and operated interest in the Ubon project in Block 12/27. Chevron also has a 16 percent nonoperated working interest in the Arthit field located in the Malay Basin. Concessions for the producing areas within this basin expire between 2036 and 2040.
Within the Pattani Basin, the company previously held operated interests ranging from 70 to 80 percent of the Erawan concession, which expired in April 2022.
Chevron holds between 30 to 80 percent operated and nonoperated working interests in the Thailand-Cambodia Overlapping Claims Area that are inactive, pending resolution of border issues between Thailand and Cambodia.
Australia
Chevron is the largest producer of LNG in Australia. Acreage can be found in the Acreage table. Net daily oil-equivalent production can be found in the Net Production of Crude Oil, Natural Gas Liquids and Natural Gas table.
Upstream activities in Australia are concentrated offshore Western Australia, where the company is the operator of two major LNG projects, Gorgon and Wheatstone, and has a nonoperated working interest in the North West Shelf (NWS) Venture and exploration acreage in the Carnarvon Basin.
Chevron holds a 47.3 percent-owned and operated interest in Gorgon on Barrow Island, which includes the development of the Gorgon and Jansz-Io fields, a three-train 15.6 million-metric-ton-per-year LNG facility, a carbon capture and underground storage facility and a domestic gas plant. The Gorgon Stage 2 project is expected to be ready for startup in the first quarter of 2023. Progress on the Jansz-Io Compression project continued during 2022, and proved reserves have been recognized for this project. Gorgon’s estimated remaining economic life exceeds 40 years.
Chevron holds an 80.2 percent interest in the offshore licenses and a 64.1 percent-owned and operated interest in the LNG facilities associated with Wheatstone. Wheatstone includes the development of the Wheatstone and Iago fields, a two-train, 8.9 million-metric-ton-per-year LNG facility, and a domestic gas plant. The onshore facilities are located at Ashburton North on the coast of Western Australia. Wheatstone’s estimated remaining economic life exceeds 18 years.
Chevron has a 16.7 percent nonoperated working interest in the North West Shelf (NWS) Venture in Western Australia. The company continues to evaluate exploration and appraisal activity across the Carnarvon Basin, in which it holds more than 1.9 million net acres. Chevron relinquished 4 million net acres in 2022 in the Carnarvon basin.
Chevron owns and operates the Clio, Acme and Acme West fields. The company is collaborating with other Carnarvon Basin participants to assess the possibility of developing Clio and Acme through shared utilization of existing infrastructure.
Chevron holds nonoperated working interests ranging from 20 to 50 percent, in three greenhouse gas assessment permits to evaluate the potential of carbon storage. The blocks, including two in the Carnarvon Basin off the north-western coast of Western Australia and one in the Bonaparte Basin offshore Northern Territory, total nearly 7.8 million acres.
United Kingdom
Acreage can be found in the Acreage table. Net oil equivalent production for the United Kingdom can be found in the Net Production of Crude Oil, Natural Gas Liquids and Natural Gas table.
Chevron holds a 19.4 percent nonoperated working interest in the Clair field, located west of the Shetland Islands. The Clair Ridge project is the second development phase of the Clair field, with a design capacity of 120,000 barrels of crude oil and 100 million cubic feet of natural gas per day. The Clair field has an estimated remaining production life extending beyond 2050.
Sales of Natural Gas Liquids and Natural Gas
The company sells NGLs and natural gas from its producing operations under a variety of contractual arrangements. In addition, the company also makes third-party purchases and sales of NGLs and natural gas in connection with its supply and trading activities.
U.S. and international sales of NGLs averaged 303,000 and 234,000 barrels per day, respectively, in 2022.
During 2022, U.S. and international sales of natural gas averaged 4.4 billion and 5.8 billion cubic feet per day, respectively, which includes the company’s share of equity affiliates’ sales. Outside the United States, substantially all of the natural gas sales from the company’s producing interests are from operations in Angola, Argentina, Australia, Bangladesh, Canada, Equatorial Guinea, Kazakhstan, Indonesia, Israel, Nigeria and Thailand.
Refer to Selected Operating Data in Management’s Discussion and Analysis of Financial Condition and Results of Operations, for further information on the company’s sales volumes of natural gas liquids and natural gas. Refer also to Delivery Commitments for information related to the company’s delivery commitments for the sale of crude oil and natural gas.
Downstream
Refining Operations
At the end of 2022, the company had a refining network capable of processing 1.8 million barrels of crude oil per day. Operable capacity at December 31, 2022, and daily refinery inputs for 2020 through 2022 for the company and affiliate refineries, are summarized in the table below. Average crude oil distillation capacity utilization was 85 percent in 2022 and 82 percent in 2021.
At U.S. refineries, crude oil distillation capacity utilization averaged 82 percent in 2022, compared with 83 percent in 2021. Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 60 percent of Chevron’s U.S. refinery inputs in both 2022 and 2021.
In the United States, the company continued work on projects aimed at improving refinery flexibility and reliability. The Pasadena Refinery received regulatory approval for a project that is expected to increase light crude oil throughput capacity to 125,000 barrels per day in 2024. This project is expected to allow the company to run more equity crude from the Permian Basin, supply more products to customers in the U.S. Gulf Coast and realize synergies with the company’s Pascagoula refinery.
Outside the United States, the company has interests in three large refineries in Singapore, South Korea and Thailand. Singapore Refining Company (SRC), a 50 percent-owned joint venture, has a total capacity of 290,000 barrels of crude per day and manufactures a wide range of petroleum products, including higher-quality gasoline that meets stricter emission standards. The 50 percent-owned GS Caltex (GSC) Yeosu Refinery in South Korea remains one of the world’s largest refineries with a total crude capacity of 800,000 barrels per day. The company’s 60.6 percent-owned refinery in Map Ta Phut, Thailand, continues to supply high-quality petroleum products into regional markets.
Petroleum Refineries: Locations, Capacities and Crude Oil Inputs
Capacities and inputs in thousands of barrels per day December 31, 2022 Refinery Crude Oil Inputs
Locations Number Operable Capacity 2022 2021 2020
Pascagoula Mississippi 1 369 320 333 305
El Segundo California 1 290 248 233 176
Richmond California 1 257 167 211 198
Pasadena Texas 1 85 77 76 69
Salt Lake City Utah 1 58 53 50 45
Total Consolidated Companies - United States 5 1,059 865 903 793
Map Ta Phut Thailand 1 175 156 135 143
Total Consolidated Companies - International 1 175 156 135 143
Affiliates Various Locations1
2 545 483 441 441
Total Including Affiliates - International 3 720 639 576 584
Total Including Affiliates - Worldwide 8 1,779 1,504 1,479 1,377
1 In March 2020, the company sold its interest in the Pakistan refinery.
Marketing Operations
The company markets petroleum products under the principal brands of “Chevron,” “Texaco” and “Caltex” throughout many parts of the world. The following table identifies the company’s and its affiliates’ refined products sales volumes, excluding intercompany sales, for the three years ended December 31, 2022.
Refined Products Sales Volumes
Thousands of barrels per day 2022 2021 2020
United States
Gasoline 639 655 581
Jet Fuel 212 173 139
Diesel/Gas Oil 216 179 167
Fuel Oil 56 39 33
Other Petroleum Products1
105 93 83
Total United States 1,228 1,139 1,003
International2
Gasoline 336 321 264
Jet Fuel 196 140 143
Diesel/Gas Oil 464 471 438
Fuel Oil 168 177 184
Other Petroleum Products1
222 206 192
Total International 1,386 1,315 1,221
Total Worldwide2
2,614 2,454 2,224
1 Principally naphtha, lubricants, asphalt, and coke.
2 Includes share of affiliates’ sales:
389 357 348
In the United States, the company markets under the Chevron and Texaco brands. At year-end 2022, the company supplied directly or through retailers and marketers approximately 8,200 Chevron- and Texaco-branded service stations, primarily in the southern and western states. Approximately 310 of these outlets are company-owned or -leased stations.
Outside the United States, Chevron supplied directly or through retailers and marketers approximately 5,600 branded service stations, including affiliates. The company markets in Latin America using the Texaco brand. In the Asia-Pacific region and the Middle East, the company uses the Caltex brand. In South Korea, the company operates through its 50 percent-owned affiliate, GSC. In Australia, Chevron markets primarily under the Puma brand and began a rebranding project to transition to the Caltex brand in 2022. In March 2022, Chevron started allowing customers at Caltex service stations in Singapore to use their loyalty points to offset a portion of the greenhouse gas emissions from the combustion of the fuel purchased. In return, Chevron purchases and retires carbon offsets.
Chevron markets commercial aviation fuel to 63 airports worldwide. The company also markets an extensive line of lubricant and coolant products under the product names Havoline, Delo, Ursa, Meropa, Rando, Clarity and Taro in the United States and worldwide under these three brands: Chevron, Texaco and Caltex.
Chemicals Operations
Chevron Oronite Company develops, manufactures and markets performance additives for lubricating oils and fuels and conducts research and development for additive component and blended packages. At the end of 2022, the company manufactured, blended or conducted research at 11 locations around the world.
Chevron owns a 50 percent interest in Chevron Phillips Chemical Company LLC (CPChem). CPChem produces olefins, polyolefins and alpha olefins and is a supplier of aromatics and polyethylene pipe, in addition to participating in the specialty chemical and specialty plastics markets. At the end of 2022, CPChem owned or had joint-venture interests in 28 manufacturing facilities and two research and development centers around the world.
CPChem has recently reached final investment decision on two major integrated polymer projects. In fourth quarter 2022, final investment decision was made on the Golden Triangle Polymers Project in Orange, Texas, for which CPChem holds a 51 percent owned and operated interest. In January 2023, final investment decision was made on the Ras Laffan Petrochemical Project in Ras Laffan, Qatar for which CPChem holds a 30 percent nonoperated working interest. Startup for both projects is targeted for late 2026.
In second quarter 2022 CPChem reached final investment decision on a Low Viscosity Poly Alpha Olefin Expansion Project at the CPChem Beringen, Belgium site, with a targeted startup in third quarter 2024. CPChem also continued to progress several other major projects at existing facilities in the U.S. Gulf Coast region, including: an Ethylene Plant Debottleneck Project in Cedar Bayou, Texas, a C3 Splitter Project in Cedar Bayou, Texas, and a 1-Hexene plant in Old Ocean, Texas, all of which are targeted to startup in late 2023.
Chevron is also involved in the petrochemical business through the operations of GSC, the company’s 50 percent owned affiliate in South Korea. GSC manufactures aromatics, including benzene, toluene and xylene. These base chemicals are used to produce a range of products, including adhesives, plastics and textile fibers. GSC also produces olefins such as ethylene, polyethylene and polypropylene, which are used to make automotive and home appliance parts, food packaging, laboratory equipment, building materials, adhesives, paint and textiles.
Renewable Fuels
The company continued to advance development of renewable fuels, which include renewable natural gas (RNG), renewable diesel, biodiesel, sustainable aviation fuel, and renewable base oils and lubricants.
The company continued to advance activities with its joint venture partners, Brightmark Fund Holdings LLC (Brightmark) and California Bioenergy, LLC. (CalBio), to produce and market dairy biomethane. In January 2022, Chevron’s joint venture with Brightmark announced plans to construct an anaerobic digestion project in California and in August 2022 it achieved first gas from the Athena Project in South Dakota. In October 2022, the company expanded its partnership with CalBio to build additional infrastructure for dairy biomethane projects in California. In December 2022, Chevron acquired full ownership of Beyond6, LLC and its nationwide network of 55 compressed natural gas (CNG) stations to grow its renewable natural gas value chain.
In May 2022, Chevron formed a joint venture, Bunge Chevron Ag Renewables LLC, in which it holds a 50 percent working interest. The venture produces soybean oil from processing facilities in Destrehan, Louisiana, and Cairo, Illinois. Soybean oil can be used as a renewable feedstock to make renewable diesel, biodiesel, and sustainable aviation fuel.
In June 2022, Chevron completed the acquisition of the Renewable Energy Group, Inc. (REG), which has 11 biofuel refineries located in the U.S. and Germany, 10 biofuel refineries producing biodiesel and one producing renewable diesel. Work commenced in August 2022 at the Emden refinery in Germany that is expected to reduce the carbon intensity of the biofuel produced at the facility. Expansion work at the Geismar renewable diesel plant in Louisiana continues to be on track, with full capacity expected in 2024.
Progress continues at the company’s El Segundo Refinery in California to increase its capacity to produce renewable fuels through fluid catalytic cracking unit co-processing of bio-feedstock and conversion of the diesel hydrotreater.
Chevron developed renewable base oil through our patented technology and partnership with Novvi and integrated this renewable base oil into Chevron’s lubricant product lines. Chevron developed Havoline© PRO-RS™, which has lifecycle emissions that are 35 percent lower than those of conventional motor oil of equal viscosity. During 2022, the company made this renewable based lubricant available to U.S. consumers.
In April 2022, Chevron completed the purchase of the NEXBASE brand, associated qualifications and approvals, and related sales and marketing business from Neste Oyj. As part of the acquisition, Chevron maintains all current supply sources utilizing long-term offtake agreements. This addition of a fully approved global slate of Group III and renewable base oils complements Chevron’s Group II global slate.
Transportation
Pipelines Chevron owns and operates a network of crude oil, natural gas and product pipelines and other infrastructure assets in the United States. In addition, Chevron operates pipelines for its 50 percent-owned CPChem affiliate. The company also has direct and indirect interests in other U.S. and international pipelines.
Refer to Nigeria and Kazakhstan/Russia in the Upstream section for information on the West African Gas Pipeline and the Caspian Pipeline Consortium.
Shipping The company’s marine fleet includes both U.S. and foreign flagged vessels. The operated fleet consists of conventional crude tankers, product carriers and LNG carriers. These vessels transport crude oil, LNG, refined products and feedstock in support of the company’s global upstream and downstream businesses. In April 2022, Chevron joined the Global Centre for Maritime Decarbonisation (GCMD) as a strategic partner to the organization. The Singapore-based nonprofit was launched in August 2021 to help the International Maritime Organization meet its greenhouse gas emissions reduction goals for 2030 and 2050 by supporting cross-industry collaboration.
Other Businesses
Chevron Technical Center The company’s technical center develops and applies innovative technologies and digital solutions to support the current and future energy system.
The organization conducts research, develops and qualifies technology, and provides technical services and competency development. Areas of expertise include earth sciences, reservoir and production engineering, facilities engineering, reserve governance and reporting, capital projects, drilling and completions, asset performance, health, safety and environment, information technology, technology ventures, and downstream technology and services.
Chevron’s information technology organization integrates computing, telecommunications, data management, cybersecurity and network technology to provide a digital infrastructure to enable Chevron’s global operations and business processes.
The Chevron Technology Ventures (CTV) unit identifies and invests in externally developed technologies and new business solutions with the potential to enhance the way Chevron produces and delivers affordable, reliable, and ever-cleaner energy. CTV has more than two decades of being the on-ramp for external innovation into Chevron, including venture investing, with eight funds that have supported more than 120 startups and worked with more than 250 co-investors.
In addition to the company’s own managed funds, Chevron also makes investments indirectly through the following funds: the Oil and Gas Climate Initiative (OGCI) Climate Investments’ Catalyst Fund I, which targets decarbonization within the oil and gas, industrial, built environments and commercial transportation sectors; Emerald funds, one of which targets energy, water, food, mobility, industrial IT and advanced materials and another that focuses on sustainable packaging; Carbon Direct Capital, a growth equity investor in carbon management technologies; and the HX Venture Fund that targets Houston, Texas high-growth start-up companies.
Some of the investments the company makes in the areas described above are in new or unproven technologies and business processes; therefore, the ultimate technical or commercial successes of these investments are not certain. Refer to Note 27 Other Financial Information for quantification of the company’s research and development expenses.
Chevron New Energies The new energies organization is designed to advance the company’s strategy by bringing together dedicated resources focused on developing new lower carbon businesses that have the potential to scale. Its initial focus includes commercialization opportunities in hydrogen, carbon capture and storage, carbon offsets and emerging technologies such as geothermal. These businesses are expected to support the company’s efforts to reduce its greenhouse gas emissions and are also expected to become high-growth opportunities with the potential to generate competitive returns.
Environmental Protection The company designs, operates and maintains its facilities to avoid potential spills or leaks and to minimize the impact of those that may occur. Chevron requires its facilities and operations to have operating standards and processes and emergency response plans that address significant risks identified through site-specific risk and impact assessments. Chevron also requires that sufficient resources be available to execute these plans. In the unlikely event that a major spill or leak occurs, Chevron also maintains a Worldwide Emergency Response Team comprised of employees who are trained in various aspects of emergency response, including post-incident remediation.
To complement the company’s capabilities, Chevron maintains active membership in international oil spill response cooperatives, including the Marine Spill Response Corporation, which operates in U.S. territorial waters, and Oil Spill Response, Ltd., which operates globally. The company is a founding member of the Marine Well Containment Company, whose primary mission is to expediently deploy containment equipment and systems to capture and contain crude oil in the unlikely event of a future loss of control of a deepwater well in the Gulf of Mexico. In addition, the company is a member of the Subsea Well Response Project, which has the objective to further develop the industry’s capability to contain and shut in subsea well control incidents in different regions of the world.
The company aims to lower the carbon intensity of its traditional oil and gas operations and comply with the greenhouse gas-related laws and regulations to which it is subject. Refer to

Item 1A. Risk Factors
Item 1A. Risk Factors
As a global energy company, Chevron is subject to a variety of risks that could materially impact the company’s results of operations and financial condition.
BUSINESS AND OPERATIONAL RISK FACTORS
Chevron is exposed to the effects of changing commodity prices Chevron is primarily in a commodities business that has a history of price volatility. The most significant factor that affects the company’s results of operations is the price of crude oil, which can be influenced by general economic conditions and level of economic growth, including low or negative growth; industry production and inventory levels; technology advancements, including those in pursuit of a lower carbon economy; production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries or other producers; weather-related damage and disruptions due to other natural or human causes beyond our control (including without limitation due to the COVID-19 pandemic); competing fuel prices; geopolitical risks; the pace of energy transition; customer and consumer preferences and the use of substitutes; and governmental regulations, policies and other actions regarding the development of oil and gas reserves, as well as greenhouse gas emissions and climate change. Chevron evaluates the risk of changing commodity prices as a core part of its business planning process. An investment in the company carries significant exposure to fluctuations in global crude oil prices.
Extended periods of low prices for crude oil can have a material adverse impact on the company’s results of operations, financial condition and liquidity. Among other things, the company’s upstream earnings, cash flows, and capital expenditure programs could be negatively affected, as could its production and proved reserves. Upstream assets may also become impaired. Downstream earnings could be negatively affected because they depend upon the supply and demand for refined products and the associated margins on refined product sales. A significant or sustained decline in liquidity could adversely affect the company’s credit ratings, potentially increase financing costs and reduce access to capital markets. The company may be unable to realize anticipated cost savings, expenditure reductions and asset sales that are intended to compensate for such downturns, and such downturns may also slow the pace and scale at which we are able to invest in new business lines such as the lower carbon businesses associated with our Chevron New Energies organization. In some cases, liabilities associated with divested assets may return to the company when an acquirer of those assets subsequently declares bankruptcy. In addition, extended periods of low commodity prices can have a material adverse impact on the results of operations, financial condition and liquidity of the company’s suppliers, vendors, partners and equity affiliates upon which the company’s own results of operations and financial condition depends.
The scope of Chevron’s business will decline if the company does not successfully develop resources The company is in an extractive business; therefore, if it is not successful in replacing the crude oil and natural gas it produces with good prospects for future organic opportunities or through acquisitions, the company’s business will decline. Creating and maintaining an inventory of projects depends on many factors, including obtaining and renewing rights to explore, develop and produce hydrocarbons; drilling success; reservoir optimization; ability to bring long-lead-time, capital-intensive projects to completion on budget and on schedule; partner alignment, including strategic support; and efficient and profitable operation of mature properties.
The company’s operations could be disrupted by natural or human causes beyond its control Chevron operates in both urban areas and remote and sometimes inhospitable regions. The company’s operations are therefore subject to disruption from natural or human causes beyond its control, including risks from hurricanes, severe storms, floods, heat waves, other forms of severe weather, wildfires, ambient temperature increases, sea level rise, war or other military conflicts such as the ongoing conflict in Ukraine, accidents, civil unrest, political events, fires, earthquakes, system failures, cyber threats, terrorist acts and epidemic or pandemic diseases such as the COVID-19 pandemic, some of which may be impacted by climate change and any of which could result in suspension of operations or harm to people or the natural environment.
Chevron’s risk management systems are designed to assess potential physical and other risks to its operations and assets and to plan for their resiliency. While capital investment reviews and decisions incorporate potential ranges of physical risks such as storm severity and frequency, sea level rise, air and water temperature, precipitation, fresh water access, wind speed, and earthquake severity, among other factors, it is difficult to predict with certainty the timing, frequency or severity of such events, any of which could have a material adverse effect on the company's results of operations or financial condition.
Impacts of the continuation or further resurgences of the COVID-19 pandemic may have an adverse and potentially material adverse effect on Chevron’s financial and operating results The economic, business, and oil and gas industry impacts from the COVID-19 pandemic and the disruption to capital markets have been far reaching. While the oil and gas industry has witnessed a substantial recovery of commodity prices and demand for products, there continues to be uncertainty and unpredictability about the impact of the COVID-19 pandemic on our financial and operating results in future periods. The extent to which the COVID-19 pandemic adversely impacts our future financial and operating results, and for what duration and magnitude, depends on several factors that are continuing to evolve, are difficult to predict and, in many instances, are beyond the company’s control. Such factors include the duration and scope of the pandemic, including any further resurgences of the COVID-19 virus and its variants, and the impact on our workforce and operations; the negative impact of the pandemic on the economy and economic activity, including travel restrictions and prolonged low demand for our products; the ability of our affiliates, suppliers and partners to successfully navigate the impacts of the pandemic; the actions taken by governments, businesses and individuals in response to the pandemic; the actions of OPEC and other countries that otherwise impact supply and demand and, correspondingly, commodity prices; the extent and duration of recovery of economies and demand for our products after the pandemic subsides; and Chevron’s ability to keep its cost model in line with changing demand for our products. In-country conditions, including potential future waves of the COVID-19 virus and its variants in countries that appear to have reduced their infection rates, could impact logistics and material movement and remain a risk to business continuity.
In light of the significant uncertainty around the duration and extent of the impact of the COVID-19 pandemic, management is currently unable to develop with any level of confidence estimates and assumptions that may have a material impact on the company’s consolidated financial statements and financial or operational performance in any given period. In addition, the unprecedented nature of such market conditions could cause current management estimates and assumptions to be challenged in hindsight.
In addition, further resurgences of the pandemic could precipitate or aggravate the other risk factors identified in this Form 10-K, which in turn could materially and adversely affect our business, financial condition, liquidity, results of operations and profitability, including in ways not currently known or considered by us to present significant risks.
Cyberattacks targeting Chevron’s process control networks or other digital infrastructure could have a material adverse impact on the company’s business and results of operations There are numerous and evolving risks to Chevron’s cybersecurity and privacy from cyber threat actors, including criminal hackers, state-sponsored intrusions, industrial espionage and employee malfeasance. These cyber threat actors, whether internal or external to Chevron, are becoming more sophisticated and coordinated in their attempts to access the company’s information technology (IT) systems and data, including the IT systems of cloud providers and other third parties with whom the company conducts business
through, without limitation, malicious software; data privacy breaches by employees, insiders or others with authorized access; cyber or phishing-attacks; ransomware; attempts to gain unauthorized access to our data and systems; and other electronic security breaches. Although Chevron devotes significant resources to prevent unwanted intrusions and to protect its systems and data, whether such data is housed internally or by external third parties, the company has experienced and will continue to experience cyber incidents of varying degrees in the conduct of its business. Cyber threat actors could compromise the company’s process control networks or other critical systems and infrastructure, resulting in disruptions to its business operations, injury to people, harm to the environment or its assets, disruptions in access to its financial reporting systems, or loss, misuse or corruption of its critical data and proprietary information, including without limitation its intellectual property and business information and that of its employees, customers, partners and other third parties. Any of the foregoing can be exacerbated by a delay or failure to detect a cyber incident or the full extent of such incident. Further, the company has exposure to cyber incidents and the negative impacts of such incidents related to its critical data and proprietary information housed on third-party IT systems, including the cloud. Additionally, authorized third-party IT systems or software can be compromised and used to gain access or introduce malware to Chevron's IT systems that can materially impact the company’s business. Regardless of the precise method or form, cyber events could result in significant financial losses, legal or regulatory violations, reputational harm, and legal liability and could ultimately have a material adverse effect on the company’s business and results of operations.
The company’s operations have inherent risks and hazards that require significant and continuous oversight Chevron’s results depend on its ability to identify and mitigate the risks and hazards inherent to operating in the energy industry. The company seeks to minimize these operational risks by carefully designing and building its facilities and conducting its operations in a safe and reliable manner. However, failure to manage these risks effectively could impair our ability to operate and result in unexpected incidents, including releases, explosions or mechanical failures resulting in personal injury, loss of life, environmental damage, loss of revenues, legal liability and/or disruption to operations. Chevron has implemented and maintains a system of corporate policies, processes and systems, behaviors and compliance mechanisms to manage safety, health, environmental, reliability and efficiency risks; to verify compliance with applicable laws and policies; and to respond to and learn from unexpected incidents. In certain situations where Chevron is not the operator, the company may have limited influence and control over third parties, which may limit its ability to manage and control such risks.
The company does not insure against all potential losses, which could result in significant financial exposure The company does not have commercial insurance or third-party indemnities to fully cover all operational risks or potential liability in the event of a significant incident or series of incidents causing catastrophic loss. As a result, the company is, to a substantial extent, self-insured for such events. The company relies on existing liquidity, financial resources and borrowing capacity to meet short-term obligations that would arise from such an event or series of events. The occurrence of a significant incident, series of events, or unforeseen liability for which the company is self-insured, not fully insured or for which insurance recovery is significantly delayed could have a material adverse effect on the company’s results of operations or financial condition.
LEGAL, REGULATORY AND ESG-RELATED RISK FACTORS
Chevron’s business subjects the company to liability risks from litigation or government action The company produces, transports, refines and markets potentially hazardous materials, and it purchases, handles and disposes of other potentially hazardous materials in the course of its business. Chevron's operations also produce byproducts, which may be considered pollutants. Often these operations are conducted through joint ventures over which the company may have limited influence and control. Any of these activities could result in liability or significant delays in operations arising from private litigation or government action. For example, liability or delays could result from an accidental, unlawful discharge or from new conclusions about the effects of the company’s operations on human health or the environment. In addition, to the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.
For information concerning some of the litigation in which the company is involved, see Note 16 Litigation.
Political instability and significant changes in the legal and regulatory environment could harm Chevron’s business The company’s operations, particularly exploration and production, can be affected by changing political, regulatory and economic environments in the various countries in which it operates. As has occurred in the past, actions could be taken by governments to increase public ownership of the company’s partially or wholly owned businesses, to force contract renegotiations, or to impose additional taxes or royalties. In certain locations, governments have proposed or imposed
restrictions on the company’s operations, trade, currency exchange controls, burdensome taxes, and public disclosure requirements that might harm the company’s competitiveness or relations with other governments or third parties. In other countries, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries, and internal unrest, acts of violence or strained relations between a government and the company or other governments may adversely affect the company’s operations. Those developments have, at times, significantly affected the company’s operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries. Further, Chevron is required to comply with sanctions and other trade laws and regulations of the United States and other jurisdictions where we operate which, depending upon their scope, could adversely impact the company’s operations and financial results in certain countries. In addition, litigation or changes in national, state or local environmental regulations or laws, including those designed to stop or impede the development or production of oil and gas, such as those related to the use of hydraulic fracturing or bans on drilling, or any law or regulation that impacts the demand for our products, could adversely affect the company’s current or anticipated future operations and profitability.
Legislative or regulatory changes in tax laws may expose Chevron to additional tax liabilities Changes in tax laws and regulations around the world are regularly enacted due to political or economic factors beyond the company’s control. Chevron’s taxes in the jurisdictions where the company conducts business activities have been and may be adversely affected by changes in tax laws or regulations, including but not limited to, substantive changes in, reductions in, or the repeal or expiration of tax incentives, such as U.S. federal tax incentives for biodiesel blending, which expire in 2024. Furthermore, Chevron’s tax returns are subject to audit by taxing authorities around the world. There is no assurance that taxing authorities or courts will agree with the positions that Chevron has reflected on the company’s tax returns, in which case interest and penalties could be imposed that may have a material adverse effect on the company’s results of operations or financial condition.
During periods of high profitability for certain companies or industries, there are often calls for increased taxes on profits, often called “windfall profit” taxes. Governments in various jurisdictions, including California and Australia, have announced, proposed, or implemented windfall profit taxes for companies operating in the energy and oil and gas sectors. Such taxes may be imposed on us or may be increased in the future in these or other jurisdictions. The imposition of, or increase in, such windfall profit taxes could adversely affect the company’s current or anticipated future operations and profitability.
For information concerning the company’s tax liabilities, see Note 17 Taxes and Note 24 Other Contingencies and Commitments.
Legislation, regulation, and other government actions and shifting customer and consumer preferences and other private efforts related to greenhouse gas (GHG) emissions and climate change could continue to increase Chevron’s operational costs and reduce demand for Chevron’s hydrocarbon and other products, resulting in a material adverse effect on the company’s results of operations and financial condition Chevron has experienced and may be further challenged by increases in the impacts of international and domestic legislation, regulation, or other government actions relating to GHG emissions (e.g., carbon dioxide and methane) and climate change. International agreements and national, regional, and state legislation and regulatory measures that aim to directly or indirectly limit or reduce GHG emissions are in various stages of implementation.
Legislation, regulation, and other government actions related to GHG emissions and climate change could reduce demand for Chevron’s hydrocarbon and other products and/or continue to increase Chevron’s operational costs. The Paris Agreement went into effect in November 2016, and a number of countries in which we operate may adopt additional policies to meet their Paris Agreement goals. Globally, multiple jurisdictions are considering adopting or are in the process of implementing laws or regulations to directly regulate GHG emissions through similar or other mechanisms, such as a carbon tax, a cap-and-trade program, or performance standards, or to indirectly advance reduction of GHG emissions through restrictive permitting, trade tariffs, minimum renewable usage requirements, increased GHG reporting and climate-related disclosure requirements, or tax advantages or other incentives to promote the use of alternative energy, fuel sources or lower-carbon technologies. For example, the company is currently subject to implemented programs in certain jurisdictions, such as the Renewable Fuel Standard program in the U.S., California’s Cap-and-Trade Program and Low Carbon Fuel Standard, and newly approved mandates such as the California Air Resources Board Advanced Clean Cars II regulations, as well as other indirect regulation of GHG emissions, which may, among other things, ban or restrict technologies or products that use the company’s hydrocarbon products. GHG emissions that may be directly regulated through such efforts include, among others, those associated with the company’s exploration and production of
hydrocarbons; the upgrading of production from oil sands into synthetic oil; power generation; the conversion of crude oil and natural gas into refined hydrocarbon products; the processing, liquefaction, and regasification of natural gas; the transportation of crude oil, natural gas, and related products; and customers’ and consumers’ use of the company’s hydrocarbon products. In addition, the U.S. Inflation Reduction Act (IRA) implements various incentives for lower carbon activities, including carbon capture and storage and the production of hydrogen and sustainable aviation fuel. Although the IRA offers incentives that could support certain lower carbon lines of business, those same incentives could negatively impact demand for our traditional base business of oil and gas products in the future or any existing or future lower carbon business lines. Many of these actions, as well as customers’ and consumers’ preferences and use of the company’s products or substitute products, and actions taken by the company’s competitors in response to legislation and regulations, are beyond the company’s control.
Similar to any significant changes in the regulatory environment, climate change-related legislation, regulation, or other government actions may curtail profitability in the oil and gas sector or render the extraction of the company’s hydrocarbon resources economically infeasible. In particular, GHG emissions-related legislation, regulations, and other government actions and shifting customer and consumer preferences and other private efforts aimed at reducing GHG emissions may result in increased and substantial capital, compliance, operating, and maintenance costs and could, among other things, reduce demand for hydrocarbons and the company’s hydrocarbon-based products; increase demand for lower carbon products and alternative energy sources; make the company’s products more expensive; adversely affect the economic feasibility of the company’s resources; impact or limit our business plans; and adversely affect the company’s sales volumes, revenues, margins and reputation. For example, some jurisdictions are in various stages of design, adoption, and implementation of policies and programs that cap emissions and/or require short-, medium-, and long-term GHG reductions by operators at the asset or facility level, which may not be technologically feasible, or which could require significant capital expenditure, increase costs of or limit production and limit Chevron’s ability to cost-effectively reduce GHG emissions across its global portfolio.
The ultimate effect of international agreements; national, regional, and state legislation and regulation; and government and private actions related to GHG emissions and climate change on the company’s financial performance, and the timing of these effects, will depend on a number of factors. Such factors include, among others, the sectors covered, the GHG emissions reductions required, the extent to which Chevron would be entitled to receive emission allowance allocations or would need to purchase compliance instruments on the open market or through auctions, the price and availability of emission allowances and credits and the extent to which the company is able to recover, or continue to recover, the costs incurred through the pricing of the company’s products in the competitive marketplace. Further, the ultimate impact of GHG emissions and climate change-related agreements, legislation, regulation, and government actions on the company’s financial performance is highly uncertain because the company is unable to predict with certainty, for a multitude of individual jurisdictions, the outcome of political decision-making processes, including the actual laws and regulations enacted, the variables and tradeoffs that inevitably occur in connection with such processes, and market conditions.
Increasing attention to environmental, social, and governance (ESG) matters may impact our business Increasing attention to ESG matters, including those related to climate change and sustainability, increasing societal, investor and legislative pressure on companies to address ESG matters, and potential customer and consumer use of substitutes to Chevron’s products may result in changes to the portfolio of company activities, increased costs, reduced demand for our products, reduced profits, increased investigations and litigation or threats thereof, negative impacts on our stock price and access to capital markets, and damage to our reputation. Increasing attention to climate change, for example, may result in demand shifts for our hydrocarbon products and additional governmental investigations and private litigation, or threats thereof, against the company. For instance, we have received investigative requests and demands from the U.S. Congress for information relating to climate change, methane leak detection and repair, and other topics, and further requests and/or demands are possible. At this time, Chevron cannot predict the ultimate impact any Congressional or other investigations may have on the company.
Some stakeholders, including but not limited to sovereign wealth, pension, and endowment funds, have been divesting and promoting divestment of or screening out of fossil fuel equities and urging lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Further, voluntary carbon-related and target-setting frameworks have developed, and continue to develop, that limit the ability of certain sectors, including the oil and gas sector, from participating, and may result in exclusion of the company’s equity from being included as an investment option in portfolios. In addition, some stakeholders, including some of our investors, have divergent views on our ESG-related strategies and priorities, vis-à-vis our traditional and lower carbon lines of business, calling for focus on increased production of oil and gas products
rather than new business lines and climate-related targets. These circumstances, among others, may result in pressure from activists on production; unfavorable reputational impacts, including inaccurate perceptions or a misrepresentation of our actual ESG policies and practices; diversion of management’s attention and resources; and proxy fights, among other material adverse impacts on our businesses.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters, including climate change and climate-related risks (including entities commonly referred to as “raters and rankers”). Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and investment community divestment initiatives, among other actions, may lead to negative investor sentiment toward Chevron and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Additionally, evolving expectations on various ESG matters, including biodiversity, waste and water, may increase costs, require changes in how we operate and lead to negative stakeholder sentiment.
Our aspirations, targets and disclosures related to ESG matters subject us to numerous risks that may negatively impact our reputation and stock price or result in other material adverse impacts to the company Chevron has announced an aspiration to achieve net zero Scope 1 and 2 emissions in upstream by 2050. The company also has set nearer-term GHG emission-related targets for zero routine flaring, upstream carbon intensity, and portfolio carbon intensity. These and other aspirations, targets or objectives reflect our current plans and aspirations and are not guarantees that we will achieve them, particularly as we encounter new opportunities and/or limitations as our portfolio and market conditions evolve.
Our ability to achieve any aspiration, target or objective, including with respect to climate-related initiatives, our new lower carbon strategy outlined in the Management’s Discussion and Analysis of Financial Condition and Results of Operations, pages 32 through 34, and any lower carbon new energy businesses, is subject to numerous risks, many of which are outside of our control. Examples of such risks include: (1) the continuing progress of commercially viable technologies and low- or non-carbon-based energy sources; (2) the granting of necessary permits by governing authorities; (3) the availability and acceptability of cost-effective, verifiable carbon credits; (4) the availability of suppliers that can meet our sustainability and other standards; (5) evolving regulatory requirements affecting ESG standards or disclosures; (6) evolving standards for tracking and reporting on emissions and emission reductions and removals; (7) customers’ and consumers’ preferences and use of the company’s products or substitute products; and (8) actions taken by the company’s competitors in response to legislation and regulations.
The standards for tracking and reporting on ESG matters are relatively new, have not been harmonized and continue to evolve. Our selection of disclosure frameworks that seek to align with various voluntary reporting standards may change from time to time and may result in a lack of comparative data from period to period. In addition, our processes and controls may not always align with evolving voluntary standards for identifying, measuring, and reporting ESG metrics, our interpretation of reporting standards may differ from those of others, and such standards may change over time, any of which could result in significant revisions to our goals or reported progress in achieving such goals. Achievement of or efforts to achieve aspirations, targets, goals and objectives such as the foregoing and future internal climate-related initiatives may increase costs, require purchase of carbon credits, or limit or impact the company’s business plans, operations and financial results, potentially resulting in the reduction to the economic end-of-life of certain assets, an impairment of the associated net book value, among other material adverse impacts. Our failure or perceived failure to pursue or fulfill such aspirations, targets, goals and objectives or to satisfy various reporting standards within the timelines we announce, or at all, could have a negative impact on the company’s reputation, investor sentiment, ratings outcomes for evaluating the company’s approach to ESG matters, stock price, and cost of capital and expose us to government enforcement actions and private litigation, among other material adverse impacts.
GENERAL RISK FACTORS
Changes in management’s estimates and assumptions may have a material impact on the company’s consolidated financial statements and financial or operational performance in any given period In preparing the company’s periodic reports under the Securities Exchange Act of 1934, including its financial statements, Chevron’s management is required under applicable rules and regulations to make estimates and assumptions as of a specified date. These estimates and assumptions are based on management’s best estimates and experience as of that date and are subject to substantial risk and uncertainty. Materially different results may occur as circumstances change and additional information becomes known. Areas requiring significant estimates and assumptions by management include impairments to property, plant and equipment and investments in affiliates; estimates of crude oil and natural gas recoverable reserves; accruals for estimated
liabilities, including litigation reserves; and measurement of benefit obligations for pension and other postretirement benefit plans. Changes in estimates or assumptions or the information underlying the assumptions, such as changes in the company’s business plans, general market conditions, the pace of energy transition, or changes in the company’s outlook on commodity prices, could affect reported amounts of assets, liabilities or expenses.

Item 1B. Unresolved Staff Comments
Item 1B. Unresolved Staff Comments
None.

Item 2. Properties
Item 2. Properties
The location and character of the company’s crude oil and natural gas properties and its refining, marketing, transportation, and chemicals facilities are described beginning on page 3 under Item 1. Business. Information required by Subpart 1200 of Regulation S-K (“Disclosure by Registrants Engaged in Oil and Gas Producing Activities”) is also contained in Item 1 and in Tables I through VII on pages 99 through 111 and Note 18 Properties, Plant and Equipment.

Item 3. Legal Proceedings
Item 3. Legal Proceedings
The following is a description of legal proceedings that involve governmental authorities as a party and the company reasonably believes would result in $1.0 million or more of monetary sanctions, exclusive of interest and costs, under federal, state and local laws that have been enacted or adopted regulating the discharge of materials into the environment or primarily for the purpose of protecting the environment.
As previously disclosed, the California Department of Fish and Game, Office of Spill Prevention and Response issued a Complaint - Notice of Violation (NOV) to Chevron for alleged violations related to oil spills and impacted habitat and species occurring between January 2018 and May 2022 at different Chevron fields within Kern County, California. Resolution of the alleged violations may result in the payment of a civil penalty of $1.0 million or more.
As previously disclosed, the California Department of Conservation, California Geologic Energy Management Division (CalGEM) (previously known as the Division of Oil, Gas and Geothermal Resources) promulgated revised rules pursuant to the Underground Injection Control program that took effect April 1, 2019. Subsequent to that date, CalGEM issued NOVs and two orders to Chevron related to seeps that occurred in the Cymric Oil Field in Kern County, California. An October 2, 2019 CalGEM order seeks a civil penalty of approximately $2.7 million. Chevron has filed an appeal of this order. Chevron is currently in discussions with CalGEM to explore a global settlement to resolve the order and all past and present seeps in the Cymric Field, which would increase the amount of penalty paid.
Please see information related to other legal proceedings in Note 16 Litigation.

Item 4. Mine Safety Disclosures
Item 4. Mine Safety Disclosures
Not applicable.
Information about our Executive Officers
Information relating to the company’s executive officers is included under “Information about our Executive Officers” in Part III, Item 10, Directors, Executive Officers and Corporate Governance, and is incorporated herein by reference.
PART II

Item 5. Market for Registrant's Common Equity
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of February 10, 2023, stockholders of record numbered approximately 104,000. There are no restrictions on the company’s ability to pay dividends. The information on Chevron’s dividends are contained in the Quarterly Results tabulation.
Chevron Corporation Issuer Purchases of Equity Securities for Quarter Ended December 31, 2022
Total Number Average Total Number of Shares Approximate Dollar Values of Shares that
of Shares Price Paid Purchased as Part of Publicly May Yet be Purchased Under the Program
Period Purchased 1,2
per Share Announced Program (Billions of dollars) 2
October 1 - October 31, 2022 7,582,842 $165.65 7,582,805 $9.4
November 1 - November 30, 2022 6,967,090 $183.00 6,966,715 $8.1
December 1 - December 31, 2022 6,972,807 $174.82 6,972,807 $6.9
Total October 1 - December 31, 2022 21,522,739 $174.24 21,522,327
1Includes common shares repurchased from participants in the company's deferred compensation plans for personal income tax withholdings.
2Refer to Liquidity and Capital Resources for additional detail regarding the company's authorized stock repurchase program.

Item 6. Selected Financial Data
Item 6. [Reserved]

Item 7. Management's Discussion and Analysis
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The index to Management’s Discussion and Analysis of Financial Condition and Results of Operations is presented in the Financial Table of Contents.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The company’s discussion of interest rate, foreign currency and commodity price market risk is contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial and Derivative Instruments and in Note 10 Financial and Derivative Instruments.

Item 8. Financial Statements and Supplementary Data
Item 8. Financial Statements and Supplementary Data
The index to Financial Statements and Supplementary Data is presented in the Financial Table of Contents.

Item 9. Changes in and Disagreements with Accountants
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.

Item 9A. Controls and Procedures
Item 9A. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures The company’s management has evaluated, with the participation of the Chief Executive Officer and the Chief Financial Officer, the effectiveness of the company’s disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (Exchange Act)) as of the end of the period covered by this report. Based on this evaluation, management concluded that the company’s disclosure controls and procedures were effective as of December 31, 2022.
(b) Management’s Report on Internal Control Over Financial Reporting The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in the Exchange Act Rules 13a-15(f) and 15d-15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s internal control over financial reporting based on the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the results of this evaluation, the company’s management concluded that internal control over financial reporting was effective as of December 31, 2022.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2022, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein.
(c) Changes in Internal Control Over Financial Reporting During the quarter ended December 31, 2022, there were no changes in the company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the company’s internal control over financial reporting.

Item 9B. Other Information
Item 9B. Other Information
Rule 10b5-1 Plan Elections
R. Hewitt Pate, Vice President and General Counsel, entered into a pre-arranged stock trading plan on November 17, 2022. Mr. Pate’s plan provides for the potential exercise of vested stock options and the associated sale of up to 250,742 shares of Chevron common stock between February 20, 2023 and February 8, 2024.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
PART III

Item 10. Directors, Executive Officers and Corporate Governance
Item 10. Directors, Executive Officers and Corporate Governance
Information about our Executive Officers at February 23, 2023
Members of the Corporation’s Executive Committee are the Executive Officers of the Corporation:
Name Age Current and Prior Positions (up to five years) Primary Areas of Responsibility
Michael K. Wirth 62 Chairman of the Board and Chief Executive Officer (since Feb 2018)
Chairman of the Board and
Chief Executive Officer
Pierre R. Breber 58 Vice President and Chief Financial Officer (since Apr 2019)
Executive Vice President, Downstream (Jan 2016 - Mar 2019) Finance; Procurement
A. Nigel Hearne 55 Executive Vice President, Oil, Products & Gas (since Oct 2022)
President, Chevron Eurasia Pacific Exploration & Production (July
2020 - Oct 2022)
President, Chevron Asia Pacific Exploration & Production (Jan 2019
- June 2020)
Managing Director, Australia Business Unit (July 2016 - Dec 2018)
Upstream - Worldwide Exploration and Production;
Downstream - Worldwide Manufacturing, Marketing, Lubricants, and Chemicals;
Midstream - Worldwide
Mark A. Nelson 59 Vice Chairman and Executive Vice President, Strategy, Policy & Development (since Feb 2023)
Executive Vice President, Strategy, Policy & Development (Oct
2022 - Feb 2023)
Executive Vice President, Downstream (since Mar 2019 - Sep 2022)
Vice President, Midstream, Strategy and Policy (Feb 2018 - Feb
2019)
Strategy & Sustainability; Corporate Affairs; Corporate Business Development
Eimear P. Bonner 48 Vice President (since Aug 2021), Chief Technology Officer and
President of Chevron Technical Center (since Feb 2021)
General Director of Tengizchevroil (Dec 2018 - Jan 2021)
General Manager of Operations of Tengizchevroil (Nov 2015 - Nov
2018) Information Technology; Subsurface; Global Reserves; Wells; Asset Performance and Process Safety; Facilities Designs and Solutions; Capital Projects; Health, Safety and Environment; Downstream Technology
Jeff B. Gustavson 50 Vice President, Lower Carbon Energies (since Aug 2021)
Vice President, Chevron North America Exploration & Production
(Feb 2018 - July 2021) Lower Carbon Solutions
Rhonda J. Morris 57 Vice President and Chief Human Resources Officer (since Feb 2019)
Vice President, Human Resources (Oct 2016 - Jan 2019) Human Resources; Diversity and Inclusion
R. Hewitt Pate 60 Vice President and General Counsel (since Aug 2009) Law, Governance and Compliance
The information about directors required by Item 401(a), (d), (e) and (f) of Regulation S-K and contained under the heading “Election of directors” in the Notice of the 2023 Annual Meeting of Stockholders and 2023 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act in connection with the company’s 2023 Annual Meeting (the 2023 Proxy Statement), is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 406 of Regulation S-K and contained under the heading “Corporate governance - Business conduct and ethics code” in the 2023 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(d)(4) and (5) of Regulation S-K and contained under the heading “Corporate governance - Board committees” in the 2023 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

Item 11. Executive Compensation
Item 11. Executive Compensation
The information required by Item 402 of Regulation S-K and contained under the headings “Executive compensation,” “Director compensation” and “CEO pay ratio” in the 2023 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(e)(5) of Regulation S-K and contained under the heading “Corporate governance - Management compensation committee report” in the 2023 Proxy Statement is incorporated herein by reference into this Annual Report on Form 10-K. Pursuant to the rules and regulations of the SEC under the Exchange Act, the information under such caption incorporated by reference from the 2023 Proxy Statement shall not be deemed to be “soliciting material,” or to be “filed” with the Commission, or subject to Regulation 14A or 14C or the liabilities of Section 18 of the Exchange Act, nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933.

Item 12. Security Ownership of Certain Beneficial Owners and Management
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by Item 403 of Regulation S-K and contained under the heading “Stock ownership information - Security ownership of certain beneficial owners and management” in the 2023 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 201(d) of Regulation S-K and contained under the heading “Equity compensation plan information” in the 2023 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

Item 13. Certain Relationships and Related Transactions
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by Item 404 of Regulation S-K and contained under the heading “Corporate governance - Related person transactions” in the 2023 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(a) of Regulation S-K and contained under the heading “Corporate governance - Director independence” in the 2023 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

Item 14. Principal Accountant Fees and Services
Item 14. Principal Accountant Fees and Services
The information required by Item 9(e) of Schedule 14A and contained under the heading “Board proposal to ratify PricewaterhouseCoopers LLP as the independent registered public accounting firm for 2023” in the 2023 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
Financial Table of Contents
Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents
Key Financial Results
Millions of dollars, except per-share amounts 2022 2021 2020
Net Income (Loss) Attributable to Chevron Corporation $ 35,465 $ 15,625 $ (5,543)
Per Share Amounts:
Net Income (Loss) Attributable to Chevron Corporation
- Basic $ 18.36 $ 8.15 $ (2.96)
- Diluted $ 18.28 $ 8.14 $ (2.96)
Dividends $ 5.68 $ 5.31 $ 5.16
Sales and Other Operating Revenues $ 235,717 $ 155,606 $ 94,471
Return on:
Capital Employed 20.3 % 9.4 % (2.8) %
Stockholders’ Equity 23.8 % 11.5 % (4.0) %
Earnings by Major Operating Area
Millions of dollars 2022 2021 2020
Upstream
United States $ 12,621 $ 7,319 $ (1,608)
International 17,663 8,499 (825)
Total Upstream 30,284 15,818 (2,433)
Downstream
United States 5,394 2,389 (571)
International 2,761 525 618
Total Downstream 8,155 2,914 47
All Other (2,974) (3,107) (3,157)
Net Income (Loss) Attributable to Chevron Corporation1,2
$ 35,465 $ 15,625 $ (5,543)
1 Includes foreign currency effects:
$ 669 $ 306 $ (645)
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, 2022. 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 substantial business activities in the following countries: Angola, Argentina, Australia, Bangladesh, Brazil, Canada, China, Egypt, Equatorial Guinea, Israel, Kazakhstan, Mexico, Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait, the Philippines, Republic of Congo, Singapore, South Korea, Thailand, the United Kingdom, the United States, and Venezuela.
The company’s objective is to safely deliver higher returns, lower carbon and superior shareholder value in any business environment. Earnings of the company depend mostly on the profitability of its upstream business segment. The most significant factor affecting the results of operations for the upstream segment is the price of crude oil, which is determined in global markets outside of the company’s control. In the company’s downstream business, crude oil is the largest cost component of refined products. Periods of sustained lower commodity prices could result in the impairment or write-off of specific assets in future periods and cause the company to adjust operating expenses, including employee reductions, and capital expenditures, along with other measures intended to improve financial performance.
Governments, companies, communities, and other stakeholders are increasingly supporting efforts to address climate change. International initiatives and national, regional and state legislation and regulations that aim to directly or indirectly reduce GHG emissions are in various stages of design, adoption, and implementation. These policies and programs, some of which support the global net zero emissions ambitions of the Paris Agreement, can change the amount of energy consumed, the rate of energy-demand growth, the energy mix, and the relative economics of one fuel versus another. Implementation of jurisdiction-specific policies and programs can be dependent on, and can affect the pace of, technological advancements, the granting of necessary permits by governing authorities, the availability of cost-effective, verifiable carbon credits, the availability of suppliers that can meet sustainability and other standards, evolving regulatory or other requirements affecting ESG standards or other disclosures, and evolving standards for tracking and reporting on emissions and emission reductions and removals.
Some of these policies and programs include renewable and low carbon fuel standards, such as the Renewable Fuel Standard program in the U.S. and California’s Low Carbon Fuel Standard; programs that price GHG emissions, including
Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents
California’s Cap-and-Trade Program; performance standards, including methane-specific regulation such as the U.S. EPA’s forthcoming New Source Performance Standard and Emissions Guidelines for Existing Sources; and measures that provide various incentives for lower carbon activities, including carbon capture and storage and the production of hydrogen and sustainable aviation fuel, such as the U.S. Inflation Reduction Act. Requirements for these and other similar policies and programs are complex, ever changing, program specific and encompass: (1) the blending of renewable fuels into transportation fuels; (2) the purchasing, selling, utilizing and retiring of allowances and carbon credits; and (3) other emissions reduction measures including efficiency improvements and capturing GHG emissions. While these compliance policies and programs may have negative impacts on the company now and in the future including, but not limited to, the displacement of hydrocarbon and other products, these policies have also enabled opportunities for Chevron as it grows and aims to further grow its lower carbon businesses. For example, the acquisition of Renewable Energy Group, Inc. (REG) in 2022 grew the company’s renewable fuels production capacity and increased the company’s carbon credit generation activities. Although we expect the company’s costs to comply with these policies and programs to continue to increase, these costs currently do not have a material impact on the company’s financial condition or results of operations.
Significant uncertainty remains as to the pace in which the transition to a lower carbon future will progress, which is dependent, in part, on further advancements and changes in policy, technology, and customer and consumer preferences. The level of expenditure required to comply with new or potential climate change-related laws and regulations and the amount of additional investments needed in new or existing technology or facilities, such as carbon capture and storage, is difficult to predict with certainty and is expected to vary depending on the actual laws and regulations enacted, available technology options, customer and consumer preferences, the company’s activities, and market conditions. As discussed below, in 2021, the company announced planned capital spend of approximately $10 billion through 2028 in lower carbon investments. Although the future is uncertain, many published outlooks conclude that fossil fuels will remain a significant part of an energy system that increasingly incorporates lower carbon sources of supply for many years to come.
Chevron supports the Paris Agreement’s global approach to governments addressing climate change and continues to take actions to help lower the carbon intensity of its operations while continuing to meet the demand for energy. Chevron believes that broad, market-based mechanisms are the most efficient approach to addressing GHG emission reductions. Chevron integrates climate change-related issues and the regulatory and other responses to these issues into its strategy and planning, capital investment reviews, and risk management tools and processes, where it believes they are applicable. They are also factored into the company’s long-range supply, demand, and energy price forecasts. These forecasts reflect estimates of long-range effects from climate change-related policy actions, such as electric vehicle and renewable fuel penetration, energy efficiency standards, and demand response to oil and natural gas prices.
The company will continue to develop oil and gas resources to meet customers’ and consumers’ demand for energy. At the same time, Chevron believes that the future of energy is lower carbon. The company will continue to maintain flexibility in its portfolio to be responsive to changes in policy, technology, and customer and consumer preferences. Chevron aims to grow its traditional oil and gas business, lower the carbon intensity of its operations and grow lower carbon businesses in renewable fuels, hydrogen, carbon capture, offsets, and other emerging technologies. To grow its lower carbon businesses, Chevron plans to target sectors of the economy where emissions are harder to abate or that cannot be easily electrified, while leveraging the company’s capabilities, assets and customer relationships. The company’s traditional oil and gas business may increase or decrease depending upon regulatory or market forces, among other factors.
In 2021, Chevron announced the following aspiration and targets that are aligned with its lower carbon strategy:
2050 Net Zero Upstream Aspiration Chevron aspires to achieve net zero for upstream production Scope 1 and 2 GHG emissions on an equity basis by 2050. The company believes accomplishing this aspiration depends on, among other things, partnerships with multiple stakeholders including customers, continuing progress on commercially viable technology, government policy, successful negotiations for carbon capture and storage and nature-based projects, availability and acceptability of cost-effective, verifiable offsets in the global market, and granting of necessary permits by governing authorities.
2028 Upstream Production GHG Intensity Targets These metrics include Scope 1, direct emissions, and Scope 2, indirect emissions from imported electricity and steam, and are net of emissions from exported electricity and steam. The targeted 2028 reductions from 2016 on an equity ownership basis include a:
•40 percent reduction in oil production GHG intensity to 24 kilograms (kg) carbon dioxide equivalent per barrel of oil-equivalent (CO2e/boe),
•26 percent reduction in gas production GHG intensity to 24 kg CO2e/boe,
Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents
•53 percent reduction in methane intensity to 2 kg CO2e/boe, and
•66 percent reduction in flaring GHG intensity to 3 kg CO2e/boe.
The company also targets no routine flaring by 2030. We have set 2016 as our baseline to align with the year the Paris Agreement entered into force, and the company plans to update the metrics every five years in line with the Paris Agreement stocktakes. We believe these updates will provide additional transparency on the company’s progress toward its net zero aspiration.
2028 Portfolio Carbon Intensity Target The company also introduced a portfolio carbon intensity (PCI) metric, which is a measure of the carbon intensity across the full value chain of Chevron’s entire business. This metric encompasses the company’s upstream and downstream business and includes Scope 1 (direct emissions), Scope 2 (indirect emissions from imported electricity and steam), and certain Scope 3 (primarily emissions from use of sold products) emissions. The company’s PCI target is 71 grams (g) carbon dioxide equivalent (CO2e) per megajoule (MJ) by 2028, a greater than five percent reduction from 2016.
Planned Lower-Carbon Capital Spend through 2028 In 2021, the company established planned capital spend of approximately $10 billion through 2028 to advance its lower carbon strategy, which includes approximately $2 billion to lower the carbon intensity of its traditional oil and gas operations, and approximately $8 billion for lower carbon investments in renewable fuels, hydrogen and carbon capture and offsets. We anticipate setting additional capital spending targets as the company progresses toward its 2050 upstream production Scope 1 and 2 net zero aspiration and further grows its lower carbon business lines.
During 2021 and 2022, the company spent $4.8 billion in lower carbon investments, including $2.9 billion associated with the acquisition of REG.
Refer to “Risk Factors” in Part I, Item 1A, on pages 20 through 26 for further discussion of GHG regulation and climate change and the associated risks to Chevron’s business, including the risks impacting Chevron’s lower carbon strategy and its aspirations, targets and plans.
Income Taxes The effective tax rate for the company can change substantially during periods of significant earnings volatility. This is due to the mix effects that are impacted by both the absolute level of earnings or losses and whether they arise in higher or lower tax rate jurisdictions. As a result, a decline or increase in the effective income tax rate in one period may not be indicative of expected results in future periods. Additional information related to the company’s effective income tax rate is included in Note 17 Taxes to the Consolidated Financial Statements.
The Inflation Reduction Act (IRA), enacted in the United States on August 16, 2022, imposes several new taxes that will be effective in 2023, including a 15 percent minimum tax on book income and a 1 percent excise tax on stock repurchases. The IRA also implements various incentives for lower carbon activities, including carbon capture and storage and the production of hydrogen and sustainable aviation fuel, and extends the federal biodiesel mixture excise tax credit through December 31, 2024. We do not currently expect the IRA to have a material impact on our results of operations.
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, exploration, 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.
Inflation continued to be a key factor impacting the economy over the last year. For key oil and gas industry inputs (e.g. rigs, well services, etc.), markets are likely to remain tight with any upward pressure tied directly to possible increases in activity. In contrast, inflationary pressures have started to reduce for non-oil and gas specific goods and services as a result of reduced supply chain disruptions and a slowdown in economic activity. Chevron’s 2023 capital expenditure budget assumes cost inflation that averages in the mid-single digits with certain areas higher, such as in the Permian Basin that assumes low double-digit cost inflation. Chevron believes it is well positioned to manage its costs for 2023, in large part due to indexed contracts and secured supplies for critical inputs.
Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents
Refer to the “Cautionary Statements Relevant to Forward-Looking Information” on page 2 and to “Risk Factors” in Part I, Item 1A, on pages 20 through 26 for a discussion of some of the inherent risks that could materially impact the company’s results of operations or financial condition.
Other Impacts The company continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value and to acquire assets or operations complementary to its asset base to help augment the company’s financial performance and value growth. Asset dispositions and restructurings may result in significant gains or losses in future periods.
The company closely monitors developments in the financial and credit markets, the level of worldwide economic activity, and the implications for the company of movements in prices for crude oil and natural gas. Management takes these developments into account in the conduct of daily operations and for business planning.
The COVID-19 pandemic caused a significant decrease in demand for our products and created disruptions and volatility in the global marketplace beginning late in first quarter 2020. Demand has largely recovered as of year-end 2022; however, there continues to be uncertainty around the extent to which the COVID-19 pandemic may impact our future results, which could be material.
Earnings trends for the company’s major business areas are described as follows:
Upstream Earnings for the upstream segment are closely aligned with industry prices for crude oil and natural gas. Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry production and inventory levels, technology advancements, production quotas or other actions imposed by OPEC+ countries, actions of regulators, weather-related damage and disruptions, competing fuel prices, natural and human causes beyond the company’s control such as the COVID-19 pandemic, 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 find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts, the pace of energy transition, and changes in tax, environmental and other applicable laws and regulations.
Chevron has interests in Venezuelan assets operated by independent affiliates. Chevron has been conducting limited activities in Venezuela consistent with the authorization provided pursuant to general licenses issued by the United States government. In fourth quarter 2022, Chevron received License 41 from the United States government, enabling the company to resume activity in Venezuela subject to certain limitations. The financial results for Chevron’s business in Venezuela are being recorded as non-equity investments since 2020, where income is only recognized when cash is received and production and reserves are not included in the company's results. Crude oil liftings in Venezuela commenced in first quarter 2023, which are expected to positively impact the company’s results going forward.
Caspian Pipeline Consortium (CPC), an equity affiliate, operates a 935-mile crude oil export pipeline from the Tengiz Field in Kazakhstan to tanker-loading facilities at Novorossiysk on the Russian coast of the Black Sea, providing the main export route for crude oil production from TCO, Karachaganak and other producing fields in Kazakhstan. The tanker loading facilities at Novorossiysk consist of three single point mooring facilities, with availability of two or more required to operate at full capacity. CPC is capable of operating at approximately 70 percent of capacity with one single point mooring facility in service. Two of the three offshore loading moorings at the CPC marine terminal were taken out of service during August 2022 for equipment repairs identified during normal maintenance. Repairs were completed in fourth quarter 2022. Production at TCO was not impacted by this CPC outage given turnaround activity at TCO and at other regional producers that ship through CPC. However, there is a risk that production from TCO could be curtailed in the future should availability of export facilities be constrained.
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 and could have an adverse effect on CPC operations and/or the company’s financial position. The financial impacts of such risks, including presently imposed sanctions, are not currently material for the company; however, it remains uncertain how long these conditions may last or how severe they may become.
Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents
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 $101 per barrel for the full-year 2022, compared to $71 in 2021. As of mid-February 2023, the Brent price was $85 per barrel. The WTI price averaged $95 per barrel for the full-year 2022, compared to $68 in 2021. As of mid-February 2023, the WTI price was $79 per barrel. The majority of the company’s equity crude production is priced based on the Brent benchmark.
Crude prices increased in 2022 driven by geopolitical risk, supply decisions by OPEC+ and continued demand recovery due to the further easing of COVID-19 restrictions. The company’s average realization for U.S. crude oil and natural gas liquids in 2022 was $77 per barrel, up 37 percent from 2021. The company’s average realization for international crude oil and natural gas liquids in 2022 was $91 per barrel, up 41 percent from 2021.
In contrast to price movements in the global market for crude oil, prices for natural gas are also impacted by regional supply and demand and infrastructure conditions in local markets. In the United States, prices at Henry Hub averaged $6.36 per thousand cubic feet (MCF) during 2022, compared with $3.85 per MCF during 2021. As of mid-February 2023, the Henry Hub spot price was $2.40 per MCF. (See page 43 for the company’s average natural gas realizations for the U.S.).
Outside the United States, prices for natural gas also depend on a wide range of supply, demand and regulatory circumstances. The company’s long-term contract prices for liquefied natural gas (LNG) are typically linked to crude oil prices. Most of the equity LNG offtake from the operated Australian LNG projects is committed under binding long-term contracts, with some sold in the Asian spot LNG market. International natural gas realizations averaged $9.75 per MCF during 2022, compared with $5.93 per MCF during 2021, mainly due to higher LNG prices.
Production The company’s worldwide net oil-equivalent production in 2022 was 3 million barrels per day. About 27 percent of the company’s net oil-equivalent production in 2022 occurred in OPEC+ member countries of Angola, Equatorial Guinea, Kazakhstan, Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait and Republic of Congo.
The company estimates its net oil-equivalent production in 2023, assuming a Brent crude oil price of $80 per barrel, to be flat to up 3 percent compared to 2022. 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; fluctuations in demand for crude oil and natural gas in various markets; weather conditions that may shut in production; civil unrest; changing geopolitics; delays in completion of maintenance turnarounds; storage constraints or economic conditions that could lead to shut-in production; or other disruptions to operations. The outlook for future production levels is also affected by the size and number of economic investment opportunities and the time lag between initial exploration and the beginning of production. The company has increased its investment emphasis on short-cycle projects.
Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents
Proved Reserves Net proved reserves for consolidated companies and affiliated companies totaled 11.2 billion barrels of oil-equivalent at year-end 2022, a slight decrease from year-end 2021. The reserve replacement ratio in 2022 was 97 percent. The 5 and 10 year reserve replacement ratios were 92 percent and 99 percent, respectively. Refer to Table V for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2020 and each year-end from 2020 through 2022, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2022.
Refer to the “Results of Operations” section on pages 39 and 40 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.
Refining margins were higher in 2022 because of recovering demand for refined products, low product inventories, lower industry refining capacity and lower product exports from Russia and China. Refining utilization was strong in 2022 to keep pace with demand growth. Although refining margins were elevated and still remain above historical levels, they fell considerably in late 2022. There are signs that higher refined product prices and concerns over macroeconomic conditions are slowing demand.
The company’s most significant marketing areas are the West Coast and Gulf Coast of the United States and Asia Pacific. Chevron operates or has significant ownership interests in refineries in each of these areas. Additionally, the company has a growing presence in renewable fuels after acquiring REG.
Refer to the “Results of Operations” section on page 40 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.
Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents
Noteworthy Developments
Key noteworthy developments and other events during 2022 and early 2023 included the following:
Angola Announced final investment decision for gas development projects at the Quiluma and Maboqueiro (Q&M) fields.
Argentina Received a concession for the development of unconventional hydrocarbon resources in the east area of the El Trapial field for a 35-year period.
Australia Received permits, as part of joint ventures, to assess carbon storage for three blocks totaling nearly 7.8 million acres in offshore Australia.
Canada Invested in Aurora Hydrogen, a company developing emission-free hydrogen production technology.
Egypt Made a significant gas discovery at the Nargis block offshore Egypt in the eastern Mediterranean Sea.
Finland Acquired Neste Oyj’s Group III base oil business, including its related sales and marketing business, and NEXBASETM brand.
Israel Approved a project to expand the company’s Tamar gas field in offshore Israel.
Namibia Entered Namibia by acquiring an 80 percent working interest in a deepwater oil and gas exploration lease.
Nigeria Extended Agbami and Usan leases to 2042.
Qatar Reached final investment decision with QatarEnergy on Ras Laffan Petrochemicals Complex through the company’s 50 percent owned affiliate, Chevron Phillips Chemical Company LLC (CPChem).
Republic of Congo Extended the Haute Mer production sharing contract to 2040.
United States Completed the sale of the company’s interest in the Eagle Ford Shale in Texas.
United States Approved the Ballymore project in the deepwater U.S. Gulf of Mexico. The field is planned to be produced through an existing facility with an allocated capacity of 75,000 barrels of crude oil per day.
United States Completed Project Canary pilot to independently certify operational and environment performance and earned highest certification rating for almost all participating Permian and DJ basins upstream assets, positioning the company to market responsibly sourced natural gas from the certified assets.
United States Acquired a 50 percent stake in an expanded joint venture to develop the Bayou Bend Carbon Capture and Sequestration (CCS) hub, with the goal of the hub becoming one of the first offshore CCS projects in the United States.
United States Formed a joint venture with Bunge North America, Inc. to develop renewable fuel feedstocks, leveraging Bunge’s expertise in oilseed processing and farmer relationships and Chevron’s expertise in fuels manufacturing and marketing.
United States Acquired REG, becoming the second largest producer of bio-based diesel in the United States.
United States Awarded 34 exploration leases in the Gulf of Mexico.
United States Announced investment in a new joint venture with California Bioenergy LLC to build infrastructure for the company’s dairy biomethane projects in California.
United States Commenced a project expected to increase light crude oil processing capacity to 125,000 barrels per day at the company’s Pasadena, Texas refinery.
United States Reached final investment decision on a major integrated polymer project (Golden Triangle Polymers) in the U.S. Gulf Coast at its 50 percent owned affiliate, CPChem.
United States Completed construction of a joint venture solar energy project to generate renewable energy for the company’s oil and gas operations in the Permian Basin.
United States Acquired full ownership of Beyond6, LLC and its nationwide network of 55 compressed natural gas stations to grow Chevron’s renewable natural gas value chain.
United States Announced joint venture with Baseload Capital to develop geothermal projects.
United States Announced collaboration with Raven SR Inc. and Hyzon Motors to produce hydrogen from green waste.
Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents
United States Announced agreements or investments in companies to access and possibly develop lower carbon technologies, including Iwatani Corporation (hydrogen fueling sites), Carbon Clean Solutions Limited (carbon capture), TAE Technologies (nuclear fusion) and Svante Technology Inc. (carbon capture).
Common Stock Dividends The 2022 annual dividend was $5.68 per share, making 2022 the 35th consecutive year that the company increased its annual per share dividend payout. In January 2023, the company’s Board of Directors increased its quarterly dividend by $0.09 per share, approximately six percent, to $1.51 per share payable in March 2023.
Common Stock Repurchase Program The company repurchased $11.25 billion of its common stock in 2022 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 2021 and 2020 can be found in the “Results of Operations” section on pages 39 through 40 of the company’s 2021 Annual Report on Form 10-K filed with the SEC on February 24, 2022.
U.S. Upstream
Millions of dollars 2022 2021 2020
Earnings (Loss) $ 12,621 $ 7,319 $ (1,608)
U.S. upstream reported earnings of $12.6 billion in 2022, compared with $7.3 billion in 2021. The increase was due to higher realizations of $6.6 billion and higher sales volumes of $380 million, partially offset by higher operating expenses of $1.1 billion largely due to an early contract termination at Sabine Pass and lower asset sale gains of $670 million.
The company’s average realization for U.S. crude oil and natural gas liquids in 2022 was $76.71 per barrel compared with $56.06 in 2021. The average natural gas realization was $5.55 per thousand cubic feet in 2022, compared with $3.11 in 2021.
Net oil-equivalent production in 2022 averaged 1.18 million barrels per day, up 4 percent from 2021. The increase was primarily due to net production increases in the Permian Basin.
The net liquids component of oil-equivalent production for 2022 averaged 888,000 barrels per day, up 3 percent from 2021. Net natural gas production averaged 1.76 billion cubic feet per day in 2022, an increase of 4 percent from 2021.
Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents
International Upstream
Millions of dollars 2022 2021 2020
Earnings (Loss)*
$ 17,663 $ 8,499 $ (825)
*Includes foreign currency effects:
$ 816 $ 302 $ (285)
International upstream reported earnings of $17.7 billion in 2022, compared with $8.5 billion in 2021. The increase was primarily due to higher realizations of $10.0 billion, lower operating expenses, lower depreciation, depletion and amortization related to end of concessions in Indonesia and Thailand of $1.3 billion and asset sale gains of $220 million. This was partially offset by lower sales volumes of $1.3 billion (also largely associated with the end of concessions in Indonesia and Thailand) and write-off and impairment charges of $1.1 billion. Foreign currency effects had a favorable impact on earnings of $514 million between periods.
The company’s average realization for international crude oil and natural gas liquids in 2022 was $90.71 per barrel compared with $64.53 in 2021. The average natural gas realization was $9.75 per thousand cubic feet in 2022 compared with $5.93 in 2021.
International net oil-equivalent production was 1.82 million barrels per day in 2022, down 7 percent from 2021. The decrease was primarily due to lower production following expiration of the Erawan concession in Thailand and Rokan concession in Indonesia.
The net liquids component of international oil-equivalent production was 831,000 barrels per day in 2022, a decrease of 13 percent from 2021. International net natural gas production of 5.92 billion cubic feet per day in 2022, a decrease of 2 percent from 2021.
U.S. Downstream
Millions of dollars 2022 2021 2020
Earnings (Loss) $ 5,394 $ 2,389 $ (571)
U.S. downstream reported earnings of $5.4 billion in 2022, compared with $2.4 billion in 2021. The increase was primarily due to higher margins on refined product sales of $4.4 billion, partially offset by lower earnings from the 50 percent-owned CPChem of $790 million and higher operating expenses of $790 million, largely due to planned turnarounds.
Total refined product sales of 1.23 million barrels per day in 2022 increased 8 percent from 2021, mainly due to higher renewable fuel sales following the REG acquisition and higher jet fuel demand.
International Downstream
Millions of dollars 2022 2021 2020
Earnings*
$ 2,761 $ 525 $ 618
*Includes foreign currency effects:
$ 235 $ 185 $ (152)
International downstream earned $2.8 billion in 2022, compared with $525 million in 2021. The increase in earnings was mainly due to higher margins on refined product sales of $2.7 billion and a favorable swing in foreign currency effects of $50 million between periods, partially offset by higher operating expenses of $650 million, largely due to transportation costs.
Total refined product sales of 1.39 million barrels per day in 2022 were up 5 percent from 2021, mainly due to higher jet fuel demand as travel restrictions associated with the COVID-19 pandemic continue to ease.
All Other
Millions of dollars 2022 2021 2020
Net charges*
$ (2,974) $ (3,107) $ (3,157)
*Includes foreign currency effects:
$ (382) $ (181) $ (208)
All Other consists of worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology companies.
Net charges in 2022 decreased $133 million from 2021. The change between periods was mainly due to lower pension settlement expense, loss on early debt retirement and lower interest expense, partially offset by the absence of 2021 favorable tax items and higher interest income. Foreign currency effects increased net charges by $201 million between periods.
Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents
Consolidated Statement of Income
Comparative amounts for certain income statement categories are shown below. A discussion of variances between 2021 and 2020 can be found in the “Consolidated Statement of Income” section on pages 39 and 40 of the company’s 2021 Annual Report on Form 10-K.
Millions of dollars 2022 2021 2020
Sales and other operating revenues $ 235,717 $ 155,606 $ 94,471
Sales and other operating revenues increased in 2022 mainly due to higher refined product, crude oil, and natural gas prices and higher refined product sales volumes.
Millions of dollars 2022 2021 2020
Income (loss) from equity affiliates $ 8,585 $ 5,657 $ (472)
Income from equity affiliates improved in 2022 mainly due to higher upstream-related earnings from Tengizchevroil in Kazakhstan and Angola LNG and higher downstream-related earnings from GS Caltex in Korea, partially offset by lower earnings from CPChem. Refer to Note 15 Investments and Advances for a discussion of Chevron’s investments in affiliated companies.
Millions of dollars 2022 2021 2020
Other income $ 1,950 $ 1,202 $ 693
Other income increased in 2022 mainly due to a favorable swing in foreign currency effects, higher interest income and lower charges associated with the early retirement of debt, partially offset by lower gains on asset sales.
Millions of dollars 2022 2021 2020
Purchased crude oil and products $ 145,416 $ 92,249 $ 52,148
Crude oil and product purchases increased in 2022 primarily due to higher crude oil, natural gas, and refined product prices.
Millions of dollars 2022 2021 2020
Operating, selling, general and administrative expenses $ 29,026 $ 24,740 $ 24,536
Operating, selling, general and administrative expenses increased in 2022 primarily due to higher transportation expenses, early contract termination charge at Sabine Pass and costs associated with planned refinery turnarounds.
Millions of dollars 2022 2021 2020
Exploration expense $ 974 $ 549 $ 1,537
Exploration expenses in 2022 increased primarily due to higher charges for well write-offs.
Millions of dollars 2022 2021 2020
Depreciation, depletion and amortization $ 16,319 $ 17,925 $ 19,508
Depreciation, depletion and amortization expenses decreased in 2022 primarily due to lower rates and lower production, partially offset by higher impairment and write-off charges.
Millions of dollars 2022 2021 2020
Taxes other than on income $ 4,032 $ 3,963 $ 2,839
Taxes other than on income increased in 2022 primarily due to higher taxes on production, partially offset by lower excise taxes.
Millions of dollars 2022 2021 2020
Interest and debt expense $ 516 $ 712 $ 697
Interest and debt expenses decreased in 2022 mainly due to lower debt balances.
Millions of dollars 2022 2021 2020
Other components of net periodic benefit costs $ 295 $ 688 $ 880
Other components of net periodic benefit costs decreased in 2022 primarily due to lower pension settlement costs, as fewer lump-sum pension distributions were made in the current year.
Millions of dollars 2022 2021 2020
Income tax expense (benefit) $ 14,066 $ 5,950 $ (1,892)
Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents
The increase in income tax expense in 2022 of $8.1 billion is due to the increase in total income before tax for the company of $28.0 billion. The increase in income before taxes for the company is primarily the result of higher upstream realizations and downstream margins.
U.S. income before tax increased from $9.7 billion in 2021 to $21.0 billion in 2022. This $11.3 billion increase in income was primarily driven by higher upstream realizations and downstream margins, partially offset by higher operating expenses and lower asset sale gains. The increase in income had a direct impact on the company’s U.S. income tax resulting in an increase to tax expense of $2.9 billion between year-over-year periods, from $1.6 billion in 2021 to $4.5 billion in 2022.
International income before tax increased from $12.0 billion in 2021 to $28.7 billion in 2022. This $16.7 billion increase in income was primarily driven by higher upstream realizations and downstream margins. The increased income primarily drove the $5.2 billion increase in international income tax expense between year-over-year periods, from $4.3 billion in 2021 to $9.6 billion in 2022.
Refer also to the discussion of the effective income tax rate in Note 17 Taxes.
Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents
Selected Operating Data1,2
2022 2021 2020
U.S. Upstream
Net Crude Oil and Natural Gas Liquids Production (MBPD) 888 858 789
Net Natural Gas Production (MMCFPD)3
1,758 1,689 1,607
Net Oil-Equivalent Production (MBOEPD) 1,181 1,139 1,058
Sales of Natural Gas (MMCFPD)4
4,354 3,986 3,873
Sales of Natural Gas Liquids (MBPD) 276 201 208
Revenues from Net Production
Liquids ($/Bbl) $ 76.71 $ 56.06 $ 30.53
Natural Gas ($/MCF) $ 5.55 $ 3.11 $ 0.98
International Upstream
Net Crude Oil and Natural Gas Liquids Production (MBPD)5
831 956 1,078
Net Natural Gas Production (MMCFPD)3
5,919 6,020 5,683
Net Oil-Equivalent Production (MBOEPD)4
1,818 1,960 2,025
Sales of Natural Gas (MMCFPD) 5,786 5,178 5,634
Sales of Natural Gas Liquids (MBPD) 107 84 46
Revenues from Liftings
Liquids ($/Bbl) $ 90.71 $ 64.53 $ 36.07
Natural Gas ($/MCF) $ 9.75 $ 5.93 $ 4.59
Worldwide Upstream
Net Oil-Equivalent Production (MBOEPD)5
United States 1,181 1,139 1,058
International 1,818 1,960 2,025
Total 2,999 3,099 3,083
U.S. Downstream
Gasoline Sales (MBPD)6
639 655 581
Other Refined Product Sales (MBPD) 589 484 422
Total Refined Product Sales (MBPD) 1,228 1,139 1,003
Sales of Natural Gas (MMCFPD)4
24 21 21
Sales of Natural Gas Liquids (MBPD) 27 29 25
Refinery Crude Oil Input (MBPD) 866 903 793
International Downstream
Gasoline Sales (MBPD)5
336 321 264
Other Refined Product Sales (MBPD) 1,050 994 957
Total Refined Product Sales (MBPD)7
1,386 1,315 1,221
Sales of Natural Gas (MMCFPD)4
3 - -
Sales of Natural Gas Liquids (MBPD) 127 96 74
Refinery Crude Oil Input (MBPD) 639 576 584
1 Includes company share of equity affiliates.
2 MBPD - thousands of barrels per day; MMCFPD - millions of cubic feet per day; MBOEPD - 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.
3 Includes natural gas consumed in operations (MMCFPD):
United States 53 44 37
International 517 548 566
4 Downstream sales of Natural Gas separately identified from Upstream.
5 Includes net production of synthetic oil:
Canada 45 55 54
6 Includes branded and unbranded gasoline.
7 Includes sales of affiliates (MBPD):
389 357 348
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 $17.9 billion and $5.7 billion at December 31, 2022 and 2021, respectively. Cash provided by operating activities in 2022 was $49.6 billion, compared to $29.2 billion in 2021, primarily due to higher upstream realizations and refining margins. Cash provided by operating activities was net of contributions to employee pension plans of approximately $1.3 billion in 2022 and $1.8 billion in 2021. Proceeds and deposits related to asset sales totaled $1.4 billion in each of the last two years. Returns of investment totaled $1.2 billion and $439 million in 2022 and 2021, respectively. The returns of investment in 2022 were primarily from Angola LNG. As of third quarter 2022, Angola LNG distributions were, and are expected to continue to be, largely reflected in cash flow from operations. Cash flow from financing activities includes proceeds from shares issued for stock options of $5.8 billion in 2022, compared with $1.4 billion in 2021. Future cash proceeds from option exercises are expected to be lower than in 2022.
Restricted cash of $1.4 billion and $1.2 billion at December 31, 2022 and 2021, respectively, was held in cash and short-term marketable securities and recorded as “Deferred charges and other assets” and “Prepaid expenses and other current assets” on the Consolidated Balance Sheet. These amounts are generally associated with upstream decommissioning activities, tax payments and funds held in escrow for tax-deferred exchanges.
Dividends Dividends paid to common stockholders were $11.0 billion in 2022 and $10.2 billion in 2021.
Debt and Finance Lease Liabilities Total debt and finance lease liabilities were $23.3 billion at December 31, 2022, down from $31.4 billion at year-end 2021.
The $8.1 billion decrease in total debt and finance lease liabilities during 2022 was primarily due to the repayment of long-term notes that matured during the year and the early retirement of long-term notes. The company’s debt and finance lease liabilities due within one year, consisting primarily of the current portion of long-term debt and redeemable long-term obligations, totaled $6.0 billion at December 31, 2022, compared with $8.0 billion at year-end 2021. Of these amounts, $4.1 billion and $7.8 billion were reclassified to long-term debt at the end of 2022 and 2021, respectively.
At year-end 2022, settlement of these obligations was not expected to require the use of working capital in 2023, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.
The company has access to a commercial paper program as a financing source for working capital or other short-term needs. The company had no commercial paper outstanding as of December 31, 2022.
The company has an automatic shelf registration statement that expires in August 2023 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
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), and Texaco Capital Inc. Most of these securities are the obligations of, or guaranteed by, Chevron Corporation and are rated AA- by Standard and Poor’s Corporation and Aa2 by Moody’s Investors Service. The company’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and P-1 by Moody’s. All of these ratings denote high-quality, investment-grade securities.
The company’s future debt level is dependent primarily on results of operations, cash that may be generated from asset dispositions, the capital program, lending commitments to affiliates and shareholder distributions. Based on its high-quality debt ratings, the company believes that it has substantial borrowing capacity to meet unanticipated cash requirements. During extended periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, the company has the ability to modify its capital spending plans and discontinue or curtail the stock repurchase program. This provides the flexibility to continue paying the common stock dividend and remain committed to retaining the company’s high-quality debt ratings.
Committed Credit Facilities Information related to committed credit facilities is included in Note 19 Short-Term Debt.
Summarized Financial Information for Guarantee of Securities of Subsidiaries CUSA issued bonds that are fully and unconditionally guaranteed on an unsecured basis by Chevron Corporation (together, the “Obligor Group”). The tables below contain summary financial information for Chevron Corporation, as Guarantor, excluding its consolidated subsidiaries, and CUSA, as the issuer, excluding its consolidated subsidiaries. The summary financial information of the Obligor Group is presented on a combined basis, and transactions between the combined entities have been eliminated. Financial information for non-guarantor entities has been excluded.
Year Ended December 31, 2022 Year Ended December 31, 2021
(Millions of dollars) (unaudited)
Sales and other operating revenues $ 126,911 $ 88,038
Sales and other operating revenues - related party 50,082 28,499
Total costs and other deductions 121,757 86,369
Total costs and other deductions - related party 43,042 28,277
Net income (loss) $ 15,043 $ 5,515
At December 31,
2022 At December 31,
(Millions of dollars) (unaudited)
Current assets $ 28,781 $ 15,567
Current assets - related party 12,326 12,227
Other assets 50,505 48,461
Current liabilities 22,663 22,554
Current liabilities - related party 118,277 79,778
Other liabilities 27,353 32,825
Total net equity (deficit) $ (76,681) $ (58,902)
Common Stock Repurchase Program The Board of Directors authorized a stock repurchase program in 2019, with a maximum dollar limit of $25 billion and no set term limits (the “2019 Program”). During 2022, the company purchased 69.9 million shares for $11.25 billion under the 2019 Program. As of December 31, 2022, the company had purchased a total of 131.4 million shares for $18.1 billion, resulting in $6.9 billion remaining under the 2019 Program. The company currently expects to repurchase $3.75 billion of its common stock during the first quarter of 2023 under the 2019 Program and will incur an additional one percent excise tax on such purchases as required by the IRA.
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 $75 billion authorization takes effect on April 1, 2023 and does not have a fixed expiration date (the “2023 Program”). It replaces the Board’s previous repurchase authorization of $25 billion from January 2019, which will terminate on March 31, 2023, after the completion of the company’s repurchases in the first quarter of 2023.
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
Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents
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 2022, 2021 and 2020 is as follows:
Year ended December 31
Capex 2022 2021 2020
Millions of dollars U.S. Int’l. Total U.S. Int’l. Total U.S. Int’l. Total
Upstream $ 6,847 $ 2,718 $ 9,565 $ 4,554 $ 2,221 $ 6,775 $ 4,933 $ 2,555 $ 7,488
Downstream 1,699 375 2,074 806 234 1,040 644 551 1,195
All Other 310 25 335 221 20 241 226 13 239
Capex $ 8,856 $ 3,118 $ 11,974 $ 5,581 $ 2,475 $ 8,056 $ 5,803 $ 3,119 $ 8,922
Capex for 2022 was $12.0 billion, 49 percent higher than 2021 due to increased upstream spend in the Permian Basin along with higher spend in downstream, largely related to the formation of the Bunge North America, Inc. (Bunge) joint venture and acquisition of the remaining interest in Beyond6, LLC (Beyond6).
The company estimates that 2023 Capex will be approximately $14 billion. In the upstream business, Capex is estimated to be $11.5 billion and includes more than $4 billion for Permian Basin development and roughly $2 billion for other shale & tight assets. More than 20 percent of upstream Capex is planned for projects in the Gulf of Mexico. Worldwide downstream spending in 2023 is estimated to be $1.9 billion. Investments in technology businesses and other corporate operations in 2023 are budgeted at $0.6 billion. Lower carbon Capex across all segments totals around $2 billion, including approximately $0.5 billion to lower the carbon intensity of Chevron’s traditional operations and about $1 billion to increase renewable fuels production capacity.
Affiliate capital expenditures (Affiliate Capex), which does not require cash outlays by the company, is expected to be $3 billion in 2023. Nearly half of Affiliate Capex is for Tengizchevroil’s FGP / WPMP Project in Kazakhstan and about a third is for CPChem.
Capital and Exploratory Expenditures Capital and exploratory expenditures (C&E) is a key performance indicator and provides the company’s investment level in its consolidated companies. This metric includes additions to fixed asset or investment accounts along with exploration expense for its consolidated companies. Management uses this metric along with Affiliate C&E (as defined below) to manage the allocation of capital across the company’s entire portfolio, funding requirements and ultimately shareholder distributions.
The components of C&E are presented in the following table:
Year ended December 31
Millions of dollars 2022 2021 2020
Capital expenditures $ 11,974 $ 8,056 $ 8,922
Expensed exploration expenditures 488 431 500
Assets acquired through finance leases and other obligations 3 64 53
Payments for other assets and liabilities, net (169) 2 42
Capital and exploratory expenditures (C&E) $ 12,296 $ 8,553 $ 9,517
Affiliate capital and exploratory expenditures (Affiliate C&E) $ 3,366 $ 3,167 $ 3,982
C&E by business segment for 2022, 2021 and 2020 is as follows:
Year ended December 31
C&E 2022 2021 2020
Millions of dollars U.S. Int’l. Total U.S. Int’l. Total U.S. Int’l. Total
Upstream $ 6,980 $ 3,073 $ 10,053 $ 4,696 $ 2,512 $ 7,208 $ 5,130 $ 2,867 $ 7,997
Downstream 1,702 206 1,908 870 234 1,104 697 584 1,281
All Other 310 25 335 221 20 241 226 13 239
C&E $ 8,992 $ 3,304 $ 12,296 $ 5,787 $ 2,766 $ 8,553 $ 6,053 $ 3,464 $ 9,517
Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents
C&E for 2022 was $12.3 billion, 44 percent higher than 2021 due to increased upstream spend in the Permian Basin along with higher spend in downstream, largely related to the formation of the Bunge joint venture and acquisition of the remaining interest in Beyond6. The acquisitions of Renewable Energy Group Inc. and Noble are not included in the company’s C&E or Capex.
Affiliate Capital and Exploratory Expenditures Equity affiliate capital and exploratory expenditures (Affiliate C&E) is also a key performance indicator that provides the company’s share of investments in its significant equity affiliate companies. This metric includes additions to fixed asset and investment accounts along with exploration expense in the equity affiliate companies’ financial statements. Management uses this metric to assess possible funding needs and/or shareholder distribution capacity of the company’s equity affiliate companies. Together with C&E, management also uses Affiliate C&E to manage allocation of capital across the company’s entire portfolio, funding requirements and ultimately shareholder distributions.
Affiliate C&E, which is the same as Affiliate Capex spend, by business segment for 2022, 2021 and 2020 is as follows:
Year ended December 31
Affiliate C&E 2022 2021 2020
Millions of dollars U.S. Int’l. Total U.S. Int’l. Total U.S. Int’l. Total
Upstream $ - $ 2,406 $ 2,406 $ 2 $ 2,404 $ 2,406 $ - $ 2,917 $ 2,917
Downstream 768 192 960 365 396 761 324 741 1,065
All Other - - - - - - - - -
Affiliate C&E $ 768 $ 2,598 $ 3,366 $ 367 $ 2,800 $ 3,167 $ 324 $ 3,658 $ 3,982
Affiliate C&E for 2022 was $3.4 billion, 6 percent higher than 2021.
The company monitors market conditions and can adjust future capital outlays should conditions change.
Noncontrolling Interests The company had noncontrolling interests of $960 million at December 31, 2022 and $873 million at December 31, 2021. Distributions to noncontrolling interests net of contributions totaled $114 million and $36 million in 2022 and 2021, respectively. Included within noncontrolling interests at December 31, 2022 is $142 million of redeemable noncontrolling interest.
Pension Obligations Information related to pension plan contributions is included in Note 23 Employee Benefit Plans, under the heading “Cash Contributions and Benefit Payments.”
Contractual Obligations Information related to the company’s significant contractual obligations is included in Note 19 Short-Term Debt, in Note 20 Long-Term Debt and in Note 5 Lease Commitments. The aggregate amount of interest due on these obligations, excluding leases, is: 2023 - $595; 2024 - $536; 2025 - $476; 2026 - $395; 2027 - $340; after 2027 - $3,373.
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 was adversely affected by the fact that Chevron’s inventories are valued on a last-in, first-out basis. At year-end 2022, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $9.1 billion.
At December 31
Millions of dollars 2022 2021 2020
Current assets $ 50,343 $ 33,738 $ 26,078
Current liabilities 34,208 26,791 22,183
Current Ratio 1.5 1.3 1.2
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. The company’s interest coverage ratio in 2022 was higher than 2021 due to higher income.
Year ended December 31
Millions of dollars 2022 2021 2020
Income (Loss) Before Income Tax Expense $ 49,674 $ 21,639 $ (7,453)
Plus: Interest and debt expense 516 712 697
Plus: Before-tax amortization of capitalized interest 199 215 205
Less: Net income attributable to noncontrolling interests 143 64 (18)
Subtotal for calculation 50,246 22,502 (6,533)
Total financing interest and debt costs $ 630 $ 775 $ 735
Interest Coverage Ratio 79.8 29.0 (8.9)
Free Cash Flow The cash provided by operating activities less capital expenditures, which represents the cash available to creditors and investors after investing in the business.
Year ended December 31
Millions of dollars 2022 2021 2020
Net cash provided by operating activities $ 49,602 $ 29,187 $ 10,577
Less: Capital expenditures 11,974 8,056 8,922
Free Cash Flow $ 37,628 $ 21,131 $ 1,655
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 2022 2021 2020
Short-term debt $ 1,964 $ 256 $ 1,548
Long-term debt 21,375 31,113 42,767
Total debt 23,339 31,369 44,315
Total Chevron Corporation Stockholders’ Equity 159,282 139,067 131,688
Total debt plus total Chevron Corporation Stockholders’ Equity $ 182,621 $ 170,436 $ 176,003
Debt Ratio 12.8 % 18.4 % 25.2 %
Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Table of Contents
Net Debt Ratio Total debt less cash and cash equivalents and marketable securities as a percentage of total debt less cash and cash equivalents and marketable securities, plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage, net of its cash balances.
At December 31
Millions of dollars 2022 2021 2020
Short-term debt $ 1,964 $ 256 $ 1,548
Long-term debt 21,375 31,113 42,767
Total Debt
23,339 31,369 44,315
Less: Cash and cash equivalents 17,678 5,640 5,596
Less: Marketable securities 223 35 31
Total adjusted debt 5,438 25,694 38,688
Total Chevron Corporation Stockholders’ Equity
159,282 139,067 131,688
Total adjusted debt plus total Chevron Corporation Stockholders’ Equity $ 164,720 $ 164,761 $ 170,376
Net Debt Ratio 3.3 % 15.6 % 22.7 %
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 2022 2021 2020
Chevron Corporation Stockholders’ Equity $ 159,282 $ 139,067 $ 131,688
Plus: Short-term debt 1,964 256 1,548
Plus: Long-term debt 21,375 31,113 42,767
Plus: Noncontrolling interest 960 873 1,038
Capital Employed at December 31 $ 183,581 $ 171,309 $ 177,041
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 2022 2021 2020
Net income attributable to Chevron $ 35,465 $ 15,625 $ (5,543)
Plus: After-tax interest and debt expense 476 662 658
Plus: Noncontrolling interest 143 64 (18)
Net income after adjustments 36,084 16,351 (4,903)
Average capital employed $ 177,445 $ 174,175 $ 174,611
Return on Average Capital Employed 20.3 % 9.4 % (2.8) %
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 2022 2021 2020
Net income attributable to Chevron $ 35,465 $ 15,625 $ (5,543)
Chevron Corporation Stockholders’ Equity at December 31 159,282 139,067 131,688
Average Chevron Corporation Stockholders’ Equity 149,175 135,378 137,951
Return on Average Stockholders’ Equity 23.8 % 11.5 % (4.0) %
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 “Risk Factors” in Part I, Item 1A.
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Derivative Commodity Instruments Chevron is exposed to market risks related to the price volatility of crude oil, refined products, natural gas liquids, natural gas, liquefied natural gas and refinery feedstocks. The company uses derivative commodity instruments to manage these exposures on a portion of its activity, including firm commitments and anticipated transactions for the purchase, sale and storage of crude oil, refined products, natural gas liquids, natural gas, liquefied natural gas and feedstock for company refineries. The company also uses derivative commodity instruments for limited trading purposes. The results of these activities were not material to the company’s financial position, results of operations or cash flows in 2022.
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 2022 was not material to the company’s results of operations.
The company uses the Monte Carlo simulation method as its Value-at-Risk (VaR) model to estimate the maximum potential loss in fair value, at the 95 percent confidence level with a one-day holding period, from the effect of adverse changes in market conditions on derivative commodity instruments held or issued. Based on these inputs, the VaR for the company’s primary risk exposures in the area of derivative commodity instruments at December 31, 2022 and 2021 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 material open foreign currency derivative contracts at December 31, 2022.
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 2022, the company had no interest rate swaps.
Transactions With Related Parties
Chevron enters into a number of business arrangements with related parties, principally its equity affiliates. These arrangements include long-term supply or offtake agreements and long-term purchase agreements. Refer to “Other Information” in Note 15 Investments and Advances for further discussion. Management believes these agreements have been negotiated on terms consistent with those that would have been negotiated with an unrelated party.
Litigation and Other Contingencies
Ecuador Information related to Ecuador matters is included in Note 16 Litigation under the heading “Ecuador.”
Climate Change Information related to climate change-related matters is included in Note 16 Litigation under the heading “Climate Change.”
Louisiana Information related to Louisiana coastal matters is included in Note 16 Litigation under the heading “Louisiana.”
Environmental The following table displays the annual changes to the company’s before-tax environmental remediation reserves, including those for U.S. federal Superfund sites and analogous sites under state laws.
Millions of dollars 2022 2021 2020
Balance at January 1 $ 960 $ 1,139 $ 1,234
Net additions 182 114 179
Expenditures (274) (293) (274)
Balance at December 31 $ 868 $ 960 $ 1,139
The company records asset retirement obligations when there is a legal obligation associated with the retirement of long-lived assets and the liability can be reasonably estimated. These asset retirement obligations include costs related to
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environmental issues. The liability balance of approximately $12.7 billion for asset retirement obligations at year-end 2022 is related primarily to upstream properties.
For the company’s other ongoing operating assets, such as refineries and chemicals facilities, no provisions are made for exit or cleanup costs that may be required when such assets reach the end of their useful lives unless a decision to sell or otherwise decommission the facility has been made, as the indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the asset retirement obligation.
Refer to the discussion below for additional information on environmental matters and their impact on Chevron, and on the company’s 2022 environmental expenditures. Refer to Note 24 Other Contingencies and Commitments under the heading “Environmental” for additional discussion of environmental remediation provisions and year-end reserves. Refer also to Note 25 Asset Retirement Obligations for additional discussion of the company’s asset retirement obligations.
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 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 “Risk Factors” in Part I, Item 1A, on pages 20 through 26 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 32 and 33 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 2022 at approximately $2.0 billion for its consolidated companies. Included in these expenditures were approximately $0.2 billion of environmental capital expenditures and $1.8 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.
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For 2023, total worldwide environmental capital expenditures are estimated at $0.2 billion. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites.
Critical Accounting Estimates and Assumptions
Management makes many estimates and assumptions in the application of accounting principles generally accepted in the United States of America (GAAP) that may have a material impact on the company’s consolidated financial statements and related disclosures and on the comparability of such information over different reporting periods. Such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on management’s experience and other information available prior to the issuance of the financial statements. Materially different results can occur as circumstances change and additional information becomes known.
The discussion in this section of “critical” accounting estimates and assumptions is according to the disclosure guidelines of the SEC, wherein:
1.the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters, or the susceptibility of such matters to change; and
2.the impact of the estimates and assumptions on the company’s financial condition or operating performance is material.
The development and selection of accounting estimates and assumptions, including those deemed “critical,” and the associated disclosures in this discussion have been discussed with the Audit Committee of the Board of Directors. The areas of accounting and the associated “critical” estimates and assumptions made by the company are as follows:
Oil and Gas Reserves Crude oil, natural gas liquids and natural gas reserves are estimates of future production that impact certain asset and expense accounts included in the Consolidated Financial Statements. Proved reserves are the estimated quantities of oil and gas that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in the future under existing economic conditions, operating methods and government regulations. Proved reserves include both developed and undeveloped volumes. Proved developed reserves represent volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for recompletion. Variables impacting Chevron’s estimated volumes of crude oil and natural gas reserves include field performance, available technology, commodity prices, and development, production and carbon costs.
The estimates of crude oil, natural gas liquids 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.Amortization - 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 2022, Chevron’s UOP Depreciation, Depletion and Amortization (DD&A) for oil and gas properties was $10.8 billion, and proved developed reserves at the beginning of 2022 were 6.6 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 2022 would have increased by approximately $600 million.
2.Impairment - Oil and gas reserves are used in assessing oil and gas producing properties for impairment. A significant reduction in the estimated reserves of a property would trigger an impairment review. Proved reserves (and, in some cases, a portion of unproved resources) are used to estimate future production volumes in the cash flow model. For a further discussion of estimates and assumptions used in impairment assessments, see Impairment of Properties, Plant and Equipment and Investments in Affiliates below.
Refer to Table V, “Reserve Quantity Information,” for the changes in proved reserve estimates for each of the three years ended December 31, 2020, 2021 and 2022, 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, 2020, 2021 and 2022.
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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, natural gas liquids, natural gas, commodity chemicals and refined products. However, the impairment reviews and calculations are based on assumptions that are generally consistent with the company’s business plans and long-term investment decisions. Refer also to the discussion of impairments of properties, plant and equipment in Note 18 Properties, Plant and Equipment and to the section on Properties, Plant and Equipment in Note 1 Summary of Significant Accounting Policies.
The company performs impairment assessments when triggering events arise to determine whether any write-down in the carrying value of an asset or asset group is required. For example, when significant downward revisions to crude oil, natural gas liquids 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, natural gas liquids or natural gas price outlook would trigger impairment reviews for impacted upstream assets. In addition, impairments could occur due to changes in national, state or local environmental regulations or laws, including those designed to stop or impede the development or production of oil and gas. Also, if the expectation of sale of a particular asset or asset group in any period has been deemed more likely than not, an impairment review is performed, and if the estimated net proceeds exceed the carrying value of the asset or asset group, no impairment charge is required. Such calculations are reviewed each period until the asset or asset group is disposed. Assets that are not impaired on a held-and-used basis could possibly become impaired if a decision is made to sell such assets. That is, the assets would be impaired if they are classified as held-for-sale and the estimated proceeds from the sale, less costs to sell, are less than the assets’ associated carrying values.
Investments in common stock of affiliates that are accounted for under the equity method, as well as investments in other securities of these equity investees, are reviewed for impairment when the fair value of the investment falls below the company’s carrying value. When this occurs, a determination must be made as to whether this loss is other-than-temporary, in which case the investment is impaired. Because of the number of differing assumptions potentially affecting whether an investment is impaired in any period or the amount of the impairment, a sensitivity analysis is not practicable.
A sensitivity analysis of the impact on earnings for these periods if other assumptions had been used in impairment reviews and impairment calculations is not practicable, given the broad range of the company’s PP&E and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired, or resulted in larger impacts on impaired assets.
Asset Retirement Obligations In the determination of fair value for an asset retirement obligation (ARO), the company uses various assumptions and judgments, including such factors as the existence of a legal obligation, estimated amounts and timing of settlements, discount and inflation rates, and the expected impact of advances in technology and process improvements. A sensitivity analysis of the ARO impact on earnings for 2022 is not practicable, given the broad range of the company’s long-lived assets and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions would have reduced estimated future obligations, thereby lowering accretion expense and amortization costs, whereas unfavorable changes would have the opposite effect. Refer to Note 25 Asset Retirement Obligations for additional discussions on asset retirement obligations.
Pension and Other Postretirement Benefit Plans Note 23 Employee Benefit Plans includes information on the funded status of the company’s pension and other postretirement benefit (OPEB) plans reflected on the Consolidated Balance Sheet; the components of pension and OPEB expense reflected on the Consolidated Statement of Income; and the related underlying assumptions.
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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 2022, the company used an expected long-term rate of return of 6.6 percent and a discount rate for service costs of 3.5 percent and a discount rate for interest cost of 2.7 percent for the primary U.S. pension plan. The actual return for 2022 was (17.8) percent. For the 10 years ended December 31, 2022, actual asset returns averaged 5.7 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 6.6 percent during each year.
Total pension expense for 2022 was $763 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 1 percent increase in this assumption for the company’s primary U.S. pension plan, which accounted for about 55 percent of companywide pension expense, would have reduced total pension plan expense for 2022 by approximately $75 million. A 1 percent increase in the discount rates for this same plan would have reduced pension expense for 2022 by approximately $177 million.
The aggregate funded status recognized at December 31, 2022, was a net liability of approximately $1.8 billion. An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan. At December 31, 2022, the company used a discount rate of 5.2 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 63 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $239 million, and would have decreased the plan’s underfunded status from approximately $475 million to $236 million.
For the company’s OPEB plans, expense for 2022 was $89 million, and the total liability, all unfunded at the end of 2022, was $1.9 billion. For the primary U.S. OPEB plan, the company used a discount rate for service cost of 3.1 percent and a discount rate for interest cost of 2.1 percent to measure expense in 2022, and a 5.2 percent discount rate to measure the benefit obligations at December 31, 2022. Discount rate changes, similar to those used in the pension sensitivity analysis, resulted in an immaterial impact on 2022 OPEB expense and OPEB liabilities at the end of 2022.
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 90 in Note 23 Employee Benefit Plans for more information on the $3.4 billion of before-tax actuarial losses recorded by the company as of December 31, 2022. In addition, information related to company contributions is included on page 93 in Note 23 Employee Benefit Plans under the heading “Cash Contributions and Benefit Payments.”
Contingent Losses Management also makes judgments and estimates in recording liabilities for claims, litigation, tax matters and environmental remediation. Actual costs can frequently vary from estimates for a variety of reasons. For example, the costs for settlement of claims and litigation can vary from estimates based on differing interpretations of laws, opinions on culpability and assessments on the amount of damages. Similarly, liabilities for environmental remediation are subject to change because of changes in laws, regulations and their interpretation, the determination of additional information on the extent and nature of site contamination, and improvements in technology.
Under the accounting rules, a liability is generally recorded for these types of contingencies if management determines the loss to be both probable and estimable. The company generally reports these losses as “Operating expenses” or “Selling, general and administrative expenses” 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, 2022.
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
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assumptions and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss. For further information, refer to “Changes in management’s estimates and assumptions may have a material impact on the company’s consolidated financial statements and financial or operational performance in any given period” in “Risk Factors” in Part I, Item 1A, on pages 25 and 26.
New Accounting Standards
Refer to Note 4 New Accounting Standards for information regarding new accounting standards.
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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 2022 presentation basis.
Subsidiary and Affiliated Companies The Consolidated Financial Statements include the accounts of controlled subsidiary companies more than 50 percent-owned and any variable interest entities in which the company is the primary beneficiary. Undivided interests in oil and gas joint ventures and certain other assets are consolidated on a proportionate basis. Investments in and advances to affiliates in which the company has a substantial ownership interest of approximately 20 percent to 50 percent, or for which the company exercises significant influence but not control over policy decisions, are accounted for by the equity method.
Investments in affiliates are assessed for possible impairment when events indicate that the fair value of the investment may be below the company’s carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in net income. In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee’s financial performance, and the company’s ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. The new cost basis of investments in these equity investees is not changed for subsequent recoveries in fair value.
Differences between the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned to the extent practicable to specific assets and liabilities based on the company’s analysis of the various factors giving rise to the difference. When appropriate, the company’s share of the affiliate’s reported earnings is adjusted quarterly to reflect the difference between these allocated values and the affiliate’s historical book values.
Noncontrolling Interests Ownership interests in the company’s subsidiaries held by parties other than the parent are presented separately from the parent’s equity on the Consolidated Balance Sheet. The amount of consolidated net income attributable to the parent and the noncontrolling interests are both presented on the face of the Consolidated Statement of Income and Consolidated Statement of Equity. Included within noncontrolling interest is redeemable noncontrolling interest.
Fair Value Measurements The three levels of the fair value hierarchy of inputs the company uses to measure the fair value of an asset or a liability are as follows. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Level 3 inputs are inputs that are not observable in the market.
Derivatives The majority of the company’s activity in derivative commodity instruments is intended to manage the financial risk posed by physical transactions. For some of this derivative activity, the company may elect to apply fair value or cash flow hedge accounting with changes in fair value recorded as components of accumulated other comprehensive income (loss). For other similar derivative instruments, generally because of the short-term nature of the contracts or their limited use, the company does not apply hedge accounting, and changes in the fair value of those contracts are reflected in current income. For the company’s commodity trading activity, gains and losses from derivative instruments are reported in current income. The company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Interest rate swaps related to a portion of the company’s fixed-rate debt, if any, may be accounted for as fair value hedges. Interest rate swaps related to floating-rate debt, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. Where Chevron is a party to master netting arrangements, fair value receivable and payable amounts recognized for derivative instruments executed with the same counterparty are generally offset on the balance sheet.
Inventories Crude oil, products and chemicals inventories are generally stated at cost, using a last-in, first-out method. In the aggregate, these costs are below market. “Materials, supplies and other” inventories are primarily stated at cost or net realizable value.
Notes to the Consolidated Financial Statements
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Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. All other exploratory wells and costs are expensed. Refer to Note 21 Accounting for Suspended Exploratory Wells for additional discussion of accounting for suspended exploratory well costs.
Long-lived assets to be held and used, including proved crude oil and natural gas properties, are assessed for possible impairment by comparing their carrying values with their associated undiscounted, future net cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset (including changes to the commodity price forecast or carbon costs), significant change in the extent or manner of use of or a physical change in an asset, and a more likely than not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted, future net cash flows. For proved crude oil and natural gas properties, the company performs impairment reviews on a country, concession, PSC, development area or field basis, as appropriate. In downstream, impairment reviews are performed on the basis of a refinery, a plant, a marketing/lubricants area or distribution area, as appropriate. Impairment amounts are recorded as incremental “Depreciation, depletion and amortization” expense.
Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value. Refer to Note 9 Fair Value Measurements relating to fair value measurements. The fair value of a liability for an ARO is recorded as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. Refer also to Note 25 Asset Retirement Obligations relating to AROs.
Depreciation and depletion of all capitalized costs of proved crude oil and natural gas producing properties, except mineral interests, are expensed using the unit-of-production method, generally by individual field, as the proved developed reserves are produced. Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of-production method by individual field as the related proved reserves are produced. Impairments of capitalized costs of unproved mineral interests are expensed.
The capitalized costs of all other plant and equipment are depreciated or amortized over their estimated useful lives. In general, the declining-balance method is used to depreciate plant and equipment in the United States; the straight-line method is generally used to depreciate international plant and equipment and to amortize finance lease right-of-use assets.
Gains or losses are not recognized for normal retirements of properties, plant and equipment subject to composite group amortization or depreciation. Gains or losses from abnormal retirements are recorded as expenses, and from sales as “Other income.”
Expenditures for maintenance (including those for planned major maintenance projects), repairs and minor renewals to maintain facilities in operating condition are generally expensed as incurred. Major replacements and renewals are capitalized.
Leases Leases are classified as operating or finance leases. Both operating and finance leases recognize lease liabilities and associated right-of-use assets. The company has elected the short-term lease exception and therefore only recognizes right-of-use assets and lease liabilities for leases with a term greater than one year. The company has elected the practical expedient to not separate non-lease components from lease components for most asset classes except for certain asset classes that have significant non-lease (i.e., service) components.
Where leases are used in joint ventures, the company recognizes 100 percent of the right-of-use assets and lease liabilities when the company is the sole signatory for the lease (in most cases, where the company is the operator of a joint venture). Lease costs reflect only the costs associated with the operator’s working interest share. The lease term includes the committed lease term identified in the contract, taking into account renewal and termination options that management is
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reasonably certain to exercise. The company uses its incremental borrowing rate as a proxy for the discount rate based on the term of the lease unless the implicit rate is available.
Goodwill Goodwill resulting from a business combination is not subject to amortization. The company tests such goodwill at the reporting unit level for impairment annually at December 31, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount.
Environmental Expenditures Environmental expenditures that relate to ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized.
Liabilities related to future remediation costs are recorded when environmental assessments or cleanups or both are probable and the costs can be reasonably estimated. For crude oil, natural gas and mineral-producing properties, a liability for an ARO is made in accordance with accounting standards for asset retirement and environmental obligations. Refer to Note 25 Asset Retirement Obligations for a discussion of the company’s AROs.
For U.S. federal Superfund sites and analogous sites under state laws, the company records a liability for its designated share of the probable and estimable costs, and probable amounts for other potentially responsible parties when mandated by the regulatory agencies because the other parties are not able to pay their respective shares. The gross amount of environmental liabilities is based on the company’s best estimate of future costs using currently available technology and applying current regulations and the company’s own internal environmental policies. Future amounts are not discounted. Recoveries or reimbursements are recorded as assets when receipt is reasonably assured.
Currency Translation The U.S. dollar is the functional currency for substantially all of the company’s consolidated operations and those of its equity affiliates. For those operations, all gains and losses from currency remeasurement are included in current period income. The cumulative translation effects for those few entities, both consolidated and affiliated, using functional currencies other than the U.S. dollar are included in “Currency translation adjustment” on the Consolidated Statement of Equity.
Revenue Recognition The company accounts for each delivery order of crude oil, natural gas, petroleum and chemical products as a separate performance obligation. Revenue is recognized when the performance obligation is satisfied, which typically occurs at the point in time when control of the product transfers to the customer. Payment is generally due within 30 days of delivery. The company accounts for delivery transportation as a fulfillment cost, not a separate performance obligation, and recognizes these costs as an operating expense in the period when revenue for the related commodity is recognized.
Revenue is measured as the amount the company expects to receive in exchange for transferring commodities to the customer. The company’s commodity sales are typically based on prevailing market-based prices and may include discounts and allowances. Until market prices become known under terms of the company’s contracts, the transaction price included in revenue is based on the company’s estimate of the most likely outcome.
Discounts and allowances are estimated using a combination of historical and recent data trends. When deliveries contain multiple products, an observable standalone selling price is generally used to measure revenue for each product. The company includes estimates in the transaction price only to the extent that a significant reversal of revenue is not probable in subsequent periods.
Stock Options and Other Share-Based Compensation The company issues stock options and other share-based compensation to certain employees. For equity awards, such as stock options, total compensation cost is based on the grant date fair value, and for liability awards, such as stock appreciation rights, total compensation cost is based on the settlement value. The company recognizes stock-based compensation expense for all awards over the service period required to earn the award, which is the shorter of the vesting period or the time period in which an employee becomes eligible to retain the award at retirement. The company’s Long-Term Incentive Plan (LTIP) awards include stock options and stock appreciation rights, which have graded vesting provisions by which one-third of each award vests on each of the first, second and third anniversaries of the date of grant. In addition, performance shares granted under the company’s LTIP will vest at the end of the three-year performance period. For awards granted under the company’s LTIP beginning in 2017, stock options and stock appreciation rights have graded vesting by which one third of each award vests annually on each January 31 on or after the first anniversary of the grant date. Special restricted stock unit awards have cliff vesting by which the total award will vest on January 31 on or after the third anniversary of the grant date. Standard restricted stock unit awards have cliff vesting by which the total award will vest on January 31 on or after the fifth anniversary of the grant date, subject to adjustment upon termination pursuant to the satisfaction of certain criteria. Commencing for grants issued in January 2023
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
and after, standard restricted stock units vest ratably on an annual basis over a three-year period. The company amortizes these awards on a straight-line basis.
Note 2
Changes in Accumulated Other Comprehensive Losses
The change in Accumulated Other Comprehensive Losses (AOCL) presented on the Consolidated Balance Sheet and the impact of significant amounts reclassified from AOCL on information presented in the Consolidated Statement of Income for the year ended December 31, 2022, are reflected in the table below.
Currency Translation Adjustments Unrealized Holding Gains (Losses) on Securities Derivatives Defined Benefit Plans Total
Balance at December 31, 2019 $ (142) $ (8) $ - $ (4,840) $ (4,990)
Components of Other Comprehensive Income (Loss)1:
Before Reclassifications
35 (2) - (1,487) (1,454)
Reclassifications2
- - - 832 832
Net Other Comprehensive Income (Loss)
35 (2) - (655) (622)
Balance at December 31, 2020 $ (107) $ (10) $ - $ (5,495) $ (5,612)
Components of Other Comprehensive Income (Loss)1:
Before Reclassifications
(55) (1) (6) 949 887
Reclassifications2, 3
- - 6 830 836
Net Other Comprehensive Income (Loss)
(55) (1) - 1,779 1,723
Balance at December 31, 2021 $ (162) $ (11) $ - $ (3,716) $ (3,889)
Components of Other Comprehensive Income (Loss)1:
Before Reclassifications
(41) (1) 68 703 729
Reclassifications2, 3
- - (80) 442 362
Net Other Comprehensive Income (Loss) (41) (1) (12) 1,145 1,091
Balance at December 31, 2022 $ (203) $ (12) $ (12) $ (2,571) $ (2,798)
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 $580 that are included in employee benefit costs for the year ended December 31, 2022. Related income taxes for the same period, totaling $138, 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
Financial Table of Contents
Millions of dollars, except per-share amounts
Note 3
Information Relating to the Consolidated Statement of Cash Flows
Year ended December 31
2022 2021 2020
Distributions more (less) than income from equity affiliates includes the following:
Distributions from equity affiliates $ 3,855 $ 3,659 $ 1,543
(Income) loss from equity affiliates (8,585) (5,657) 472
Distributions more (less) than income from equity affiliates $ (4,730) $ (1,998) $ 2,015
Net decrease (increase) in operating working capital was composed of the following:
Decrease (increase) in accounts and notes receivable $ (2,317) $ (7,548) $ 2,423
Decrease (increase) in inventories (930) (530) 284
Decrease (increase) in prepaid expenses and other current assets (226) 19 (87)
Increase (decrease) in accounts payable and accrued liabilities 2,750 5,475 (3,576)
Increase (decrease) in income and other taxes payable 2,848 1,223 (696)
Net decrease (increase) in operating working capital $ 2,125 $ (1,361) $ (1,652)
Net cash provided by operating activities includes the following cash payments:
Interest on debt (net of capitalized interest) $ 525 $ 699 $ 720
Income taxes 9,148 4,355 2,987
Proceeds and deposits related to asset sales and returns of investment consisted of the following gross amounts:
Proceeds and deposits related to asset sales $ 1,435 $ 1,352 $ 2,891
Returns of investment from equity affiliates 1,200 439 77
Proceeds and deposits related to asset sales and returns of investment $ 2,635 $ 1,791 $ 2,968
Net sales (purchases) of marketable securities consisted of the following gross amounts:
Marketable securities purchased $ (7) $ (4) $ -
Marketable securities sold 124 3 35
Net sales (purchases) of marketable securities $ 117 $ (1) $ 35
Net repayment (borrowing) of loans by equity affiliates:
Borrowing of loans by equity affiliates $ (108) $ - $ (3,925)
Repayment of loans by equity affiliates 84 401 2,506
Net repayment (borrowing) of loans by equity affiliates $ (24) $ 401 $ (1,419)
Net borrowings (repayments) of short-term obligations consisted of the following gross and net amounts:
Proceeds from issuances of short-term obligations $ - $ 4,448 $ 10,846
Repayments of short-term obligations - (6,906) (9,771)
Net borrowings (repayments) of short-term obligations with three months or less maturity 263 (3,114) (424)
Net borrowings (repayments) of short-term obligations $ 263 $ (5,572) $ 651
Net sales (purchases) of treasury shares consists of the following gross and net amounts:
Shares issued for share-based compensation plans $ 5,838 $ 1,421 $ 226
Shares purchased under share repurchase and deferred compensation plans (11,255) (1,383) (1,757)
Net sales (purchases) of treasury shares $ (5,417) $ 38 $ (1,531)
Net contributions from (distributions to) noncontrolling interests consisted of the following gross and net amounts:
Distributions to noncontrolling interests $ (118) $ (53) $ (26)
Contributions from noncontrolling interests 4 17 2
Net contributions from (distributions to) noncontrolling interests $ (114) $ (36) $ (24)
The “Other” line in the Operating Activities section includes changes in postretirement benefits obligations and other long-term liabilities.
The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash. “Depreciation, depletion and amortization,” “Deferred income tax provision,” and “Dry hole expense,” collectively include approximately $1.1 billion in non-cash reductions to properties, plant and equipment in 2022 relating to impairments and other non-cash charges. The company did not have any material impairments in 2021.
Refer also to Note 25 Asset Retirement Obligations for a discussion of revisions to the company’s AROs that also did not involve cash receipts or payments for the three years ending December 31, 2022.
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
The components of “Capital expenditures” are presented in the following table:
Year ended December 31
2022 2021 2020
Additions to properties, plant and equipment *
$ 10,349 $ 7,515 $ 8,492
Additions to investments 1,147 460 136
Current-year dry hole expenditures 309 83 327
Payments for other assets and liabilities, net
169 (2) (33)
Capital expenditures $ 11,974 $ 8,056 $ 8,922
* Excludes non-cash movements of $334 in 2022, $316 in 2021 and $816 in 2020.
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
2022 2021 2020
Cash and cash equivalents
$ 17,678 $ 5,640 $ 5,596
Restricted cash included in “Prepaid expenses and other current assets”
630 333 365
Restricted cash included in “Deferred charges and other assets”
813 822 776
Total cash, cash equivalents and restricted cash
$ 19,121 $ 6,795 $ 6,737
Note 4
New Accounting Standards
There are not currently any new or pending accounting standards that have a significant impact on Chevron.
Note 5
Lease Commitments
The company enters into leasing arrangements as a lessee; any lessor arrangements are not significant. Operating lease arrangements mainly involve land, bareboat charters, terminals, drill ships, drilling rigs, time chartered vessels, office buildings and warehouses, and exploration and production equipment. Finance leases primarily include facilities, vessels and office buildings.
Details of the right-of-use assets and lease liabilities for operating and finance leases, including the balance sheet presentation, are as follows:
At December 31, 2022 At December 31, 2021
Operating
Leases Finance
Leases Operating
Leases Finance
Leases
Deferred charges and other assets $ 4,262 $ - $ 3,668 $ -
Properties, plant and equipment, net - 392 - 429
Right-of-use assets* $ 4,262 $ 392 $ 3,668 $ 429
Accrued Liabilities $ 1,111 $ - $ 995 $ -
Short-term Debt - 45 - 48
Current lease liabilities 1,111 45 995 48
Deferred credits and other noncurrent obligations 2,920 - 2,508 -
Long-term Debt - 403 - 449
Noncurrent lease liabilities 2,920 403 2,508 449
Total lease liabilities
$ 4,031 $ 448 $ 3,503 $ 497
Weighted-average remaining lease term (in years) 7.0 11.9 7.8 13.2
Weighted-average discount rate 1.9 % 4.1 % 2.2 % 4.2 %
* Includes non-cash additions of $1,807 and $3 in 2022, and $1,063 and $60 in 2021 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:
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
Year-ended December 31
2022 2021 2020
Operating lease costs* $ 2,359 $ 2,199 $ 2,551
Finance lease costs 57 66 45
Total lease costs
$ 2,416 $ 2,265 $ 2,596
* 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
2022 2021 2020
Operating cash flows from operating leases $ 1,892 $ 1,670 $ 1,744
Investing cash flows from operating leases 467 398 762
Operating cash flows from finance leases 18 21 14
Financing cash flows from finance leases 44 193 34
At December 31, 2022, the estimated future undiscounted cash flows for operating and finance leases were as follows:
At December 31, 2022
Operating Leases Finance
Leases
Year 2023 $ 1,171 $ 61
2024 902 61
2025 633 57
2026 391 54
2027 252 47
Thereafter 1,042 269
Total $ 4,391 $ 549
Less: Amounts representing interest 360 101
Total lease liabilities
$ 4,031 $ 448
Additionally, the company has $1,570 in future undiscounted cash flows for operating leases not yet commenced. These leases are primarily for drill ships and drilling rigs. The company also has $327 in future undiscounted cash flows for a finance lease not yet commenced for production equipment. For those leasing arrangements where the underlying asset is not yet constructed, the lessor is primarily involved in the design and construction of the asset.
Note 6
Summarized Financial Data - Chevron U.S.A. Inc.
Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron Corporation. CUSA and its subsidiaries manage and operate most of Chevron’s U.S. businesses. Assets include those related to the exploration and production of crude oil, natural gas liquids and natural gas and those associated with the refining, marketing, supply and distribution of products derived from petroleum, excluding most of the regulated pipeline operations of Chevron. CUSA also holds the company’s investment in the Chevron Phillips Chemical Company LLC joint venture, which is accounted for using the equity method. The summarized financial information for CUSA and its consolidated subsidiaries is as follows:
Year ended December 31
2022 2021 2020
Sales and other operating revenues
$ 183,032 $ 120,380 $ 67,950
Total costs and other deductions
166,955 114,641 72,575
Net income (loss) attributable to CUSA
13,315 6,904 (2,676)
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
At December 31
2022 2021
Current assets $ 18,704 $ 20,216
Other assets 50,153 47,355
Current liabilities 22,452 17,824
Other liabilities 19,274 18,438
Total CUSA net equity $ 27,131 $ 31,309
Memo: Total debt $ 10,800 $ 11,693
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
2022 2021 2020
Sales and other operating revenues $ 23,795 $ 15,927 $ 9,194
Costs and other deductions 11,596 8,186 6,076
Net income attributable to TCO 8,566 5,418 2,196
At December 31
2022 2021
Current assets $ 6,522 $ 3,307
Other assets 54,506 51,473
Current liabilities 3,567 3,436
Other liabilities 12,312 12,060
Total TCO net equity $ 45,149 $ 39,284
Note 8
Summarized Financial Data - Chevron Phillips Chemical Company LLC
Chevron has a 50 percent equity ownership interest in Chevron Phillips Chemical Company LLC (CPChem). Refer to Note 15 Investments and Advances for a discussion of CPChem operations. Summarized financial information for 100 percent of CPChem is presented in the table below:
Year ended December 31
2022 2021 2020
Sales and other operating revenues $ 14,180 $ 14,104 $ 8,407
Costs and other deductions 12,870 10,862 7,221
Net income attributable to CPChem 1,662 3,684 1,260
At December 31
2022 2021
Current assets $ 3,472 $ 3,381
Other assets 15,184 14,396
Current liabilities 2,146 1,854
Other liabilities 2,941 3,160
Total CPChem net equity $ 13,569 $ 12,763
Note 9
Fair Value Measurements
The tables below show the fair value hierarchy for assets and liabilities measured at fair value on a recurring and nonrecurring basis at December 31, 2022 and 2021.
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, 2022.
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
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
amount to the Consolidated Statement of Income. The company designates certain derivative instruments as cash flow hedges that, if applicable, are reflected in the table below. Derivatives classified as Level 1 include futures, swaps and options contracts valued using quoted prices from active markets such as the New York Mercantile Exchange. Derivatives classified as Level 2 include swaps, options and forward contracts, the fair values of which are obtained from third-party broker quotes, industry pricing services and exchanges. The company obtains multiple sources of pricing information for the Level 2 instruments. Since this pricing information is generated from observable market data, it has historically been very consistent. The company does not materially adjust this information.
Properties, Plant and Equipment The company did not have any individually material impairments of long-lived assets measured at fair value on a nonrecurring basis to report in 2022 or 2021.
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 2022 or 2021.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
At December 31, 2022 At December 31, 2021
Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3
Marketable securities $ 223 $ 223 $ - $ - $ 35 $ 35 $ - $ -
Derivatives - not designated 184 111 73 - 313 285 28 -
Total assets at fair value $ 407 $ 334 $ 73 $ - $ 348 $ 320 $ 28 $ -
Derivatives - not designated 43 33 10 - 72 24 48 -
Derivatives - designated 15 15 - - - - - -
Total liabilities at fair value $ 58 $ 48 $ 10 $ - $ 72 $ 24 $ 48 $ -
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 2022 Total Level 1 Level 2 Level 3 Year 2021
Properties, plant and equipment, net (held and used) $ 54 $ - $ - $ 54 $ 518 $ 124 $ - $ - $ 124 $ 414
Properties, plant and equipment, net (held for sale) - - - - 432 - - - - -
Investments and advances 33 2 - 31 9 16 - - 16 32
Total nonrecurring assets at fair value $ 87 $ 2 $ - $ 85 $ 959 $ 140 $ - $ - $ 140 $ 446
At year-end 2022, the company had assets measured at fair value Level 3 using unobservable inputs of $85. The carrying value of these assets were written down to fair value based on estimates derived from internal 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.
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 $17,678 and $5,640 at December 31, 2022, and December 31, 2021, 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, 2022.
“Cash and cash equivalents” do not include investments with a carrying/fair value of $1,443 and $1,155 at December 31, 2022, and December 31, 2021, respectively. At December 31, 2022, these investments are classified as Level 1 and include restricted funds related to certain upstream decommissioning activities, tax payments and a financing program.
Long-term debt, excluding finance lease liabilities, of $16,258 and $22,164 at December 31, 2022, and December 31, 2021, respectively, had estimated fair values of $14,959 and $23,670, respectively. Long-term debt primarily includes corporate issued bonds. The fair value of corporate bonds is $14,571 and classified as Level 1. The fair value of other long-term debt classified as Level 2 is $388.
The carrying values of other short-term financial assets and liabilities on the Consolidated Balance Sheet approximate their fair values. Fair value remeasurements of other financial instruments at December 31, 2022 and 2021, were not material.
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
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, 2022, 2021 and 2020, and their classification on the Consolidated Balance Sheet below and Consolidated Statement of Income on the following page:
Consolidated Balance Sheet: Fair Value of Derivatives
At December 31
Type of Contract Balance Sheet Classification 2022 2021
Commodity Accounts and notes receivable, net
$ 175 $ 251
Commodity Long-term receivables, net
9 62
Total assets at fair value $ 184 $ 313
Commodity Accounts payable $ 46 $ 71
Commodity Deferred credits and other noncurrent obligations
12 1
Total liabilities at fair value $ 58 $ 72
Consolidated Statement of Income: The Effect of Derivatives
Gain/(Loss)
Type of Derivative Statement of Year ended December 31
Contract Income Classification 2022 2021 2020
Commodity Sales and other operating revenues $ (651) $ (685) $ 69
Commodity Purchased crude oil and products
(226) (64) (36)
Commodity Other income 10 (46) 7
$ (867) $ (795) $ 40
The amount reclassified from “Accumulated other comprehensive losses” (AOCL) to “Sales and other operating revenues” from designated hedges was $80 in 2022, compared with an immaterial amount in the prior year. At December 31, 2022, before-tax deferred losses in AOCL related to outstanding crude oil price hedging contracts were $15, 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, 2022 and 2021.
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, 2022
Derivative Assets - not designated $ 2,591 $ 2,407 $ 184 $ 5 $ 179
Derivative Assets - designated $ 8 $ 8 $ - $ - $ -
Derivative Liabilities - not designated $ 2,450 $ 2,407 $ 43 $ - $ 43
Derivative Liabilities - designated $ 23 $ 8 $ 15 $ - $ 15
At December 31, 2021
Derivative Assets - not designated $ 1,684 $ 1,371 $ 313 $ - $ 313
Derivative Liabilities - not designated $ 1,443 $ 1,371 $ 72 $ - $ 72
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
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, 2022, the company classified $436 of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. These assets are associated with upstream operations that are anticipated to be sold in the next 12 months. The revenues and earnings contributions of these assets in 2022 were not material.
Note 12
Equity
Retained earnings at December 31, 2022 and 2021, included $33,570 and $28,876, respectively, for the company’s share of undistributed earnings of equity affiliates.
At December 31, 2022, about 104 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, 597,152 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:
Year ended December 31
2022 2021 2020
Basic EPS Calculation
Earnings available to common stockholders - Basic1
$ 35,465 $ 15,625 $ (5,543)
Weighted-average number of common shares outstanding2
1,931 1,916 1,870
Add: Deferred awards held as stock units
- - -
Total weighted-average number of common shares outstanding 1,931 1,916 1,870
Earnings per share of common stock - Basic $ 18.36 $ 8.15 $ (2.96)
Diluted EPS Calculation
Earnings available to common stockholders - Diluted1
$ 35,465 $ 15,625 $ (5,543)
Weighted-average number of common shares outstanding2
1,931 1,916 1,870
Add: Deferred awards held as stock units
- - -
Add: Dilutive effect of employee stock-based awards
9 4 -
Total weighted-average number of common shares outstanding 1,940 1,920 1,870
Earnings per share of common stock - Diluted $ 18.28 $ 8.14 $ (2.96)
1 There was no effect of dividend equivalents paid on stock units or dilutive impact of employee stock-based awards on earnings.
2 Millions of shares; 1 million shares of employee-based awards were not included in the 2020 diluted EPS calculation as the result would be anti-dilutive.
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
Note 14
Operating Segments and Geographic Data
Although each subsidiary of Chevron is responsible for its own affairs, Chevron Corporation manages its investments in these subsidiaries and their affiliates. The investments are grouped into two business segments, Upstream and Downstream, representing the company’s “reportable segments” and “operating segments.” Upstream operations consist primarily of exploring for, developing, producing and transporting crude oil and natural gas; liquefaction, transportation and regasification associated with liquefied natural gas (LNG); transporting crude oil by major international oil export pipelines; processing, transporting, storage and marketing of natural gas; and a gas-to-liquids plant. Downstream operations consist primarily of refining of crude oil into petroleum products; marketing of crude oil, refined products, and lubricants; manufacturing and marketing of renewable fuels; transporting of crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant additives. All Other activities of the company include worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology activities.
The company’s segments are managed by “segment managers” who report to the “chief operating decision maker” (CODM). The segments represent components of the company that engage in activities (a) from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the segments and assesses their performance; and (c) for which discrete financial information is available.
The company’s primary country of operation is the United States of America, its country of domicile. Other components of the company’s operations are reported as “International” (outside the United States).
Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Non-billable costs remain at the corporate level in “All Other.” Earnings by major operating area are presented in the following table:
Year ended December 31
2022 2021 2020
Upstream
United States $ 12,621 $ 7,319 $ (1,608)
International 17,663 8,499 (825)
Total Upstream 30,284 15,818 (2,433)
Downstream
United States 5,394 2,389 (571)
International 2,761 525 618
Total Downstream 8,155 2,914 47
Total Segment Earnings 38,439 18,732 (2,386)
All Other
Interest expense (476) (662) (658)
Interest income 261 36 52
Other (2,759) (2,481) (2,551)
Net Income (Loss) Attributable to Chevron Corporation
$ 35,465 $ 15,625 $ (5,543)
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 2022 and 2021 are as follows:
At December 31
2022 2021
Upstream
United States $ 44,246 $ 41,870
International 134,489 138,157
Goodwill 4,370 4,385
Total Upstream 183,105 184,412
Downstream
United States 31,676 26,376
International 21,193 18,848
Goodwill 352 -
Total Downstream 53,221 45,224
Total Segment Assets 236,326 229,636
All Other
United States 17,861 5,746
International 3,522 4,153
Total All Other 21,383 9,899
Total Assets - United States 93,783 73,992
Total Assets - International 159,204 161,158
Goodwill 4,722 4,385
Total Assets $ 257,709 $ 239,535
Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2022, 2021 and 2020, are presented in the table on the next page. Products are transferred between operating segments at internal product values that approximate market prices.
Revenues for the upstream segment are derived primarily from the production and sale of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the manufacture and sale of fuel and lubricant additives and the transportation and trading of refined products and crude oil. “All Other” activities include revenues from insurance operations, real estate activities and technology companies.
Notes to the Consolidated Financial Statements
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Millions of dollars, except per-share amounts
Year ended December 311
2022 2021 2020
Upstream
United States
$ 50,822 $ 29,219 $ 14,577
International
56,156 40,921 26,804
Subtotal
106,978 70,140 41,381
Intersegment Elimination - United States
(29,870) (15,154) (8,068)
Intersegment Elimination - International
(13,815) (10,994) (7,002)
Total Upstream 63,293 43,992 26,311
Downstream
United States
91,824 57,209 32,589
International
87,741 58,098 38,936
Subtotal
179,565 115,307 71,525
Intersegment Elimination - United States
(5,529) (2,296) (2,150)
Intersegment Elimination - International
(1,728) (1,521) (1,292)
Total Downstream 172,308 111,490 68,083
All Other
United States
515 506 744
International
3 2 15
Subtotal
518 508 759
Intersegment Elimination - United States
(400) (382) (667)
Intersegment Elimination - International
(2) (2) (15)
Total All Other 116 124 77
Sales and Other Operating Revenues
United States
143,161 86,934 47,910
International
143,900 99,021 65,755
Subtotal
287,061 185,955 113,665
Intersegment Elimination - United States
(35,799) (17,832) (10,885)
Intersegment Elimination - International
(15,545) (12,517) (8,309)
Total Sales and Other Operating Revenues
$ 235,717 $ 155,606 $ 94,471
1 Other than the United States, no other country accounted for 10 percent or more of the company’s Sales and Other Operating Revenues.
Segment Income Taxes Segment income tax expense for the years 2022, 2021 and 2020 is as follows:
Year ended December 31
2022 2021 2020
Upstream
United States $ 3,678 $ 1,934 $ (570)
International 9,055 4,192 (415)
Total Upstream 12,733 6,126 (985)
Downstream
United States 1,515 547 (192)
International 280 203 253
Total Downstream 1,795 750 61
All Other (462) (926) (968)
Total Income Tax Expense (Benefit) $ 14,066 $ 5,950 $ (1,892)
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.
Notes to the Consolidated Financial Statements
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Millions of dollars, except per-share amounts
Note 15
Investments and Advances
Equity in earnings, together with investments in and advances to companies accounted for using the equity method and other investments accounted for at or below cost, is shown in the following table. For certain equity affiliates, Chevron pays its share of some income taxes directly. For such affiliates, the equity in earnings does not include these taxes, which are reported on the Consolidated Statement of Income as “Income tax expense.”
Investments and Advances Equity in Earnings
At December 31 Year ended December 31
2022 2021 2022 2021 2020
Upstream
Tengizchevroil $ 26,534 $ 23,727 $ 4,386 $ 2,831 $ 1,238
Petropiar - - - - (1,396)
Petroboscan - - - - (1,112)
Caspian Pipeline Consortium 761 805 128 155 159
Angola LNG Limited 1,963 2,180 1,857 336 (166)
Other 1,938 1,859 255 187 137
Total Upstream 31,196 28,571 6,626 3,509 (1,140)
Downstream
Chevron Phillips Chemical Company LLC 6,843 6,455 867 1,842 630
GS Caltex Corporation 4,288 3,616 874 85 (185)
Other 2,288 1,725 224 220 223
Total Downstream 13,419 11,796 1,965 2,147 668
All Other
Other (5) (10) (6) 1 -
Total equity method $ 44,610 $ 40,357 $ 8,585 $ 5,657 $ (472)
Other non-equity method investments 628 339
Total investments and advances $ 45,238 $ 40,696
Total United States $ 9,855 $ 8,540 $ 975 $ 1,889 $ 709
Total International $ 35,383 $ 32,156 $ 7,610 $ 3,768 $ (1,181)
Descriptions of major equity affiliates and non-equity investments, including significant differences between the company’s carrying value of its investments and its underlying equity in the net assets of the affiliates, are as follows:
Tengizchevroil Chevron has a 50 percent equity ownership interest in Tengizchevroil (TCO), which operates the Tengiz and Korolev crude oil fields in Kazakhstan. At December 31, 2022, the company’s carrying value of its investment in TCO was about $90 higher than the amount of underlying equity in TCO’s net assets. This difference results from Chevron acquiring a portion of its interest in TCO at a value greater than the underlying book value for that portion of TCO’s net assets. Included in the investment is a loan to TCO to fund the development of the FGP/WPMP with a principal balance of $4,500.
Petropiar Chevron has a 30 percent interest in Petropiar, a joint stock company which operates the heavy oil Huyapari Field and upgrading project in Venezuela’s Orinoco Belt. In 2020, the company fully impaired its investments in the Petropiar affiliate and, effective July 1, 2020, began accounting for this venture as a non-equity method investment.
Petroboscan Chevron has a 39.2 percent interest in Petroboscan, a joint stock company which operates the Boscan Field in Venezuela. In 2020, the company fully impaired its investments in the Petroboscan affiliate and, effective July 1, 2020, began accounting for this venture as a non-equity method investment. The company also has an outstanding long-term loan to Petroboscan of $560, which remains fully provisioned for at year-end 2022.
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 $59 to fund a portion of the Golden Triangle Polymers Project in Orange, Texas, in which Chevron Phillips Chemical Company LLC owns 51 percent.
Notes to the Consolidated Financial Statements
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Millions of dollars, except per-share amounts
GS Caltex Corporation Chevron owns 50 percent of GS Caltex Corporation, a joint venture with GS Energy in South Korea. The joint venture imports, produces and markets petroleum products, petrochemicals and lubricants.
Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $16,286, $10,796 and $6,038 with affiliated companies for 2022, 2021 and 2020, respectively. “Purchased crude oil and products” includes $10,171, $5,778 and $3,003 with affiliated companies for 2022, 2021 and 2020, respectively.
“Accounts and notes receivable” on the Consolidated Balance Sheet includes $907 and $1,454 due from affiliated companies at December 31, 2022 and 2021, respectively. “Accounts payable” includes $709 and $552 due to affiliated companies at December 31, 2022 and 2021, 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 $4,278, $4,704 and $5,153 at December 31, 2022, 2021 and 2020, respectively.
Affiliates Chevron Share
Year ended December 31 2022 2021 2020 2022 2021 2020
Total revenues $ 100,184 $ 71,241 $ 49,093 $ 48,323 $ 34,359 $ 21,641
Income before income tax expense*
23,811 15,175 5,682 10,876 6,984 2,550
Net income attributable to affiliates 19,077 12,598 4,704 8,595 5,670 2,034
At December 31
Current assets $ 26,632 $ 21,871 $ 17,087 $ 11,671 $ 9,267 $ 7,328
Noncurrent assets 101,557 100,235 97,468 46,428 44,360 43,247
Current liabilities 16,319 17,275 12,164 7,708 7,492 5,052
Noncurrent liabilities 22,943 24,219 25,586 5,980 5,982 5,884
Total affiliates’ net equity $ 88,927 $ 80,612 $ 76,805 $ 44,411 $ 40,153 $ 39,639
* 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 2022 was $4,734, with Chevron’s share being $2,281.
Note 16
Litigation
Ecuador
In 2003, Chevron was sued in Ecuador for environmental harm allegedly caused by an oil consortium formerly operated by a Texaco subsidiary. The subsidiary previously had been released from environmental claims by Ecuador after it completed a three-year remediation program, which Ecuador certified. Nonetheless, in February 2011, the Ecuadorian trial court entered judgment against Chevron for approximately $9.5 billion, plus punitive damages. An appellate panel affirmed, and Ecuador’s National Court of Justice ratified the judgment but nullified the punitive damages. Ecuador’s highest Constitutional Court rejected Chevron’s final appeal in July 2018.
In 2011, Chevron sued the Ecuadorian plaintiffs and several of their lawyers and cohorts in the U.S. District Court for the Southern District of New York (SDNY) for violations of the Racketeer Influenced and Corrupt Organizations (RICO) Act and state law. The SDNY ruled that the Ecuadorian judgment had been procured through fraud, bribery, and corruption, and prohibited the defendants from seeking to enforce the judgment in the United States or profiting from their illegal acts. The Second Circuit affirmed, and the U.S. Supreme Court denied certiorari in 2017. The Ecuadorian plaintiffs sought to have the Ecuadorian judgment recognized and enforced in Canada, Brazil, and Argentina, but all of those actions were dismissed in Chevron’s favor.
In 2009, Chevron filed an arbitration claim against Ecuador before an arbitral tribunal administered by the Permanent Court of Arbitration in The Hague, under the United States-Ecuador Bilateral Investment Treaty. In 2018, the Tribunal ruled that the Ecuadorian judgment was procured through fraud, bribery, and corruption, and was based on environmental claims that Ecuador had already settled and released. According to the Tribunal, the Ecuadorian judgment “violates international public policy” and “should not be recognized or enforced by the courts of other States.” The Tribunal ordered Ecuador to remove the judgment’s status of enforceability and to compensate Chevron for its injuries. The arbitration’s final phases, to determine the amount of compensation owed to Chevron and to allocate the arbitration’s costs, remain pending. In 2020, the District Court of The Hague denied Ecuador’s request to set aside the Tribunal’s award. Based on Ecuador’s admissions during the litigation, the Court stated that it now is “common ground” between Ecuador and Chevron that the Ecuadorian judgment is fraudulent. In June 2022, The Hague Court of Appeals dismissed Ecuador’s appeal. In September
Notes to the Consolidated Financial Statements
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Millions of dollars, except per-share amounts
2022, Ecuador appealed to the Dutch Supreme Court. In a separate proceeding before the Office of the United States Trade Representative, Ecuador also admitted in July 2020 that the Ecuadorian judgment is fraudulent.
Management continues to believe that the Ecuadorian judgment is illegitimate and unenforceable and will vigorously defend against any further attempts to have it recognized or enforced.
Climate Change
Governmental and other entities in various jurisdictions across the United States have filed legal proceedings against fossil fuel producing companies, including Chevron entities, purporting to seek legal and equitable relief to address alleged impacts of climate change. Chevron entities are or were among the codefendants in 23 separate lawsuits brought by 17 U.S. cities and counties, three U.S. states, the District of Columbia, a group of municipalities in Puerto Rico and a trade group. One of the city lawsuits was dismissed on the merits, and one of the county lawsuits was voluntarily dismissed by the plaintiff. The lawsuits assert various causes of action, including public nuisance, private nuisance, failure to warn, fraud, conspiracy to commit fraud, design defect, product defect, trespass, negligence, impairment of public trust, violations of consumer protection statutes, violations of a federal antitrust statute, and violations of the RICO Act, based upon, among other things, the company’s production of oil and gas products and alleged misrepresentations or omissions relating to climate change risks associated with those products. The unprecedented legal theories set forth in these proceedings entail the possibility of damages liability (both compensatory and punitive), injunctive and other forms of equitable relief, including without limitation abatement and disgorgement of profits, civil penalties and liability for fees and costs of suits, that, while we believe remote, could have a material adverse effect on the company’s results of operations and financial condition. Further such proceedings are likely to be filed by other parties. Management believes that these proceedings are legally and factually meritless and detract from constructive efforts to address the important policy issues presented by climate change, and will vigorously defend against such proceedings.
Louisiana
Seven coastal parishes and the State of Louisiana have filed lawsuits in Louisiana against numerous oil and gas companies seeking damages for coastal erosion in or near oil fields located within Louisiana’s coastal zone under Louisiana’s State and Local Coastal Resources Management Act (SLCRMA). Chevron entities are defendants in 39 of these cases. The lawsuits allege that the defendants’ historical operations were conducted without necessary permits or failed to comply with permits obtained and seek damages and other relief, including the costs of restoring coastal wetlands allegedly impacted by oil field operations. Plaintiffs’ SLCRMA theories are unprecedented; thus, there remains significant uncertainty about the scope of the claims and alleged damages and any potential effects on the company’s results of operations and financial condition. Management believes that the claims lack legal and factual merit and will continue to vigorously defend against such proceedings.
Note 17
Taxes
Income Taxes
Year ended December 31
2022 2021 2020
Income tax expense (benefit)
U.S. federal
Current $ 1,723 $ 174 $ (182)
Deferred 2,240 1,004 (1,315)
State and local
Current 482 222 65
Deferred 39 202 (152)
Total United States 4,484 1,602 (1,584)
International
Current 9,738 4,854 1,833
Deferred (156) (506) (2,141)
Total International 9,582 4,348 (308)
Total income tax expense (benefit) $ 14,066 $ 5,950 $ (1,892)
The reconciliation between the U.S. statutory federal income tax rate and the company’s effective income tax rate is detailed in the following table:
Notes to the Consolidated Financial Statements
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Millions of dollars, except per-share amounts
2022 2021 2020
Income (loss) before income taxes
United States $ 21,005 $ 9,674 $ (5,700)
International 28,669 11,965 (1,753)
Total income (loss) before income taxes 49,674 21,639 (7,453)
Theoretical tax (at U.S. statutory rate of 21%) 10,432 4,544 (1,565)
Equity affiliate accounting effect (1,678) (890) 211
Effect of income taxes from international operations 5,041 2,692 (39)
State and local taxes on income, net of U.S. federal income tax benefit
508 216 (65)
Prior year tax adjustments, claims and settlements 1
(90) 362 (236)
Tax credits (6) (173) (33)
Other U.S. 1, 2
(141) (801) (165)
Total income tax expense (benefit) $ 14,066 $ 5,950 $ (1,892)
Effective income tax rate 3
28.3 % 27.5 % 25.4 %
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 (2022 - $(36); 2021 - $(624); 2020 - $0).
3 The company’s effective tax rate is reflective of equity income reported on an after-tax basis as part of the “Total Income (Loss) Before Income Tax Expense,” in accordance with U.S. Generally Accepted Accounting Principles. Chevron’s share of its equity affiliates’ total income tax expense in 2022 was $2,281.
The 2022 increase in income tax expense of $8,116 is a result of the year-over-year increase in total income before income tax expense, which is primarily due to higher upstream realizations and downstream margins. The company’s effective tax rate changed from 27.5 percent in 2021 to 28.3 percent in 2022. The change in effective tax rate is mainly due to mix effects resulting from the absolute level of earnings or losses and whether they arose in higher or lower tax rate jurisdictions.
The company records its deferred taxes on a tax-jurisdiction basis. The reported deferred tax balances are composed of the following:
At December 31
2022 2021
Deferred tax liabilities
Properties, plant and equipment $ 18,295 $ 17,169
Investments and other 4,492 4,105
Total deferred tax liabilities 22,787 21,274
Deferred tax assets
Foreign tax credits (12,599) (11,718)
Asset retirement obligations/environmental reserves (4,518) (4,553)
Employee benefits (2,087) (3,037)
Deferred credits (446) (996)
Tax loss carryforwards (3,887) (4,175)
Other accrued liabilities (746) (239)
Inventory (219) (289)
Operating leases (1,134) (1,255)
Miscellaneous (4,057) (3,657)
Total deferred tax assets (29,693) (29,919)
Deferred tax assets valuation allowance 19,532 17,651
Total deferred taxes, net $ 12,626 $ 9,006
Deferred tax liabilities increased by $1,513 from year-end 2021, primarily driven by an increase to properties, plant and equipment. Deferred tax assets decreased by $226 from year-end 2021. This decrease was primarily related to decreases in employee benefits and tax loss carryforwards for various locations, partially offset by the increase in foreign tax credits.
The overall valuation allowance relates to deferred tax assets for U.S. foreign tax credit carryforwards, tax loss carryforwards and temporary differences. The valuation allowance reduces the deferred tax assets to amounts that are, in management’s assessment, more likely than not to be realized. At the end of 2022, the company had gross tax loss carryforwards of approximately $9,850 and tax credit carryforwards of approximately $440, 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 2023 through 2041. U.S. foreign tax credit carryforwards of $12,599 will expire between 2023 and 2033.
Notes to the Consolidated Financial Statements
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At December 31, 2022 and 2021, deferred taxes were classified on the Consolidated Balance Sheet as follows:
At December 31
2022 2021
Deferred charges and other assets $ (4,505) $ (5,659)
Noncurrent deferred income taxes 17,131 14,665
Total deferred income taxes, net $ 12,626 $ 9,006
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. The indefinite reinvestment assertion continues to apply for the purpose of determining deferred tax liabilities for U.S. state and foreign withholding tax purposes.
Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for possible future remittances totaled approximately $51,300 at December 31, 2022. This amount represents earnings reinvested as part of the company’s ongoing international business. It is not practicable to estimate the amount of state and foreign withholding taxes that might be payable on the possible remittance of earnings that are intended to be reinvested indefinitely. The company does not anticipate incurring significant additional taxes on remittances of earnings that are not indefinitely reinvested.
Uncertain Income Tax Positions The company recognizes a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that the position is more likely than not (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in the accounting standards for income taxes refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods.
The following table indicates the changes to the company’s unrecognized tax benefits for the years ended December 31, 2022, 2021 and 2020. 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.
2022 2021 2020
Balance at January 1 $ 5,288 $ 5,018 $ 4,987
Foreign currency effects (2) (1) 2
Additions based on tax positions taken in current year 30 194 253
Additions for tax positions taken in prior years
234 218 437
Reductions for tax positions taken in prior years
(117) (36) (216)
Settlements with taxing authorities in current year
(110) (18) (429)
Reductions as a result of a lapse of the applicable statute of limitations
- (87) (16)
Balance at December 31 $ 5,323 $ 5,288 $ 5,018
Approximately 80 percent of the $5,323 of unrecognized tax benefits at December 31, 2022, 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.
Tax positions for Chevron and its subsidiaries and affiliates are subject to income tax audits by many tax jurisdictions throughout the world. For the company’s major tax jurisdictions, examinations of tax returns for certain prior tax years had not been completed as of December 31, 2022. For these jurisdictions, the latest years for which income tax examinations had been finalized were as follows: United States - 2016, Nigeria - 2007, Australia - 2009, Kazakhstan - 2012 and Saudi Arabia - 2016.
The company engages in ongoing discussions with tax authorities regarding the resolution of tax matters in the various jurisdictions. Both the outcome of these tax matters and the timing of resolution and/or closure of the tax audits are highly uncertain. Of the amount of unrecognized tax benefits the company has identified as of December 31, 2022, it is reasonably possible that developments on tax matters in certain tax jurisdictions may result in decreases of approximately 20 percent within the next 12 months. Given the number of years that still remain subject to examination and the number of matters being examined in the various tax jurisdictions, the company is unable to estimate the range of possible adjustments to the balance of unrecognized tax benefits beyond the next 12 months.
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, 2022, accrued expense of $112 for anticipated interest
Notes to the Consolidated Financial Statements
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Millions of dollars, except per-share amounts
and penalties was included on the Consolidated Balance Sheet, compared with accrued benefit of $(76) as of year-end 2021. Income tax expense (benefit) associated with interest and penalties was $152, $19 and $(124) in 2022, 2021 and 2020, respectively.
Taxes Other Than on Income
Year ended December 31
2022 2021 2020
United States
Import duties and other levies $ 10 $ 7 $ 7
Property and other miscellaneous taxes
609 552 588
Payroll taxes 248 302 235
Taxes on production 989 628 317
Total United States 1,856 1,489 1,147
International
Import duties and other levies 63 49 39
Property and other miscellaneous taxes
1,789 2,174 1,461
Payroll taxes 122 113 117
Taxes on production 202 138 75
Total International 2,176 2,474 1,692
Total taxes other than on income $ 4,032 $ 3,963 $ 2,839
Note 18
Properties, Plant and Equipment1
At December 31 Year ended December 31
Gross Investment at Cost Net Investment Additions at Cost2
Depreciation Expense3
2022 2021 2020 2022 2021 2020 2022 2021 2020 2022 2021 2020
Upstream
United States $ 96,590 $ 93,393 $ 96,555 $ 37,031 $ 36,027 $ 38,175 $ 6,461 $ 4,520 $ 13,067 $ 5,012 $ 5,675 $ 6,841
International 188,556 202,757 209,846 88,549 94,770 102,010 2,599 2,349 11,069 9,830 10,824 11,121
Total Upstream 285,146 296,150 306,401 125,580 130,797 140,185 9,060 6,869 24,136 14,842 16,499 17,962
Downstream
United States 29,802 26,888 26,499 12,827 10,766 11,101 2,742 543 638 913 833 851
International 8,281 8,134 7,993 3,226 3,300 3,395 246 234 573 311 296 283
Total Downstream 38,083 35,022 34,492 16,053 14,066 14,496 2,988 777 1,211 1,224 1,129 1,134
All Other
United States 4,402 4,729 4,195 1,931 2,078 1,916 230 143 194 247 290 403
International 154 144 144 27 20 21 12 7 5 6 7 9
Total All Other 4,556 4,873 4,339 1,958 2,098 1,937 242 150 199 253 297 412
Total United States 130,794 125,010 127,249 51,789 48,871 51,192 9,433 5,206 13,899 6,172 6,798 8,095
Total International 196,991 211,035 217,983 91,802 98,090 105,426 2,857 2,590 11,647 10,147 11,127 11,413
Total $ 327,785 $ 336,045 $ 345,232 $ 143,591 $ 146,961 $ 156,618 $ 12,290 $ 7,796 $ 25,546 $ 16,319 $ 17,925 $ 19,508
1Other than the United States and Australia, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2022. Australia had PP&E of $44,012, $46,687 and $48,374 in 2022, 2021 and 2020, respectively. Gross Investment at Cost, Net Investment and Additions at Cost for 2020 each include $16,703 associated with the Noble acquisition.
2Net of dry hole expense related to prior years’ expenditures of $177, $35 and $709 in 2022, 2021 and 2020, respectively.
3Depreciation expense includes accretion expense of $560, $616 and $560 in 2022, 2021 and 2020, respectively, and impairments and write-offs of $950, $414 and $2,792 in 2022, 2021 and 2020, respectively.
Notes to the Consolidated Financial Statements
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Note 19
Short-Term Debt
At December 31
2022 2021
Commercial paper $ - $ -
Notes payable to banks and others with originating terms of one year or less
328 62
Current maturities of long-term debt1
2,699 4,946
Current maturities of long-term finance leases
45 48
Redeemable long-term obligations 2,942 2,959
Subtotal
6,014 8,015
Reclassified to long-term debt (4,050) (7,759)
Total short-term debt $ 1,964 $ 256
1 Inclusive of unamortized premiums of $5 at December 31, 2022 and $0 at December 31, 2021.
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, 2022, the company had no interest rate swaps on short-term debt.
At December 31, 2022, the company had $8,495 in 364-day committed credit facilities with various major banks that enable the refinancing of short-term obligations on a long-term basis. The credit facilities allow the company to convert any amounts outstanding into a term loan for a period of up to one year. This supports commercial paper borrowing and can also be used for general corporate purposes. The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facility would be unsecured indebtedness at interest rates based on the Secured Overnight Financing Rate (SOFR), or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under this facility at December 31, 2022.
The company classified $4,050 and $7,759 of short-term debt as long-term at December 31, 2022 and 2021, respectively. Settlement of these obligations is not expected to require the use of working capital within one year, and the company has both the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.
Notes to the Consolidated Financial Statements
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Note 20
Long-Term Debt
Total long-term debt including finance lease liabilities at December 31, 2022, was $21,375. The company’s long-term debt outstanding at year-end 2022 and 2021 was as follows:
At December 31
2022 2021
Weighted Average Interest Rate (%)1
Range of Interest Rates (%)2
Principal Principal
Notes due 2023 1.282 0.426 - 7.250
$ 1,800 $ 4,800
Floating rate notes due 2023 3.384 3.121 - 3.821
800 800
Notes due 2024 3.291 2.895 - 3.900
1,650 1,650
Notes due 2025 1.724 0.687 - 3.326
4,000 4,000
Notes due 2026 2.954 2,250 2,250
Notes due 2027 2.379 1.018 - 8.000
2,000 2,000
Notes due 2028 3.850 600 600
Notes due 2029 3.250 500 500
Notes due 2030 2.236 1,500 1,500
Debentures due 2031 8.625 102 102
Debentures due 2032 8.416 8.000 - 8.625
183 183
Notes due 2040 2.978 293 293
Notes due 2041 6.000 397 397
Notes due 2043 5.250 330 330
Notes due 2044 5.050 222 222
Notes due 2047 4.950 187 187
Notes due 2049 4.200 237 237
Notes due 2050 2.763 2.343 - 3.078
1,750 1,750
Debentures due 2097 7.250 60 60
Bank loans due 2023 5.206 4.928 - 5.342
91 100
3.400% loan
- 211
Medium-term notes, maturing from 2023 to 2038 6.306 4.283 - 7.900
23 23
Notes due 2022 - 4,946
Total including debt due within one year 18,975 27,141
Debt due within one year (2,694) (4,946)
Fair market value adjustment for debt acquired in the Noble acquisition 664 741
Reclassified from short-term debt 4,050 7,759
Unamortized discounts and debt issuance costs (23) (31)
Finance lease liabilities3
403 449
Total long-term debt $ 21,375 $ 31,113
1 Weighted-average interest rate at December 31, 2022.
2 Range of interest rates at December 31, 2022.
3 For details on finance lease liabilities, see Note 5 Lease Commitments.
Chevron has an automatic shelf registration statement that expires in August 2023. 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 $18,975 matures as follows: 2023 - $2,694; 2024 - $1,650; 2025 - $4,000; 2026 - $2,250; 2027 - $2,000; and after 2027 - $6,381.
In addition to the $4.9 billion in long-term debt that matured in 2022, the company also early-redeemed $3.0 billion in notes at face value that were scheduled to mature in the second quarter of 2023.
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, 2022:
2022 2021 2020
Beginning balance at January 1 $ 2,109 $ 2,512 $ 3,041
Additions to capitalized exploratory well costs pending the determination of proved reserves
72 56 28
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
(481) (425) (102)
Capitalized exploratory well costs charged to expense
(73) (34) (667)
Other*
- - 212
Ending balance at December 31 $ 1,627 $ 2,109 $ 2,512
* 2020 represents fair value of well costs acquired in the Noble acquisition.
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
2022 2021 2020
Exploratory well costs capitalized for a period of one year or less
$ 73 $ 65 $ 26
Exploratory well costs capitalized for a period greater than one year
1,554 2,044 2,486
Balance at December 31 $ 1,627 $ 2,109 $ 2,512
Number of projects with exploratory well costs that have been capitalized for a period greater than one year*
12 15 17
*Certain projects have multiple wells or fields or both.
Of the $1,554 of exploratory well costs capitalized for more than one year at December 31, 2022, $945 is related to seven projects that had drilling activities underway or firmly planned for the near future. The $609 balance is related to five 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 $609 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability: (a) $194 (three 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 12 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 three-quarters of these decisions are expected to occur in the next five years.
The $1,554 of suspended well costs capitalized for a period greater than one year as of December 31, 2022, represents 71 exploratory wells in 12 projects. The tables below contain the aging of these costs on a well and project basis:
Aging based on drilling completion date of individual wells: Amount Number of wells
2000-2009 $ 263 14
2010-2014 1,121 49
2015-2021 170 8
Total $ 1,554 71
Aging based on drilling completion date of last suspended well in project: Amount Number of projects
2008-2013 $ 428 5
2014-2018 1,083 6
2019-2022 43 1
Total $ 1,554 12
Note 22
Stock Options and Other Share-Based Compensation
Compensation expense for stock options for 2022, 2021 and 2020 was $60 ($46 after tax), $60 ($47 after tax) and $94 ($74 after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance shares and restricted stock units was $1,013 ($770 after tax), $701 ($554 after tax) and $96 ($76 after tax) for 2022, 2021 and 2020, respectively. No significant stock-based compensation cost was capitalized at December 31, 2022, or December 31, 2021.
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 2022, 2021 and 2020 was $5,835, $1,274 and $226, respectively. Actual tax benefits realized for the tax deductions from option exercises were $216, $(15) and $8 for 2022, 2021 and 2020, respectively.
Cash paid to settle performance shares, restricted stock units and stock appreciation rights was $556, $163 and $95 for 2022, 2021 and 2020, respectively.
On May 25, 2022, stockholders approved the Chevron 2022 Long-Term Incentive Plan (2022 LTIP). Awards under the 2022 LTIP may take the form of, but are not limited to, stock options, restricted stock, restricted stock units, stock appreciation rights, performance shares and non-stock grants. From May 2022 through May 2032, no more than 104 million shares may be issued under the 2022 LTIP. For awards issued on or after May 25, 2022, no more than 48 million of those shares may be issued in the form of full value awards such as share-settled restricted stock, share-settled restricted stock units and other share-settled awards that do not require full payment in cash or property for shares underlying such awards by the award recipient. For the major types of awards issued before January 1, 2017, the contractual terms vary between three years for the performance shares and restricted stock units, and 10 years for the stock options and stock appreciation rights. For awards issued after January 1, 2017, contractual terms vary between three years for the performance shares and special restricted stock units, five years for standard restricted stock units and 10 years for the stock options and stock appreciation rights. Commencing for grants issued in January 2023 and after, standard restricted stock units vest ratably on an annual basis over a three-year period. Forfeitures of performance shares, restricted stock units, and stock appreciation rights are recognized as they occur. Forfeitures of stock options are estimated using historical forfeiture data dating back to 1990.
Noble Share-Based Plans (Noble Plans) When Chevron acquired Noble in October 2020, outstanding stock options granted under various Noble Plans were exchanged for Chevron options. These awards retained the same provisions as the original Noble Plans. Awards issued may be exercised for up to five years after termination of employment, depending upon the termination type, or the original expiration date, whichever is earlier. Other awards issued under the Noble Plans included restricted stock awards, restricted stock units, and performance shares, which retained the same provisions as the original Noble Plans. Upon termination of employment due to change-in-control, all unvested awards issued under the Noble Plans, including stock options, restricted stock awards, restricted stock units and performance shares vested on the termination date. If not exercised, awards will expire between 2023 and 2029.
Fair Value and Assumptions The fair market values of stock options and stock appreciation rights granted in 2022, 2021 and 2020 were measured on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions:
Year ended December 31
2022 2021 2020
Expected term in years1
6.9 6.8 6.6
Volatility2
31.3 % 31.1 % 20.8 %
Risk-free interest rate based on zero coupon U.S. treasury note
1.79 % 0.71 % 1.50 %
Dividend yield 5.0 % 6.0 % 4.0 %
Weighted-average fair value per option granted $ 23.56 $ 12.22 $ 13.00
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 2022 is presented below:
Shares (Thousands) Weighted-Average
Exercise Price Averaged Remaining Contractual Term (Years) Aggregate Intrinsic Value
Outstanding at January 1, 2022 77,399 $ 108.10
Granted 3,870 $ 132.69
Exercised (55,275) $ 105.56
Forfeited (729) $ 208.46
Outstanding at December 31, 2022 25,265 $ 114.61 6.62 $ 1,794
Exercisable at December 31, 2022 16,421 $ 117.20 5.18 $ 1,178
The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2022, 2021 and 2020 was $2,369, $152 and $92, respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
As of December 31, 2022, there was $78 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 1.8 years.
At January 1, 2022, the number of LTIP performance shares outstanding was equivalent to 5,023,065 shares. During 2022, 1,552,624 performance shares were granted, 1,652,839 shares vested with cash proceeds distributed to recipients and 169,584 shares were forfeited. At December 31, 2022, there were 4,753,266 performance shares outstanding that are payable in cash. The fair value of the liability recorded for these instruments was $996 and was measured largely using the Monte Carlo simulation method.
At January 1, 2022, the number of restricted stock units outstanding was equivalent to 4,386,637 shares. During 2022, 989,715 restricted stock units were granted, 979,382 units vested with cash proceeds distributed to recipients and 109,144 units were forfeited. At December 31, 2022, there were 4,287,826 restricted stock units outstanding that are payable in cash. The fair value of the liability recorded for the vested portion of these instruments was $548, valued at the stock price as of December 31, 2022. In addition, outstanding stock appreciation rights that were granted under the LTIP totaled 686,573 equivalent shares as of December 31, 2022. The fair value of the liability recorded for the vested portion of these instruments was $50.
Note 23
Employee Benefit Plans
The company has defined benefit pension plans for many employees. The company typically prefunds defined benefit plans as required by local regulations or in certain situations where prefunding provides economic advantages. In the United States, all qualified plans are subject to the Employee Retirement Income Security Act (ERISA) minimum funding standard. The company does not typically fund U.S. nonqualified pension plans that are not subject to funding requirements under laws and regulations because contributions to these pension plans may be less economic and investment returns may be less attractive than the company’s other investment alternatives.
The company also sponsors other postretirement benefit (OPEB) plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees. The plans are unfunded, and the company and retirees share the costs. For the company’s main U.S. medical plan, the increase to the pre-Medicare company contribution for retiree medical coverage is limited to no more than 4 percent each year. Certain life insurance benefits are paid by the company.
The company recognizes the overfunded or underfunded status of each of its defined benefit pension and OPEB plans as an asset or liability on the Consolidated Balance Sheet.
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
The funded status of the company’s pension and OPEB plans for 2022 and 2021 follows:
Pension Benefits
2022 2021 Other Benefits
U.S. Int’l. U.S. Int’l. 2022 2021
Change in Benefit Obligation
Benefit obligation at January 1 $ 12,966 $ 5,351 $ 15,166 $ 6,307 $ 2,489 $ 2,650
Service cost 432 83 450 123 43 43
Interest cost 318 137 235 137 60 53
Plan participants’ contributions - 3 - 3 62 43
Plan amendments 40 38 - - 18 -
Actuarial (gain) loss (2,753) (1,559) (325) (364) (509) (108)
Foreign currency exchange rate changes - (423) - (85) (5) (3)
Benefits paid (1,290) (276) (2,560) (746) (220) (189)
Divestitures/Acquisitions - - - - - -
Curtailment - - - (24) - -
Benefit obligation at December 31 9,713 3,354 12,966 5,351 1,938 2,489
Change in Plan Assets
Fair value of plan assets at January 1 9,919 4,950 9,930 5,363 - -
Actual return on plan assets (1,851) (1,096) 997 166 - -
Foreign currency exchange rate changes - (453) - (35) - -
Employer contributions 1,164 158 1,552 199 158 146
Plan participants’ contributions - 3 - 3 62 43
Benefits paid (1,290) (276) (2,560) (746) (220) (189)
Fair value of plan assets at December 31 7,942 3,286 9,919 4,950 - -
Funded status at December 31 $ (1,771) $ (68) $ (3,047) $ (401) $ (1,938) $ (2,489)
Amounts recognized on the Consolidated Balance Sheet for the company’s pension and OPEB plans at December 31, 2022 and 2021, include:
Pension Benefits
2022 2021 Other Benefits
U.S. Int’l. U.S. Int’l. 2022 2021
Deferred charges and other assets $ 26 $ 759 $ 36 $ 696 $ - $ -
Accrued liabilities (210) (62) (303) (142) (152) (151)
Noncurrent employee benefit plans (1,587) (765) (2,780) (955) (1,786) (2,338)
Net amount recognized at December 31 $ (1,771) $ (68) $ (3,047) $ (401) $ (1,938) $ (2,489)
For the year ended December 31, 2022, the decrease in benefit obligations was primarily due to actuarial gains caused by higher discount rates used to value the obligations and benefit payments paid to retirees in 2022. For the year ended December 31, 2021, the decrease in benefit obligations was primarily due to actuarial gains caused by higher discount rates used to value the obligations and large benefit payments paid to retirees in 2021.
Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $3,446 and $4,979 at the end of 2022 and 2021, respectively. These amounts consisted of:
Pension Benefits
2022 2021 Other Benefits
U.S. Int’l. U.S. Int’l. 2022 2021
Net actuarial loss $ 3,147 $ 659 $ 4,007 $ 920 $ (392) $ 134
Prior service (credit) costs 40 107 2 75 (115) (159)
Total recognized at December 31 $ 3,187 $ 766 $ 4,009 $ 995 $ (507) $ (25)
The accumulated benefit obligations for all U.S. and international pension plans were $8,595 and $3,084, respectively, at December 31, 2022, and $11,337 and $4,976, respectively, at December 31, 2021.
Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2022 and 2021, was:
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
Pension Benefits
2022 2021
U.S. Int’l. U.S. Int’l.
Projected benefit obligations $ 1,322 $ 828 $ 1,957 $ 1,097
Accumulated benefit obligations 1,135 671 1,665 883
Fair value of plan assets - 3 55 2
The components of net periodic benefit cost and amounts recognized in the Consolidated Statement of Comprehensive Income for 2022, 2021 and 2020 are shown in the table below:
Pension Benefits
2022 2021 2020 Other Benefits
U.S. Int’l. U.S. Int’l. U.S. Int’l. 2022 2021 2020
Net Periodic Benefit Cost
Service cost $ 432 $ 83 $ 450 $ 123 $ 497 $ 130 $ 43 $ 43 $ 38
Interest cost 318 137 235 137 353 175 60 53 71
Expected return on plan assets (624) (176) (596) (171) (650) (209) - - -
Amortization of prior service costs (credits) 2 6 2 8 2 10 (27) (27) (28)
Recognized actuarial losses 218 15 309 46 385 45 13 16 3
Settlement losses 363 (6) 672 7 620 37 - - -
Curtailment losses (gains) - (5) - (1) 92 2 - - (27)
Total net periodic benefit cost 709 54 1,072 149 1,299 190 89 85 57
Changes Recognized in Comprehensive Income
Net actuarial (gain) loss during period (279) (257) (725) (408) 1,584 230 (514) (111) 190
Amortization of actuarial loss (581) (5) (981) (73) (1,005) (98) (13) (15) (4)
Prior service (credits) costs during period 40 38 - - - - 18 - -
Amortization of prior service (costs) credits (2) (6) (2) (11) (2) (17) 27 27 42
Total changes recognized in other
comprehensive income
(822) (230) (1,708) (492) 577 115 (482) (99) 228
Recognized in Net Periodic Benefit Cost and Other Comprehensive Income
$ (113) $ (176) $ (636) $ (343) $ 1,876 $ 305 $ (393) $ (14) $ 285
Assumptions The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31:
Pension Benefits
2022 2021 2020 Other Benefits
U.S. Int’l. U.S. Int’l. U.S. Int’l. 2022 2021 2020
Assumptions used to determine benefit obligations:
Discount rate 5.2 % 5.8 % 2.8 % 2.8 % 2.4 % 2.4 % 5.3 % 2.9 % 2.6 %
Rate of compensation increase 4.5 % 4.2 % 4.5 % 4.1 % 4.5 % 4.0 % N/A N/A N/A
Assumptions used to determine net periodic benefit cost:
Discount rate for service cost 3.6 % 2.8 % 3.0 % 2.4 % 3.3 % 3.2 % 3.1 % 3.0 % 3.5 %
Discount rate for interest cost 2.8 % 2.8 % 1.9 % 2.4 % 2.6 % 3.2 % 2.4 % 2.1 % 3.0 %
Expected return on plan assets 6.6 % 3.9 % 6.5 % 3.5 % 6.5 % 4.5 % N/A N/A N/A
Rate of compensation increase 4.5 % 4.1 % 4.5 % 4.0 % 4.5 % 4.0 % N/A N/A N/A
Expected Return on Plan Assets The company’s estimated long-term rates of return on pension assets are driven primarily by actual historical asset-class returns, an assessment of expected future performance, advice from external actuarial firms and the incorporation of specific asset-class risk factors. Asset allocations are periodically updated using pension plan asset/liability studies, and the company’s estimated long-term rates of return are consistent with these studies. For 2022, the company used an expected long-term rate of return of 6.6 percent for U.S. pension plan assets, which account for 67 percent of the company’s pension plan assets.
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.
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
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 5.2 percent, 2.8 percent, and 2.4 percent for 2022, 2021, and 2020, respectively, for both the main U.S. pension and OPEB plans.
Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2022, for the main U.S. OPEB plan, the assumed health care cost-trend rates start with 6.6 percent in 2023 and gradually decline to 4.5 percent for 2032 and beyond. For this measurement at December 31, 2021, the assumed health care cost-trend rates started with 6.2 percent in 2022 and gradually declined to 4.5 percent for 2031 and beyond.
Plan Assets and Investment Strategy
The fair value measurements of the company’s pension plans for 2022 and 2021 are as follows:
U.S. Int’l.
Total Level 1 Level 2 Level 3 NAV Total Level 1 Level 2 Level 3 NAV
At December 31, 2021
Equities
U.S.1
$ 1,677 $ 1,677 $ - $ - $ - $ 491 $ 491 $ - $ - $ -
International 1,285 1,284 - 1 - 356 355 - 1 -
Collective Trusts/Mutual Funds2
2,541 32 - - 2,509 134 6 - - 128
Fixed Income
Government 215 - 215 - - 229 135 94 - -
Corporate 660 - 660 - - 532 2 530 - -
Bank Loans 137 - 136 1 - - - - - -
Mortgage/Asset Backed 1 - 1 - - 4 - 4 - -
Collective Trusts/Mutual Funds2
1,907 13 - - 1,894 2,388 1 - - 2,387
Mixed Funds3
- - - - - 99 12 87 - -
Real Estate4
1,172 - - - 1,172 312 - - 42 270
Alternative Investments - - - - - - - - - -
Cash and Cash Equivalents 264 263 1 - - 161 89 3 - 69
Other5
60 (1) 14 46 1 244 - 17 113 114
Total at December 31, 2021 $ 9,919 $ 3,268 $ 1,027 $ 48 $ 5,576 $ 4,950 $ 1,091 $ 735 $ 156 $ 2,968
At December 31, 2022
Equities
U.S.1
$ 1,358 $ 1,358 $ - $ - $ - $ 164 $ 164 $ - $ - $ -
International 946 946 - - - 120 120 - - -
Collective Trusts/Mutual Funds2
1,695 4 - - 1,691 87 6 - - 81
Fixed Income
Government 110 - 110 - - 185 127 58 - -
Corporate 680 - 680 - - 343 15 328 - -
Bank Loans 45 - 45 - - - - - - -
Mortgage/Asset Backed 1 - 1 - - 4 - 4 - -
Collective Trusts/Mutual Funds2
1,616 - - - 1,616 1,750 - - - 1,750
Mixed Funds3
- - - - - 87 14 73 - -
Real Estate4
1,184 - - - 1,184 198 - - 38 160
Alternative Investments - - - - - - - - - -
Cash and Cash Equivalents 200 25 - - 175 80 69 2 - 9
Other5
107 37 15 54 1 268 - 18 85 165
Total at December 31, 2022 $ 7,942 $ 2,370 $ 851 $ 54 $ 4,667 $ 3,286 $ 515 $ 483 $ 123 $ 2,165
1U.S. equities include investments in the company’s common stock in the amount of $0 at December 31, 2022, and $0 at December 31, 2021.
2Collective Trusts/Mutual Funds for U.S. plans are entirely index funds; for International plans, they are mostly unit trust and index funds.
3Mixed funds are composed of funds that invest in both equity and fixed-income instruments in order to diversify and lower risk.
4The year-end valuations of the U.S. real estate assets are based on third-party appraisals that occur at least once a year for each property in the portfolio.
5The “Other” asset class includes net payables for securities purchased but not yet settled (Level 1); dividends and interest- and tax-related receivables (Level 2); insurance contracts (Level 3); and investments in private-equity limited partnerships (NAV).
Notes to the Consolidated Financial Statements
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 Fixed Income
International Corporate Bank Loans Real Estate Other Total
Total at December 31, 2020 $ 1 $ - $ 2 $ 45 $ 45 $ 93
Actual Return on Plan Assets:
Assets held at the reporting date - - - - 4 4
Assets sold during the period - - - (3) - (3)
Purchases, Sales and Settlements - - (2) - 4 2
Transfers in and/or out of Level 3 - - - - 108 108
Total at December 31, 2021 $ 1 $ - $ - $ 42 $ 161 $ 204
Actual Return on Plan Assets:
Assets held at the reporting date (1) - - - (18) (19)
Assets sold during the period - - - (4) - (4)
Purchases, Sales and Settlements - - - - (4) (4)
Transfers in and/or out of Level 3 - - - - - -
Total at December 31, 2022 $ - $ - $ - $ 38 $ 139 $ 177
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 94 percent of the total pension assets. Both the U.S. and U.K. plans have an Investment Committee that regularly meets during the year to review the asset holdings and their returns. To assess the plans’ investment performance, long-term asset allocation policy benchmarks have been established.
For the primary U.S. pension plan, the company’s Investment Committee has established the following approved asset allocation ranges: Equities 35-65 percent, Fixed Income 25-45 percent, Real Estate 5-25 percent, Alternative Investments 0-5 percent and Cash 0-15 percent. For the U.K. pension plan, the U.K. Board of Trustees has established the following asset allocation guidelines: Equities 5-15 percent, Fixed Income 35-45 percent, Real Estate 5-15 percent, and Cash 0-5 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 illiquidity 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 2022, the company contributed $1,164 and $158 to its U.S. and international pension plans, respectively. In 2023, the company expects contributions to be approximately $1,000 to its U.S. plans and $100 to its international pension plans. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments, tax law changes and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.
The company anticipates paying OPEB benefits of approximately $150 in 2023; $158 was paid in 2022.
The following benefit payments, which include estimated future service, are expected to be paid by the company in the next 10 years:
Pension Benefits Other
U.S. Int’l. Benefits
2023 $ 903 $ 203 $ 152
2024 846 206 150
2025 854 214 148
2026 850 227 146
2027 840 236 145
2028-2031 4,066 1,306 708
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 $283, $252 and $281 in 2022, 2021 and 2020, respectively.
Notes to the Consolidated Financial Statements
Financial Table of Contents
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 2022, 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.
Prior to its acquisition by Chevron, Unocal established various grantor trusts to fund obligations under some of its benefit plans, including the deferred compensation and supplemental retirement plans. At December 31, 2022 and 2021, trust assets of $35 and $36, respectively, were invested primarily in interest-earning accounts.
Employee Incentive Plans The Chevron Incentive Plan is an annual cash bonus plan for eligible employees that links awards to corporate, business unit and individual performance in the prior year. Charges to expense for cash bonuses were $1,169, $1,165 and $462 in 2022, 2021 and 2020, respectively. Chevron also has the LTIP for officers and other regular salaried employees of the company and its subsidiaries who hold positions of significant responsibility. Awards under the LTIP consist of stock options and other share-based compensation that are described in Note 22 Stock Options and Other Share-Based Compensation.
Note 24
Other Contingencies and Commitments
Income Taxes The company calculates its income tax expense and liabilities quarterly. These liabilities generally are subject to audit and are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been calculated. Refer to Note 17 Taxes for a discussion of the periods for which tax returns have been audited for the company’s major tax jurisdictions and a discussion for all tax jurisdictions of the differences between the amount of tax benefits recognized in the financial statements and the amount taken or expected to be taken in a tax return.
Settlement of open tax years, as well as other tax issues in countries where the company conducts its businesses, are not expected to have a material effect on the consolidated financial position or liquidity of the company and, in the opinion of management, adequate provisions have been made for all years under examination or subject to future examination.
Guarantees The company has one guarantee to an equity affiliate totaling $175. This guarantee is associated with certain payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 5-year remaining term of this guarantee, the maximum guarantee amount will be reduced as certain fees are paid by the affiliate. There are numerous cross-indemnity agreements with the affiliate and the other partners to permit recovery of amounts paid under the guarantee. Chevron has recorded no liability for this guarantee.
Indemnifications The company often includes standard indemnification provisions in its arrangements with its partners, suppliers and vendors in the ordinary course of business, the terms of which range in duration and sometimes are not limited. The company may be obligated to indemnify such parties for losses or claims suffered or incurred in connection with its service or other claims made against such parties.
Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain contingent liabilities with respect to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which may relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate amounts of required payments under throughput and take-or-pay agreements are: 2023 - $897; 2024 - $959; 2025 - $941; 2026 - $1,002; 2027 - $1,053 ; after 2027 - $6,489. The aggregate amount of required payments for other unconditional purchase obligations are: 2023 - $349; 2024 - $425; 2025 - $322; 2026 - $358; 2027 - $311; after 2027 - $1,233. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were $1,866 in 2022, $861 in 2021 and $514 in 2020.
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,
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
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 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, 2022, was $868. Included in this balance was $218 related to remediation activities at approximately 143 sites for which the company had been identified as a potentially responsible party under the provisions of the U.S. federal Superfund law or analogous state laws 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 2022 environmental reserves balance of $650, $384 is related to the company’s U.S. downstream operations, $44 to its international downstream operations, and $222 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 2022 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.
Other Contingencies Chevron receives claims from and submits claims to customers; trading partners; joint venture partners; U.S. federal, state and local regulatory bodies; governments; contractors; insurers; suppliers; and individuals. The amounts of these claims, individually and in the aggregate, may be significant and take lengthy periods to resolve, and may result in gains or losses in future periods.
The company and its affiliates also continue to review and analyze their operations and may close, retire, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve competitiveness and profitability. These activities, individually or together, may result in significant gains or losses in future periods.
Note 25
Asset Retirement Obligations
The company records the fair value of a liability for an asset retirement obligation (ARO) both as an asset and a liability when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. The legal obligation to perform the asset retirement activity is unconditional, even though uncertainty may exist about the timing and/or method of settlement that may be beyond the company’s control. This uncertainty about the timing and/or method of settlement is factored into the measurement of the liability when sufficient information exists to reasonably estimate fair value. Recognition of the ARO includes: (1) the present value of a liability and offsetting asset, (2) the subsequent accretion of that liability and depreciation of the asset, and (3) the periodic review of the ARO liability estimates and discount rates.
AROs are primarily recorded for the company’s crude oil and natural gas producing assets. No significant AROs associated with any legal obligations to retire downstream long-lived assets have been recognized, as indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the associated ARO. The company performs periodic 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
Financial Table of Contents
Millions of dollars, except per-share amounts
The following table indicates the changes to the company’s before-tax asset retirement obligations in 2022, 2021 and 2020:
2022 2021 2020
Balance at January 1 $ 12,808 $ 13,616 $ 12,832
Liabilities assumed in the Noble acquisition - - 630
Liabilities incurred 9 31 10
Liabilities settled (1,281) (1,887) (1,661)
Accretion expense 560 616 560
Revisions in estimated cash flows 605 432 1,245
Balance at December 31 $ 12,701 $ 12,808 $ 13,616
In the table above, the amount associated with “Revisions in estimated cash flows” in 2021 primarily reflects increased cost estimates and scope changes to decommission wells, equipment and facilities. The long-term portion of the $12,701 balance at the end of 2022 was $11,419.
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, net” on the Consolidated Balance Sheet, net of the allowance for doubtful accounts. The net balance of these receivables was $14,219 and $12,877 at December 31, 2022 and 2021, respectively. Other items included in “Accounts and notes receivable, net” 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 2022 included after-tax gains of approximately $390 relating to the sale of certain properties. Of this amount, approximately $90 and $300 related to downstream and upstream, respectively. Earnings in 2021 included after-tax gains of approximately $785 relating to the sale of certain properties, of which approximately $30 and $755 related to downstream and upstream assets, respectively. Earnings in 2020 included after-tax gains of approximately $765 relating to the sale of certain properties, of which approximately $30 and $735 related to downstream and upstream assets, respectively.
Earnings in 2022 included after-tax charges of approximately $1,075 for impairments and other asset write-offs and $600 for an early contract termination in upstream, and $271 for pension settlement costs. Earnings in 2021 included after-tax charges of approximately $519 for pension settlement costs, $260 for early retirement of debt, $120 relating to upstream remediation and $110 relating to downstream legal reserves. Earnings in 2020 included after-tax charges of approximately $4,800 for impairments and other asset write-offs related to 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
2022 2021 2020
Total financing interest and debt costs $ 630 $ 775 $ 735
Less: Capitalized interest 114 63 38
Interest and debt expense $ 516 $ 712 $ 697
Research and development expenses $ 268 $ 268 $ 435
Excess of replacement cost over the carrying value of inventories (LIFO method)
$ 9,061 $ 5,588 $ 2,749
LIFO profits (losses) on inventory drawdowns included in earnings $ 122 $ 35 $ (147)
Foreign currency effects*
$ 669 $ 306 $ (645)
* Includes $253, $180 and $(152) in 2022, 2021 and 2020, respectively, for the company’s share of equity affiliates’ foreign currency effects.
The company has $4,722 in goodwill on the Consolidated Balance Sheet, of which $4,370 is in the upstream segment primarily related to the 2005 acquisition of Unocal and $352 is in the downstream segment. The company tested this goodwill for impairment during 2022, and no impairment was required.
Note 28
Financial Instruments - Credit Losses
Chevron’s expected credit loss allowance balance was $1.0 billion as of December 31, 2022 and $745 million as of December 31, 2021, 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 $18.2 billion as of December 31, 2022, 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 $4.3 billion as of December 31, 2022, 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 $560 million are included within “Investments and Advances” on the Consolidated Balance Sheet at both December 31, 2022 and December 31, 2021.
Note 29
Acquisition of Renewable Energy Group, Inc.
On June 13, 2022, the company acquired Renewable Energy Group, Inc. (REG), an independent company focused on converting natural fats, oils and greases into advanced biofuels. REG utilizes a global integrated production, procurement, distribution and logistics network to operate 11 biorefineries in the U.S. and Europe. Ten biorefineries produce biodiesel and one produces renewable diesel. The acquisition combines REG’s growing renewable fuels production and leading feedstock capabilities with Chevron’s large manufacturing, distribution and commercial marketing position.
Chevron acquired outstanding shares of REG in an all-cash transaction valued at $3.15 billion, or $61.50 per share. As part of the transaction, the company recognized long-term debt and finance leases with a fair value of $590 million.
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 values. 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 acquisition date, as information necessary to complete the analysis is obtained. Tangible and intangible assets were valued using a combination of replacement cost approach and discounted cash flows that incorporated internally generated price assumptions and production profiles together with appropriate operating and capital cost assumptions. Debt assumed in the
Notes to the Consolidated Financial Statements
Financial Table of Contents
Millions of dollars, except per-share amounts
acquisition was valued based on observable market prices for REG’s debt. As a result of measuring the assets acquired and the liabilities assumed at fair value, the company recognized $293 million of goodwill.
The following table summarizes the values assigned to assets acquired and liabilities assumed:
At June 13, 2022
(Millions of dollars)
Current assets $ 1,584
Properties, plant and equipment
1,778
Deferred tax 92
Other assets 374
Total assets acquired 3,828
Current liabilities 301
Long-term debt and finance leases 590
Other liabilities 75
Total liabilities assumed 966
Net assets acquired $ 2,862
Goodwill 293
Purchase Price $ 3,155
Pro forma financial information is not disclosed as the acquisition was deemed not to have a material impact on the company’s results of operations.
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 estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to
Table I - Costs Incurred in Exploration, Property Acquisitions and Development1
Consolidated Companies Affiliated Companies
Other
Millions of dollars U.S. Americas Africa Asia Australia Europe Total TCO Other
Year Ended December 31, 2022
Exploration
Wells $ 239 $ 84 $ 78 $ 34 $ 4 $ - $ 439 $ - $ -
Geological and geophysical 98 28 110 - 1 - 237 - -
Other 53 72 75 30 27 2 259 - -
Total exploration 390 184 263 64 32 2 935 - -
Property acquisitions2
Proved - Other 18 - 63 13 - - 94 - -
Unproved - Other 104 78 73 - - - 255 - -
Total property acquisitions 122 78 136 13 - - 349 - -
Development3
6,221 863 21 649 719 35 8,508 2,429 34
Total Costs Incurred4
$ 6,733 $ 1,125 $ 420 $ 726 $ 751 $ 37 $ 9,792 $ 2,429 $ 34
Year Ended December 31, 2021
Exploration
Wells $ 184 $ 31 $ 5 $ 36 $ - $ - $ 256 $ - $ -
Geological and geophysical 67 58 40 - 22 - 187 - -
Other 80 80 39 14 25 1 239 - -
Total exploration 331 169 84 50 47 1 682 - -
Property acquisitions2
Proved - Other 98 - 15 53 - - 166 - -
Unproved - Other 13 16 - - - - 29 - -
Total property acquisitions 111 16 15 53 - - 195 - -
Development3
4,360 640 383 545 526 44 6,498 2,442 27
Total Costs Incurred4
$ 4,802 $ 825 $ 482 $ 648 $ 573 $ 45 $ 7,375 $ 2,442 $ 27
Year Ended December 31, 2020
Exploration
Wells $ 190 $ 181 $ 1 $ 8 $ 1 $ - $ 381 $ - $ -
Geological and geophysical 83 29 58 3 12 - 185 - -
Other 125 77 42 22 39 2 307 - -
Total exploration 398 287 101 33 52 2 873 - -
Property acquisitions2
Proved - Noble 3,463 - 438 7,945 - - 11,846 - -
Proved - Other 23 - 2 56 - - 81 - -
Unproved - Noble 2,845 2 113 129 - - 3,089 - -
Unproved - Other 35 - 10 - - - 45 - -
Total property acquisitions 6,366 2 563 8,130 - - 15,061 - -
Development3
4,622 740 386 1,034 753 37 7,572 2,998 81
Total Costs Incurred4
$ 11,386 $ 1,029 $ 1,050 $ 9,197 $ 805 $ 39 $ 23,506 $ 2,998 $ 81
1 Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. Includes capitalized amounts related to asset retirement obligations. See Note 25 Asset Retirement Obligations.
2 Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired in nonmonetary transactions.
3 Includes $186, $298 and $897 of costs incurred on major capital projects prior to assignment of proved reserves for consolidated companies in 2022, 2021, and 2020, respectively.
4 Reconciliation of consolidated companies total cost incurred to Upstream Capex - $ billions:
2022 2021 2020
Total cost incurred by Consolidated Companies $ 9.8 $ 7.4 $ 23.5
Noble acquisition - - (14.9)
Expensed exploration costs (0.5) (0.4) (0.5) (Geological and geophysical and other exploration costs)
Non-oil and gas activities 0.6 0.2 - (Primarily LNG and transportation activities)
ARO reduction/(build) (0.3) (0.4) (0.8)
Upstream Capex $ 9.6 $ 6.8 $ 7.5 Reference page 46 Upstream Capex
Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents
proved reserves, and changes in estimated discounted future net cash flows. The amounts for consolidated companies are organized by geographic areas including the United States, Other Americas, Africa, Asia, Australia/Oceania and Europe. Amounts for affiliated companies include Chevron’s equity interests in Tengizchevroil (TCO) in the Republic of Kazakhstan and in other affiliates, principally in Venezuela and Angola. Refer to Note 15 Investments and Advances for a discussion of the company’s major equity affiliates.
Table II - Capitalized Costs Related to Oil and Gas Producing Activities
Consolidated Companies Affiliated Companies
Other
Millions of dollars U.S. Americas Africa Asia Australia Europe Total TCO Other
At December 31, 2022
Unproved properties $ 2,541 $ 2,176 $ 265 $ 970 $ 1,987 $ - $ 7,939 $ 108 $ -
Proved properties and
related producing assets
83,525 22,867 46,950 31,179 22,926 2,186 209,633 15,793 1,552
Support equipment 2,146 194 1,543 696 19,107 - 23,686 646 -
Deferred exploratory wells 43 56 116 40 1,119 74 1,448 - -
Other uncompleted projects 8,213 610 1,095 914 1,869 30 12,731 20,590 54
Gross Capitalized Costs 96,468 25,903 49,969 33,799 47,008 2,290 255,437 37,137 1,606
Unproved properties valuation 178 1,589 146 969 110 - 2,992 74 -
Proved producing properties - Depreciation and depletion
58,253 12,974 38,543 19,051 10,689 720 140,230 9,441 654
Support equipment depreciation 1,302 155 1,166 500 4,644 - 7,767 424 -
Accumulated provisions 59,733 14,718 39,855 20,520 15,443 720 150,989 9,939 654
Net Capitalized Costs $ 36,735 $ 11,185 $ 10,114 $ 13,279 $ 31,565 $ 1,570 $ 104,448 $ 27,198 $ 952
At December 31, 2021
Unproved properties $ 3,302 $ 2,382 $ 191 $ 982 $ 1,987 $ - $ 8,844 $ 108 $ -
Proved properties and
related producing assets
80,821 22,031 47,030 46,379 22,235 2,156 220,652 14,635 1,558
Support equipment 2,134 198 1,096 906 18,918 - 23,252 582 -
Deferred exploratory wells 328 121 196 246 1,144 74 2,109 - -
Other uncompleted projects 6,581 431 1,096 903 1,586 24 10,621 19,382 31
Gross Capitalized Costs 93,166 25,163 49,609 49,416 45,870 2,254 265,478 34,707 1,589
Unproved properties valuation 289 1,536 131 855 110 - 2,921 70 -
Proved producing properties - Depreciation and depletion
55,064 11,745 37,657 33,300 8,920 602 147,288 8,461 514
Support equipment depreciation 1,681 155 778 623 3,724 - 6,961 362 -
Accumulated provisions 57,034 13,436 38,566 34,778 12,754 602 157,170 8,893 514
Net Capitalized Costs $ 36,132 $ 11,727 $ 11,043 $ 14,638 $ 33,116 $ 1,652 $ 108,308 $ 25,814 $ 1,075
At December 31, 2020
Unproved properties $ 3,519 $ 2,438 $ 188 $ 984 $ 1,987 $ - $ 9,116 $ 108 $ -
Proved properties and
related producing assets
81,573 24,108 46,637 58,086 22,321 2,117 234,842 11,326 1,548
Support equipment 1,882 197 1,087 2,042 18,898 - 24,106 2,023 -
Deferred exploratory wells 411 142 202 505 1,144 108 2,512 - -
Other uncompleted projects 5,549 582 1,030 803 1,157 20 9,141 18,806 23
Gross Capitalized Costs 92,934 27,467 49,144 62,420 45,507 2,245 279,717 32,263 1,571
Unproved properties valuation 179 1,471 126 856 110 - 2,742 67 -
Proved producing properties - Depreciation and depletion
55,839 13,141 35,899 42,354 7,541 498 155,272 6,746 493
Support equipment depreciation 1,002 159 742 1,644 2,965 - 6,512 1,169 -
Accumulated provisions 57,020 14,771 36,767 44,854 10,616 498 164,526 7,982 493
Net Capitalized Costs $ 35,914 $ 12,696 $ 12,377 $ 17,566 $ 34,891 $ 1,747 $ 115,191 $ 24,281 $ 1,078
Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents
Table III - Results of Operations for Oil and Gas Producing Activities1
The company’s results of operations from oil and gas producing activities for the years 2022, 2021 and 2020 are shown in the following table. Net income (loss) from exploration and production activities as reported on page 76 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 76.
Consolidated Companies Affiliated Companies
Other
Millions of dollars U.S. Americas Africa Asia Australia Europe Total TCO Other
Year Ended December 31, 2022
Revenues from net production
Sales $ 9,656 $ 1,172 $ 2,192 $ 3,963 $ 7,302 $ 564 $ 24,849 $ 8,304 $ 2,080
Transfers 18,494 3,801 6,829 2,477 7,535 - 39,136 - -
Total 28,150 4,973 9,021 6,440 14,837 564 63,985 8,304 2,080
Production expenses excluding taxes (4,752) (1,071) (1,515) (1,316) (614) (60) (9,328) (485) (47)
Taxes other than on income (1,286) (85) (170) (52) (352) (4) (1,949) (933) -
Proved producing properties:
Depreciation and depletion (4,612) (1,223) (1,943) (1,765) (2,520) (117) (12,180) (964) (164)
Accretion expense2
(167) (22) (147) (87) (77) (11) (511) (6) (3)
Exploration expenses (402) (169) (243) (92) (52) (2) (960) - -
Unproved properties valuation (38) (250) (15) (124) - - (427) - -
Other income (expense)3
92 21 300 180 51 105 749 195 (27)
Results before income taxes 16,985 2,174 5,288 3,184 11,273 475 39,379 6,111 1,839
Income tax (expense) benefit (3,736) (670) (3,114) (1,742) (3,185) (193) (12,640) (1,835) 12
Results of Producing Operations $ 13,249 $ 1,504 $ 2,174 $ 1,442 $ 8,088 $ 282 $ 26,739 $ 4,276 $ 1,851
Year Ended December 31, 2021
Revenues from net production
Sales $ 6,708 $ 888 $ 1,283 $ 5,127 $ 3,725 $ 371 $ 18,102 $ 5,564 $ 868
Transfers 12,653 3,029 5,232 3,019 3,858 - 27,791 - -
Total 19,361 3,917 6,515 8,146 7,583 371 45,893 5,564 868
Production expenses excluding taxes (4,325) (974) (1,414) (2,156) (548) (67) (9,484) (487) (20)
Taxes other than on income (928) (73) (88) (15) (260) (4) (1,368) (359) -
Proved producing properties:
Depreciation and depletion (5,184) (1,470) (1,797) (3,324) (2,409) (105) (14,289) (947) (215)
Accretion expense2
(197) (22) (144) (113) (75) (13) (564) (7) (3)
Exploration expenses (221) (132) (83) (20) (47) (35) (538) - -
Unproved properties valuation (43) (95) (5) - - - (143) - -
Other income (expense)3
990 (33) (72) (124) 26 2 789 98 (332)
Results before income taxes 9,453 1,118 2,912 2,394 4,270 149 20,296 3,862 298
Income tax (expense) benefit (2,108) (318) (1,239) (1,326) (1,314) (38) (6,343) (1,161) 29
Results of Producing Operations $ 7,345 $ 800 $ 1,673 $ 1,068 $ 2,956 $ 111 $ 13,953 $ 2,701 $ 327
1The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
2Represents accretion of ARO liability. Refer to Note 25 Asset Retirement Obligations.
3Includes 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 Activities1, continued
Consolidated Companies Affiliated Companies
Other
Millions of dollars U.S. Americas Africa Asia Australia Europe Total TCO Other
Year Ended December 31, 2020
Revenues from net production
Sales $ 1,665 $ 505 $ 473 $ 5,629 $ 3,010 $ 149 $ 11,431 $ 3,088 $ 288
Transfers 7,711 1,683 3,378 1,092 1,830 - 15,694 - -
Total 9,376 2,188 3,851 6,721 4,840 149 27,125 3,088 288
Production expenses excluding taxes (3,933) (981) (1,485) (2,408) (589) (64) (9,460) (419) (98)
Taxes other than on income (597) (62) (77) (11) (121) (2) (870) (190) (30)
Proved producing properties:
Depreciation and depletion (6,482) (1,221) (2,323) (3,466) (2,192) (92) (15,776) (879) (146)
Accretion expense2
(165) (22) (136) (120) (62) (10) (515) (9) (6)
Exploration expenses (457) (314) (431) (67) (231) (15) (1,515) - 1
Unproved properties valuation (58) (215) (6) (8) (1) - (288) - -
Other income (expense)3
51 (8) (11) 1,053 (2) (9) 1,074 (29) (2,103)
Results before income taxes (2,265) (635) (618) 1,694 1,642 (43) (225) 1,562 (2,094)
Income tax (expense) benefit 558 (5) 888 (353) (558) 12 542 (471) 161
Results of Producing Operations $ (1,707) $ (640) $ 270 $ 1,341 $ 1,084 $ (31) $ 317 $ 1,091 $ (1,933)
1The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
2Represents accretion of ARO liability. Refer to Note 25 Asset Retirement Obligations.
3Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses.
Table IV - Results of Operations for Oil and Gas Producing Activities - Unit Prices and Costs1
Consolidated Companies Affiliated Companies
Other
U.S. Americas Africa Asia Australia Europe Total TCO Other
Year Ended December 31, 2022
Average sales prices
Crude, per barrel $ 91.88 $ 90.04 $ 100.82 $ 85.64 $ 98.00 $ 102.00 $ 92.92 $ 85.71 $ -
Natural gas liquids, per barrel 33.76 34.33 35.43 - - - 34.31 20.83 65.33
Natural gas, per thousand cubic feet 5.53 5.15 9.00 4.02 15.34 27.00 8.85 0.95 29.44
Average production costs, per barrel2
11.10 17.00 14.43 8.49 3.79 12.00 10.16 3.85 3.36
Year Ended December 31, 2021
Average sales prices
Crude, per barrel $ 65.16 $ 62.84 $ 72.38 $ 63.71 $ 71.40 $ 69.20 $ 66.14 $ 58.31 $ -
Natural gas liquids, per barrel 28.54 26.33 39.40 - 30.00 - 29.10 27.13 66.00
Natural gas, per thousand cubic feet 3.02 3.39 2.66 4.10 8.22 12.50 5.08 0.47 9.71
Average production costs, per barrel2
10.45 13.91 12.40 10.52 3.65 13.40 9.90 4.09 1.25
Year Ended December 31, 2020
Average sales prices3
Crude, per barrel $ 36.28 $ 35.80 $ 38.89 $ 39.77 $ 37.82 $ 34.20 $ 37.41 $ 25.39 $ 25.22
Natural gas liquids, per barrel 9.97 11.79 20.51 - 40.97 - 11.11 10.58 22.52
Natural gas, per thousand cubic feet 0.96 2.20 1.61 4.30 5.42 1.07 3.68 0.54 0.61
Average production costs, per barrel2
10.01 14.27 13.19 11.24 4.02 13.23 10.07 3.17 3.91
1The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
2Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel.
32020 unit prices have been conformed to current presentation. Crude and NGL realizations were previously combined and disclosed as liquids.
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Table V Proved Reserve Quantity Information*
Summary of Net Oil and Gas Reserves
2022 2021 2020
Liquids in Millions of Barrels
Natural Gas in Billions of Cubic Feet Crude Oil
Condensate SyntheticOil NGL Natural
Gas Crude Oil
Condensate SyntheticOil NGL Natural
Gas Crude Oil
Condensate SyntheticOil NGL Natural
Gas
Proved Developed
Consolidated Companies
U.S. 1,198 - 450 3,288 1,177 - 421 3,136 1,157 - 346 2,503
Other Americas 174 574 7 305 181 471 7 259 168 597 6 222
Africa 392 - 72 1,734 428 - 77 1,884 497 - 68 1,629
Asia 235 - - 6,578 270 - - 7,007 358 - - 7,864
Australia 99 - 3 7,898 102 - 3 8,057 115 - 4 8,951
Europe 26 - - 9 24 - - 8 23 - - 8
Total Consolidated 2,124 574 532 19,812 2,182 471 508 20,351 2,318 597 424 21,177
Affiliated Companies
TCO 515 - 52 895 555 - 52 1,059 565 - 53 1,057
Other 3 - 13 349 3 - 13 310 2 - 12 322
Total Consolidated and Affiliated Companies 2,642 574 597 21,056 2,740 471 573 21,720 2,885 597 489 22,556
Proved Undeveloped
Consolidated Companies
U.S. 875 - 435 3,543 887 - 391 2,749 593 - 247 1,747
Other Americas 121 - 10 240 107 - 8 196 92 - 2 107
Africa 62 - 25 756 52 - 28 912 57 - 36 1,208
Asia 58 - - 1,959 52 - - 466 45 - - 319
Australia 22 - - 2,444 32 - - 3,627 26 - - 2,434
Europe 32 - - 11 38 - - 13 38 - - 14
Total Consolidated 1,170 - 470 8,953 1,168 - 427 7,963 851 - 285 5,829
Affiliated Companies
TCO 611 - 21 368 695 - 32 642 985 - 49 961
Other - - - 487 1 - 6 583 1 - 5 576
Total Consolidated and Affiliated Companies 1,781 - 491 9,808 1,864 - 465 9,188 1,837 - 339 7,366
Total Proved Reserves 4,423 574 1,088 30,864 4,604 471 1,038 30,908 4,722 597 828 29,922
* Reserve quantities include natural gas projected to be consumed in operations of 2,737, 2,505 and 2,490 billions of cubic feet and equivalent synthetic oil projected to be consumed in operations of 28, 17 and 21 millions of barrels as of December 31, 2022, 2021 and 2020, 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.
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Proved reserves are estimated by company asset teams composed of earth scientists and engineers. As part of the internal control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired by the Manager of Global Reserves, an organization that is separate from the business units that estimate reserves. The Manager of Global Reserves has more than 30 years of experience working in the oil and gas industry and holds both undergraduate and graduate degrees in geoscience. His experience includes various technical and management roles in providing reserve and resource estimates in support of major capital and exploration projects, and more than 10 years of overseeing oil and gas reserves processes. He has been named a Distinguished Lecturer by the American Association of Petroleum Geologists and is an active member of the American Association of Petroleum Geologists, the SEPM Society of Sedimentary Geologists and the Society of Petroleum Engineers.
All RAC members are degreed professionals, each with more than 10 years of experience in various aspects of reserves estimation relating to reservoir engineering, petroleum engineering, earth science or finance. The members are knowledgeable in SEC guidelines for proved reserves classification and receive annual training on the preparation of reserves estimates.
The RAC has the following primary responsibilities: establish the policies and processes used within the business units to estimate reserves; provide independent reviews and oversight of the business units’ recommended reserves estimates and changes; confirm that proved reserves are recognized in accordance with SEC guidelines; determine that reserve quantities are calculated using consistent and appropriate standards, procedures and technology; and maintain the Chevron Corporation Reserves Manual, which provides standardized procedures used corporatewide for classifying and reporting hydrocarbon reserves.
During the year, the RAC is represented in meetings with each of the company’s business units to review and discuss reserve changes recommended by the various asset teams. Major changes are also reviewed with the company’s senior leadership team including the Chief Executive Officer and the Chief Financial Officer. The company’s annual reserve activity is also reviewed with the Board of Directors. If major changes to reserves were to occur between the annual reviews, those matters would also be discussed with the Board.
RAC subteams 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 2022, 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 on the following page.
Proved Undeveloped Reserves (Millions of BOE)
Quantity at January 1 3,860
Revisions 6
Improved recovery 15
Extension and discoveries 632
Purchases 61
Sales (10)
Transfers to proved developed (657)
Quantity at December 31 3,907
In 2022, revisions include an increase of 257 million BOE in Israel, due to new wells and performance revisions in the Leviathan and Tamar fields. This increase was largely offset by decreases of 145 million BOE from the United States primarily from portfolio optimizations in the Midland and Delaware basins, 69 million BOE in Kazakhstan primarily at TCO as higher prices reduced entitlement (Entitlement effects) and changes in operating assumptions reduced estimated
Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents
undeveloped reserves, and 31 million BOE in Nigeria due to lower expected offtake of natural gas relative to contracted volumes.
In 2022, extensions and discoveries of 578 million BOE in the United States were primarily due to the increase of activity and planned development of new locations in shale and tight assets in the Midland, Delaware and DJ basins. In Other Americas, 34 million BOE of extensions and discoveries were from shale and tight assets in Argentina and Canada.
The difference in 2022 extensions and discoveries of 122 million BOE, between the net quantities of proved reserves of 754 million BOE as reflected on pages 107 to 109 and net quantities of proved undeveloped reserves of 632 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 2022.
Purchases of 61 million BOE in 2022 are primarily from the acquisition of various properties in the Midland and Delaware basins in the United States.
Transfers to proved developed reserves in 2022 include 309 million BOE in the United States, primarily from the Midland, Delaware and DJ basin developments, 207 million BOE in Australia, and 141 million BOE in Kazakhstan, Angola, Canada, Argentina and other international locations. These transfers are the consequence of development expenditures on completing wells and facilities.
During 2022, investments totaling approximately $7.5 billion in oil and gas producing activities and about $0.1 billion in non-oil and gas producing activities were expended to advance the development of proved undeveloped reserves. The United States accounted for about $3.7 billion primarily related to various development activities in the Midland and Delaware basins and the Gulf of Mexico. In Asia, expenditures during the year totaled approximately $2.6 billion, primarily related to development projects for TCO in Kazakhstan. An additional $0.2 billion were spent on development activities in Australia. In Africa, about $0.5 billion was expended on various offshore development and natural gas projects in Nigeria, Angola and Republic of Congo. Development activities in Canada and other international locations were primarily responsible for about $0.5 billion of expenditures.
Reserves that remain proved undeveloped for five or more years are a result of several factors that affect optimal project development and execution. These factors may include the complex nature of the development project in adverse and remote locations, physical limitations of infrastructure or plant capacities that dictate project timing, compression projects that are pending reservoir pressure declines, and contractual limitations that dictate production levels.
At year-end 2022, the company held approximately 1.3 billion BOE of proved undeveloped reserves that have remained undeveloped for five years or more. The majority of these reserves are in locations where the company has a proven track record of developing major projects. In Australia, approximately 235 million BOE remain undeveloped for five years or more related to the Gorgon and Wheatstone Projects. Further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with operating constraints, reservoir depletion and infrastructure optimization. In Africa, approximately 167 million BOE have remained undeveloped for five years or more, primarily due to facility constraints at various fields and infrastructure associated with the Escravos gas projects in Nigeria. Affiliates account for about 776 million BOE of proved undeveloped reserves with about 726 million BOE that have remained undeveloped for five years or more. Approximately 647 million BOE are related to TCO in Kazakhstan and about 79 million BOE are related to Angola LNG. At TCO and Angola LNG, further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with reservoir depletion and facility constraints.
Annually, the company assesses whether any changes have occurred in facts or circumstances, such as changes to development plans, regulations, or government policies, that would warrant a revision to reserve estimates. In 2022, improvements in commodity prices positively impacted the economic limits of oil and gas properties, resulting in proved reserve increases, and negatively impacted proved reserves due to entitlement effects. The year-end reserves quantities have been updated for these circumstances and significant changes have been discussed in the appropriate reserves sections. Over the past three years, the ratio of proved undeveloped reserves to total proved reserves has ranged between 31 percent and 35 percent.
Proved Reserve Quantities For the three years ending December 31, 2022, the pattern of net reserve changes shown in the following tables are 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, and civil unrest.
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At December 31, 2022, proved reserves for the company were 11.2 billion BOE. The company’s estimated net proved reserves of liquids, including crude oil, condensate and synthetic oil for the years 2020, 2021 and 2022, are shown in the table on page 107. The company’s estimated net proved reserves of natural gas liquids are shown on page 108, and the company’s estimated net proved reserves of natural gas are shown on page 109.
Noteworthy changes in crude oil, condensate and synthetic oil proved reserves for 2020 through 2022 are discussed below and shown in the table on the following page:
Revisions In 2020, capital reductions and commodity price effects in the Midland and Delaware basins and Anchor in the Gulf of Mexico were primarily responsible for the 279 million barrels decrease in the United States. Reserves in Venezuela affiliates decreased by 149 million barrels, primarily due to impairments and accounting methodology change. Entitlement effects and performance revisions in TCO were primarily responsible for the 180 million barrels increase. Entitlement effects primarily contributed to an increase of 77 million barrels of synthetic oil at the Athabasca Oil Sands in Canada and 74 million barrels at multiple locations in Asia.
In 2021, the 206 million barrels increase in United States was primarily in the Gulf of Mexico and the Midland and Delaware basins. The higher commodity price environment led to the increase of 126 million barrels in the Gulf of Mexico primarily from Anchor and a 68 million barrels increase in the Midland and Delaware basins due to higher planned development activity. In TCO, entitlement effects and technical changes in field operating assumptions, reservoir model, and project schedule were primarily responsible for the 208 million barrels decrease in Kazakhstan. Entitlement effects primarily contributed to a decrease of 106 million barrels of synthetic oil at the Athabasca Oil Sands project in Canada. In the Other Americas, performance revisions and price effects, mainly in Canada and Argentina, were primarily responsible for the 41 million barrels increase.
In 2022, entitlement effects primarily contributed to a decrease of 49 million barrels of synthetic oil at the Athabasca Oil Sands project in Canada. In TCO, entitlement effects and changes in operating assumptions were primarily responsible for the 35 million barrels decrease in Kazakhstan.
Extensions and Discoveries In 2020, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 105 million barrels increase in the United States.
In 2021, extensions and discoveries in the Midland and Delaware basins, and at the Whale Project in the Gulf of Mexico, were primarily responsible for the 349 million barrels increase in the United States.
In 2022, extensions and discoveries in the Midland, Delaware and DJ basins, and approval of the Ballymore Project in the Gulf of Mexico, were primarily responsible for the 264 million barrels increase in the United States. In Other Americas, the 32 million barrels of extensions and discoveries were from Argentina and Canada.
Purchases In 2020, the acquisition of Noble assets contributed 227 million barrels in the DJ basin, Midland and Delaware basins in the United States.
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.
Sales In 2020, sales of 99 million barrels in Asia were in Azerbaijan.
In 2021, sales of 32 million barrels in the United States were in the Midland and Delaware basins.
Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents
Net Proved Reserves of Crude Oil, Condensate and Synthetic Oil
Consolidated Companies Affiliated Companies Total
Consolidated
Other Synthetic Synthetic and Affiliated
Millions of barrels U.S. Americas1
Africa Asia Australia Europe Oil 2,5
Total TCO Oil Other3
Companies
Reserves at January 1, 2020 1,928 320 613 513 166 69 540 4,149 1,473 - 159 5,781
Changes attributable to:
Revisions (279) (25) 11 74 (11) (4) 77 (157) 180 - (149) (126)
Improved recovery 1 1 - - - - - 2 - - - 2
Extensions and discoveries 105 3 1 - 1 - - 110 - - - 110
Purchases 227 - 21 10 - - - 258 - - - 258
Sales (11) - - (99) - - - (110) - - - (110)
Production (221) (39) (92) (95) (15) (4) (20) (486) (103) - (7) (596)
Reserves at December 31, 2020 4, 5
1,750 260 554 403 141 61 597 3,766 1,550 - 3 5,319
Changes attributable to:
Revisions 206 41 10 (8) 8 6 (106) 157 (208) - 2 (49)
Improved recovery - 9 - - - - - 9 - - - 9
Extensions and discoveries 349 16 - - - - - 365 - - - 365
Purchases 26 - - 2 - - - 28 - - - 28
Sales (32) - - (1) - - - (33) - - - (33)
Production (235) (38) (84) (74) (15) (5) (20) (471) (92) - (1) (564)
Reserves at December 31, 2021 4, 5
2,064 288 480 322 134 62 471 3,821 1,250 - 4 5,075
Changes attributable to:
Revisions (26) (9) 4 8 2 1 (49) (69) (35) - - (104)
Improved recovery 2 15 4 5 - - - 26 - - - 26
Extensions and discoveries 264 32 6 - - - - 302 10 - - 312
Purchases 22 5 36 - - - 168 231 - - - 231
Sales (16) - (3) - - - - (19) - - - (19)
Production (237) (36) (73) (42) (15) (5) (16) (424) (99) - (1) (524)
Reserves at December 31, 2022 4, 5
2,073 295 454 293 121 58 574 3,868 1,126 - 3 4,997
1Ending reserve balances in North America were 185, 183 and 166 and in South America were 110, 105 and 94 in 2022, 2021 and 2020, respectively.
2Reserves associated with Canada.
3Reserves associated with Africa.
4Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to page E-8 for the definition of a PSC). PSC-related reserve quantities are 6 percent, 7 percent and 9 percent for consolidated companies for 2022, 2021 and 2020, respectively.
5Reserve quantities include synthetic oil projected to be consumed in operations of 28, 17 and 21 millions of barrels as of December 31, 2022, 2021 and 2020, respectively.
Noteworthy changes in natural gas liquids proved reserves for 2020 through 2022 are discussed below and shown in the table on the following page:
Revisions In 2020, capital reductions and commodity price effects in various fields in Midland and Delaware basins were primarily responsible for the 71 million barrels decrease in the United States.
In 2021, higher commodity prices resulting in the increase of planned development activity in the Midland and Delaware basins were primarily responsible for the 107 million barrels increase in the United States.
Extensions and Discoveries In 2020, extensions and discoveries in various fields in Midland and Delaware basins were primarily responsible for the 60 million barrels increase in the United States.
In 2021, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 190 million barrels increase in the United States.
In 2022, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 163 million barrels increase in the United States.
Purchases In 2020, the acquisition of Noble assets contributed 198 million barrels primarily in the DJ basin, Midland and Delaware basins and Eagle Ford shale 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.
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Net Proved Reserves of Natural Gas Liquids
Consolidated Companies Affiliated Companies Total
Consolidated
Other and Affiliated
Millions of barrels U.S. Americas1
Africa Asia Australia Europe Total TCO Other2
Companies
Reserves at January 1, 2020 502 16 100 - 4 - 622 103 15 740
Changes attributable to:
Revisions (71) (7) (3) - - - (81) 8 5 (68)
Improved recovery - - - - - - - - - -
Extensions and discoveries 60 1 - - - - 61 - - 61
Purchases 198 - 12 - - - 210 - - 210
Sales (27) - - - - (27) - - (27)
Production (69) (2) (5) - - - (76) (9) (3) (88)
Reserves at December 31, 20203
593 8 104 - 4 - 709 102 17 828
Changes attributable to:
Revisions 107 5 8 - - - 120 (10) 4 114
Improved recovery - - - - - - - - - -
Extensions and discoveries 190 4 - - - - 194 - - 194
Purchases 8 - - - - - 8 - - 8
Sales (8) - - - - - (8) - - (8)
Production (78) (2) (6) - (1) - (87) (8) (3) (98)
Reserves at December 31, 20213
812 15 106 - 3 - 936 84 18 1,038
Changes attributable to:
Revisions 18 - (3) - - - 15 (5) (3) 7
Improved recovery - - - - - - - - - -
Extensions and discoveries 163 2 1 - - - 166 - - 166
Purchases 14 2 - - - - 16 - - 16
Sales (35) - - - - - (35) - - (35)
Production (87) (2) (7) - - - (96) (6) (2) (104)
Reserves at December 31, 20223
885 17 97 - 3 - 1,002 73 13 1,088
1Reserves associated with North America.
2Reserves associated with Africa.
3Year-end reserve quantities related to PSC are not material for 2022, 2021 and 2020, respectively.
Noteworthy changes in natural gas proved reserves for 2020 through 2022 are discussed below and shown in the table on the following page:
Revisions In 2020, the demotion of Jansz Io compression project reserves and lower field performance, partially offset by positive revisions at Gorgon, were mainly responsible for the net 2.5 TCF decrease in Australia. Capital reductions and commodity price effects in various fields of the Midland and Delaware basins were mainly responsible for the 509 BCF decrease in the United States. In Africa, a 229 BCF decrease was primarily due to reduced demand and development plan changes at Meren in Nigeria.
In 2021, the approval of the Jansz Io Compression project was mainly responsible for the 1.2 TCF increase in Australia. Higher commodity prices, resulting in the increase of planned development activity in the Midland and Delaware basins, were mainly responsible for the 829 BCF increase in the United States. In TCO, entitlement effects and technical changes in field operating assumptions, reservoir model, and project schedule were primarily responsible for the 179 BCF decrease.
In 2022, the performance of the Leviathan and Tamar fields in Israel and the Bibiyana and Jalalabad fields in Bangladesh were mainly responsible for the 1.8 TCF increase in Asia. In Australia, the 377 BCF decrease was mainly due to updated reservoir characterization of the Wheatstone field. In TCO, entitlement effects and changes in operating assumptions were primarily responsible for the 285 BCF decrease.
Extensions and Discoveries In 2020, extensions and discoveries of 385 BCF in the United States were primarily in the Midland and Delaware basins.
In 2021, extensions and discoveries of 1.4 TCF in the United States were primarily in the Midland and Delaware basins.
In 2022, extensions and discoveries of 1.6 TCF in the United States were primarily in the Midland and Delaware basins.
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Purchases In 2020, the acquisition of Noble assets contributed 5.4 TCF in Israel in Asia, 1.5 TCF in the DJ basin, Midland and Delaware basins and Eagle Ford Shale in the United States and 441 BCF in Equatorial Guinea in Africa.
Sales In 2020, sales of 1.3 TCF were primarily in the Appalachian basin in the United States and 264 BCF primarily in Azerbaijan in Asia.
In 2022, sales of 243 BCF in the United States were primarily in the Eagle Ford shale and Midland and Delaware basins.
Net Proved Reserves of Natural Gas
Consolidated Companies Affiliated Companies Total
Consolidated
Other and Affiliated
Billions of cubic feet (BCF) U.S. Americas1
Africa Asia Australia Europe Total TCO Other2
Companies
Reserves at January 1, 2020 4,728 736 2,758 3,681 14,658 26 26,587 2,004 866 29,457
Changes attributable to:
Revisions (509) (178) (229) 169 (2,455) (2) (3,204) 162 138 (2,904)
Improved recovery - - - - - - - - - -
Extensions and discoveries 385 8 2 - 58 - 453 - - 453
Purchases 1,548 - 441 5,350 - - 7,339 - - 7,339
Sales (1,314) (177) - (264) - - (1,755) - - (1,755)
Production3
(588) (60) (135) (753) (876) (2) (2,414) (148) (106) (2,668)
Reserves at December 31, 2020 4, 5
4,250 329 2,837 8,183 11,385 22 27,006 2,018 898 29,922
Changes attributable to:
Revisions 829 129 147 119 1,181 1 2,406 (179) 82 2,309
Improved recovery - - - - - - - - - -
Extensions and discoveries 1,408 63 - - 19 - 1,490 - - 1,490
Purchases 44 - - - - - 44 - - 44
Sales (29) - - - (13) - (42) - - (42)
Production3
(617) (66) (188) (829) (888) (2) (2,590) (138) (87) (2,815)
Reserves at December 31, 2021 4, 5
5,885 455 2,796 7,473 11,684 21 28,314 1,701 893 30,908
Changes attributable to:
Revisions 171 62 (118) 1,765 (377) 2 1,505 (285) 3 1,223
Improved recovery 1 - - - - - 1 - - 1
Extensions and discoveries 1,573 64 - - - - 1,637 - 17 1,654
Purchases 85 25 30 - - - 140 - - 140
Sales (243) - (11) - - - (254) - - (254)
Production3
(641) (61) (207) (701) (965) (3) (2,578) (153) (77) (2,808)
Reserves at December 31, 2022 4, 5
6,831 545 2,490 8,537 10,342 20 28,765 1,263 836 30,864
1Ending reserve balances in North America and South America were 407, 347 and 234 and 138, 108 and 95 in 2022, 2021 and 2020, respectively.
2Reserves associated with Africa.
3Total “as sold” volumes are 2,600, 2,599 and 2,447 for 2022, 2021 and 2020, respectively.
4Includes reserve quantities related to PSC. PSC-related reserve quantities are 8 percent, 8 percent and 10 percent for consolidated companies for 2022, 2021 and 2020, respectively.
5Reserve quantities include natural gas projected to be consumed in operations of 2,737, 2,505 and 2,490 billions of cubic feet as of December 31, 2022, 2021 and 2020, respectively.
Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents
Table VI - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves
The standardized measure of discounted future net cash flows is calculated in accordance with SEC and FASB requirements. This includes using the average of first-day-of-the-month oil and gas prices for the 12-month period prior to the end of the reporting period, estimated future development and production costs assuming the continuation of existing economic conditions, estimated costs for asset retirement obligations (includes costs to retire existing wells and facilities in addition to those future wells and facilities necessary to produce proved undeveloped reserves), and estimated future income taxes based on appropriate statutory tax rates. Discounted future net cash flows are calculated using 10 percent mid-period discount factors. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. The valuation requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and do not represent management’s estimate of the company’s future cash flows or value of its oil and gas reserves. In the following table, the caption “Standardized Measure Net Cash Flows” refers to the standardized measure of discounted future net cash flows.
Consolidated Companies Affiliated Companies Total
Consolidated
Other and Affiliated
Millions of dollars U.S. Americas Africa Asia Australia Europe Total TCO Other Companies
At December 31, 2022
Future cash inflows from production $ 257,478 $ 76,940 $ 55,865 $ 67,188 $ 147,839 $ 5,920 $ 611,230 $ 106,114 $ 22,630 $ 739,974
Future production costs (51,022) (22,744) (16,373) (12,261) (13,313) (1,069) (116,782) (28,046) (574) (145,402)
Future development costs (20,907) (3,233) (2,657) (2,879) (5,030) (502) (35,208) (4,127) (8) (39,343)
Future income taxes (40,096) (13,207) (26,160) (30,674) (38,861) (2,827) (151,825) (22,182) (7,707) (181,714)
Undiscounted future net cash flows 145,453 37,756 10,675 21,374 90,635 1,522 307,415 51,759 14,341 373,515
10 percent midyear annual discount for timing of estimated cash flows
(62,918) (22,165) (3,001) (10,769) (37,519) (571) (136,943) (18,810) (5,824) (161,577)
Standardized Measure
Net Cash Flows
$ 82,535 $ 15,591 $ 7,674 $ 10,605 $ 53,116 $ 951 $ 170,472 $ 32,949 $ 8,517 $ 211,938
At December 31, 2021
Future cash inflows from production $ 174,976 $ 48,328 $ 41,698 $ 52,881 $ 87,676 $ 4,366 $ 409,925 $ 80,297 $ 8,446 $ 498,668
Future production costs (40,009) (16,204) (15,204) (13,871) (13,726) (1,400) (100,414) (23,354) (285) (124,053)
Future development costs (16,709) (2,707) (2,245) (2,774) (5,283) (661) (30,379) (5,066) (18) (35,463)
Future income taxes (24,182) (7,723) (17,228) (21,064) (20,600) (922) (91,719) (15,563) (2,850) (110,132)
Undiscounted future net cash flows 94,076 21,694 7,021 15,172 48,067 1,383 187,413 36,314 5,293 229,020
10 percent midyear annual discount for timing of estimated cash flows
(41,357) (11,370) (1,899) (7,277) (21,141) (485) (83,529) (14,372) (2,244) (100,145)
Standardized Measure
Net Cash Flows
$ 52,719 $ 10,324 $ 5,122 $ 7,895 $ 26,926 $ 898 $ 103,884 $ 21,942 $ 3,049 $ 128,875
At December 31, 2020
Future cash inflows from production $ 74,671 $ 29,605 $ 27,521 $ 49,265 $ 53,241 $ 2,304 $ 236,607 $ 53,309 $ 1,070 $ 290,986
Future production costs (30,359) (15,410) (15,364) (12,784) (11,036) (1,336) (86,289) (19,525) (426) (106,240)
Future development costs (10,492) (2,366) (3,017) (2,274) (3,205) (522) (21,876) (7,138) (38) (29,052)
Future income taxes (5,874) (3,131) (6,197) (17,543) (11,700) (178) (44,623) (7,994) (212) (52,829)
Undiscounted future net cash flows 27,946 8,698 2,943 16,664 27,300 268 83,819 18,652 394 102,865
10 percent midyear annual discount for timing of estimated cash flows
(10,456) (4,652) (582) (7,856) (11,774) (56) (35,376) (8,803) (149) (44,328)
Standardized Measure
Net Cash Flows
$ 17,490 $ 4,046 $ 2,361 $ 8,808 $ 15,526 $ 212 $ 48,443 $ 9,849 $ 245 $ 58,537
Supplemental Information on Oil and Gas Producing Activities - Unaudited Financial Table of Contents
Table VII - Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves
The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs. Changes in the timing of production are included with “Revisions of previous quantity estimates.”
Total Consolidated and
Millions of dollars Consolidated Companies Affiliated Companies Affiliated Companies
Present Value at January 1, 2020 $ 80,396 $ 20,151 $ 100,547
Sales and transfers of oil and gas produced net of production costs (16,621) (2,322) (18,943)
Development costs incurred 6,301 2,892 9,193
Purchases of reserves 10,295 - 10,295
Sales of reserves (803) - (803)
Extensions, discoveries and improved recovery less related costs 2,066 - 2,066
Revisions of previous quantity estimates (1,293) 4,033 2,740
Net changes in prices, development and production costs (62,788) (22,925) (85,713)
Accretion of discount 11,274 2,948 14,222
Net change in income tax 19,616 5,317 24,933
Net Change for 2020 (31,953) (10,057) (42,010)
Present Value at December 31, 2020 $ 48,443 $ 10,094 $ 58,537
Sales and transfers of oil and gas produced net of production costs (34,668) (5,760) (40,428)
Development costs incurred 5,770 2,445 8,215
Purchases of reserves 772 - 772
Sales of reserves (889) - (889)
Extensions, discoveries and improved recovery less related costs 12,091 - 12,091
Revisions of previous quantity estimates 2,269 (6,675) (4,406)
Net changes in prices, development and production costs 89,031 30,076 119,107
Accretion of discount 6,657 1,503 8,160
Net change in income tax (25,592) (6,692) (32,284)
Net Change for 2021 55,441 14,897 70,338
Present Value at December 31, 2021 $ 103,884 $ 24,991 $ 128,875
Sales and transfers of oil and gas produced net of production costs (53,356) (9,127) (62,483)
Development costs incurred 7,962 2,430 10,392
Purchases of reserves 2,248 - 2,248
Sales of reserves (1,807) - (1,807)
Extensions, discoveries and improved recovery less related costs 16,054 823 16,877
Revisions of previous quantity estimates 5,281 (1,481) 3,800
Net changes in prices, development and production costs 110,467 28,052 138,519
Accretion of discount 14,075 3,429 17,504
Net change in income tax (34,336) (7,651) (41,987)
Net Change for 2022 66,588 16,475 83,063
Present Value at December 31, 2022 $ 170,472 $ 41,466 $ 211,938
PART IV

Item 15. Exhibits and Financial Statement Schedules
Item 15. Exhibit and Financial Statement Schedules
(a)The following documents are filed as part of this report:
(1) Financial Statements:
Page(s)
Report of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP
Consolidated Statement of Income for the three years ended December 31, 2022
Consolidated Statement of Comprehensive Income for the three years ended December 31, 2022
Consolidated Balance Sheet at December 31, 2022 and 2021
Consolidated Statement of Cash Flows for the three years ended December 31, 2022
Consolidated Statement of Equity for the three years ended December 31, 2022
Notes to the Consolidated Financial Statements
65 to 98
(2) Financial Statement Schedules:
Included below is Schedule II - Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2022.
(3) Exhibits:
The Exhibit Index on the following pages lists the exhibits that are filed as part of this report.
Schedule II - Valuation and Qualifying Accounts
Year ended December 31
Millions of Dollars 2022 2021 2020
Employee Termination Benefits
Balance at January 1 $ 43 $ 470 $ 7
Additions (reductions) charged to expense 1 (30) 859
Payments (33) (397) (396)
Balance at December 31 $ 11 $ 43 $ 470
Expected Credit Losses
Beginning allowance balance for expected credit losses $ 745 $ 671 $ 849
Current period provision 263 74 573
Write-offs charged against the allowance, if any - - (751)
Balance at December 31 $ 1,008 $ 745 $ 671
Deferred Income Tax Valuation Allowance1
Balance at January 1 $ 17,651 $ 17,762 $ 15,965
Additions to deferred income tax expense2
3,533 3,691 2,892
Reduction of deferred income tax expense (1,652) (3,802) (1,095)
Balance at December 31 $ 19,532 $ 17,651 $ 17,762
1 See also Note 17 Taxes.
2 Includes $974 of additions associated with the purchase of Noble in 2020.
Item 16. Form 10-K Summary
Not applicable.
EXHIBIT INDEX
Exhibit No.
Description
3.1 Restated Certificate of Incorporation of Chevron Corporation, dated May 30, 2008, filed as Exhibit 3.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, and incorporated herein by reference.
3.2 By-Laws of Chevron Corporation, as amended and restated December 7, 2022, filed as Exhibit 3.2 to Chevron Corporation’s Current Report on Form 8-K filed December 8, 2022, and incorporated herein by reference.
4.1 Indenture, dated as of June 15, 1995, filed as Exhibit 4.1 to Chevron Corporation’s Amendment Number 1 to Registration Statement on Form S-3 filed June 14, 1995, and incorporated herein by reference.
4.2 Indenture dated as of May 11, 2020, between Chevron Corporation and Deutsche Bank Trust Company Americas, as trustee, filed as Exhibit 4.1 to Chevron Corporation’s Current Report on Form 8-K filed May 12, 2020, and incorporated herein by reference.
4.3 Indenture dated as of August 12, 2020, among Chevron U.S.A. Inc., Chevron Corporation, as guarantor, and Deutsche Bank Trust Company Americas, as trustee, filed as Exhibit 4.1 to Chevron Corporation’s Current Report on Form 8-K filed August 13, 2020, and incorporated herein by reference.
4.4 Confidential Stockholder Voting Policy of Chevron Corporation, filed as Exhibit 4.2 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.
4.5 Description of Securities Registered under Section 12 of the Exchange Act, filed as Exhibit 4.4 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2019, and incorporated herein by reference.
10.1+
Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.1 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.
10.2+
Amendment Number One to the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, and incorporated herein by reference.
10.3+
Form of Retainer Stock Option Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.17 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2009, and incorporated herein by reference.
10.4+
Form of Stock Units Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.19 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.
10.5+ Chevron Incentive Plan, amended and restated effective January 1, 2021, filed as Exhibit 10.5 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2020, and incorporated herein by reference.
10.6+* Summary of Chevron Incentive Plan Award Criteria.
10.7+ Long-Term Incentive Plan of Chevron Corporation, filed as Appendix B to Chevron Corporation’s Notice of the 2013 Annual Meeting and 2013 Proxy Statement filed April 11, 2013, and incorporated herein by reference.
10.8+ Form of Performance Share Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed February 1, 2021, and incorporated herein by reference.
10.9+
Form of Performance Share Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed February 3, 2020, and incorporated herein by reference.
10.10+
Form of Standard Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.3 to Chevron Corporation’s Current Report on Form 8-K filed February 3, 2020, and incorporated herein by reference.
10.11+
Form of Special Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.3 to Chevron Corporation’s Current Report on Form 8-K filed February 4, 2019, and incorporated herein by reference.
10.12+
Form of Non-Qualified Stock Option Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.2 to Chevron Corporation’s Current Report on Form 8-K filed February 3, 2020, and incorporated herein by reference.
Exhibit No. Description
10.13+ Form of Stock Appreciation Rights Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.13 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2019 and incorporated herein by reference.
10.14+ Chevron Corporation Deferred Compensation Plan for Management Employees, filed as Exhibit 10.5 to Chevron Corporation’s Current Report on Form 8-K filed December 13, 2005, and incorporated herein by reference.
10.15+ Chevron Corporation Deferred Compensation Plan for Management Employees II, filed as Exhibit 10.5 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.
10.16+ Chevron Corporation Retirement Restoration Plan, filed as Exhibit 10.6 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.
10.17+ Amendment Number One to the Chevron Corporation Retirement Restoration Plan, filed as Exhibit 10.23 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2017, and incorporated herein by reference.
10.18+ Chevron Corporation ESIP Restoration Plan, Amended and Restated as of January 1, 2018, filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017, and incorporated herein by reference.
10.19+ Agreement between Chevron Corporation and R. Hewitt Pate, filed as Exhibit 10.16 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2011, and incorporated herein by reference.
10.20+ Amended and Restated Aircraft Time-Sharing Agreement, dated as of April 1, 2020, between Chevron U.S.A. Inc. and Michael K. Wirth, filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, and incorporated herein by reference.
10.21+ 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed May 27, 2022, and incorporated herein by reference.
10.22+ Form of Performance Share Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.
10.23+ Form of Standard Restricted Stock Unit Award Agreement (stock settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.2 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.
10.24+ Form of Standard Restricted Stock Unit Award Agreement (cash settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.3 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.
10.25+ Form of Special Restricted Stock Unit Award Agreement (share settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.4 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.
10.26+ Form of Special Restricted Stock Unit Award Agreement (cash settled) under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.5 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.
10.27+ Form of Non-Qualified Stock Options Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.6 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.
10.28+ Form of Stock Appreciation Right Award Agreement under the 2022 Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.7 to Chevron Corporation’s Current Report on Form 8-K filed January 27, 2023, and incorporated herein by reference.
10.29+ Letter Agreement, dated May 25, 2022, by and between Chevron Corporation and Joseph C. Geagea, filed as Exhibit 10.1 to Chevron Corporation's Current Report on Form 8-K filed May 27, 2022, and incorporated herein by reference.
10.30+* General Release and Separation Agreement, dated February 15, 2023, by and between Chevron Corporation and James W. Johnson.
21.1*
Subsidiaries of Chevron Corporation (page E-1).
22.1* Subsidiary Issuer of Guaranteed Securities.
23.1*
Consent of PricewaterhouseCoopers LLP (page E-2).
24.1*
Power of Attorney for certain directors of Chevron Corporation, authorizing the signing of the Annual Report on Form 10-K on their behalf.
Exhibit No. Description
31.1*
Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Executive Officer (page E-3).
31.2*
Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Financial Officer (page E-4).
32.1**
Rule 13a-14(b)/15d-14(b) Certification by the company’s Chief Executive Officer (page E-5).
32.2**
Rule 13a-14(b)/15d-14(b) Certification by the company’s Chief Financial Officer (page E-6).
99.1* Definitions of Selected Energy and Financial Terms (pages E-7 through E-10).
99.2 Report of Netherland, Sewell & Associates, Inc., filed as Exhibit 99.3 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2020, and incorporated herein by reference.
101* Interactive data files (formatted as Inline XBRL).
104*
Cover Page Interactive Data File (contained in Exhibit 101).
___________________________________________
+ Indicates a management contract or compensatory plan or arrangement.
* Filed herewith.
** Furnished herewith.
Pursuant to Item 601(b)(4) of Regulation S-K, certain instruments with respect to the company’s long-term debt are not filed with this Annual Report on Form 10-K. A copy of any such instrument will be furnished to the Securities and Exchange Commission upon request.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 23rd day of February, 2023.
Chevron Corporation
By: /s/ MICHAEL K. WIRTH
Michael K. Wirth, Chairman of the Board
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 23rd day of February, 2023.
Principal Executive Officer
(and Director)
/s/ MICHAEL K. WIRTH
Michael K. Wirth, Chairman of the
Board and Chief Executive Officer
Principal Financial Officer
/s/ PIERRE R. BREBER
Pierre R. Breber, Vice President
and Chief Financial Officer
Principal Accounting Officer
/s/ DAVID A. INCHAUSTI
David A. Inchausti, Vice President
and Controller
*By: /s/ MARY A. FRANCIS
Mary A. Francis,
Attorney-in-Fact
Directors
WANDA M. AUSTIN*
Wanda M. Austin
JOHN B. FRANK*
John B. Frank
ALICE P. GAST*
Alice P. Gast
ENRIQUE HERNANDEZ, JR.*
Enrique Hernandez, Jr.
MARILLYN A. HEWSON*
Marillyn A. Hewson
JON M. HUNTSMAN JR.*
Jon M. Huntsman Jr.
CHARLES W. MOORMAN*
Charles W. Moorman
DAMBISA F. MOYO*
Dambisa F. Moyo
DEBRA REED-KLAGES*
Debra Reed-Klages
RONALD D. SUGAR*
Ronald D. Sugar
D. JAMES UMPLEBY III*
D. James Umpleby III
CYNTHIA J. WARNER*
Cynthia J. Warner