SEC EDGAR Filing

Company: CHEVRON CORP
CIK: 93410
Filing Type: 10-K
Filing Date: 2021-02-25
Period of Report: 2020-12-31
SIC Code: 2911
State of Incorporation: DE
State of Location: CA
Fiscal Year End: 1231

Filename: 93410_10K_2020_0000093410-21-000009.htm
Filing Index: https://www.sec.gov/Archives/edgar/data/93410/0000093410-21-000009-index.html
HTM Filing Link: https://www.sec.gov/Archives/edgar/data/93410/000009341021000009/cvx-20201231.htm
Complete Text Filing Link: https://www.sec.gov/Archives/edgar/data/93410/0000093410-21-000009.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; 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 major subsidiaries is presented in Exhibit 21.1 on page E-1.
Overview of Petroleum Industry
Petroleum industry operations and profitability are influenced by many factors. Prices for crude oil, 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 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 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 31 through 38 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 primary objective is to deliver higher returns, lower carbon and superior shareholder value in any business environment. In the upstream, the company’s strategy is to deliver industry-leading returns while developing high-value resource opportunities. In the downstream, the company’s strategy is to be the leading downstream and chemicals company that delivers on customer needs. In seeking to help advance a lower carbon future, Chevron is focused on lowering its carbon intensity cost efficiently, increasing renewables and offsets in support of its business, and investing in low-carbon technologies to enable commercial solutions.
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 is focused on investing in its employees and its culture. Chevron hires, develops, and strives to retain critical talent, and fosters a culture that values diversity and inclusion and employee engagement, all of which support the company’s overall objective to deliver industry leading performance. Chevron’s leadership reinforces and monitors the company’s investment in people and the company’s culture. This includes reviews of metrics addressing critical function hiring, leadership development, attrition, diversity and inclusion, and employee engagement.
The following table summarizes Chevron’s number of employees by gender, where data is available, and by region as of December 31, 2020.
At December 31, 2020
Female Male Gender data not available 1
Total Employees
Number of Employees Percentage Number of Employees Percentage Number of Employees Percentage Number of Employees Percentage
U.S. 6,632 28 % 16,606 70 % 491 2 % 23,729 50 %
Other Americas 894 26 % 2,484 73 % 33 1 % 3,411 7 %
Africa 715 17 % 3,507 83 % 6 - % 4,228 9 %
Asia 2,982 29 % 7,334 71 % 80 1 % 10,396 22 %
Australia 1,746 40 % 2,584 60 % 6 - % 4,336 9 %
Europe 410 25 % 1,226 75 % 0 - % 1,636 3 %
Total Employees 2
13,379 28 % 33,741 71 % 616 1 % 47,736 100 %
1 Includes employees where gender data was not collected or employee chose not to disclose gender.
2 Includes 5,108 service station employees; 2,312 and 1,672 new employees came from the 2020 Puma Energy (Australia) Holdings Pty. Ltd and Noble Energy, Inc. acquisitions, respectively.
Hiring, Development and Retention
The company’s approach to attracting, developing and retaining its employees is anchored in a career-oriented employment model. Chevron recruits new employees through partnerships with universities and diversity associations. In 2020, over 500 students participated in the company’s first ever virtual internship program. In addition, the company recruits experienced hires to target critical skills.
Development programs are designed to build leadership capabilities at all levels and ensure the company’s workforce has the technical and operating capabilities to produce energy safely and reliably. Chevron’s leadership regularly reviews metrics on employee training and development programs, which are continually evolving to better meet the needs of the business. For instance, Chevron recently launched learning initiatives focused on digital innovation, including new Digital Academy and Digital Scholars programs. In addition, to ensure business continuity, leadership regularly reviews the talent pipeline, identifies and develops succession candidates, and builds succession plans for leadership positions. The Board provides oversight of CEO and executive succession planning.
Chevron’s 2020 annual voluntary attrition was 4.1 percent, in line with its historical rates. 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 and career advancement.
Diversity and Inclusion
Chevron is committed to advancing diversity and inclusion in the workplace so that employees are enabled to contribute to their full potential. The company believes innovative solutions to its most complex challenges emerge when diverse people, ideas, and experiences come together in an inclusive environment. Chevron reinforces the value of diversity and inclusion through accountability, communication, training and personnel selection processes. Examples of initiatives to further advance diversity and inclusion include the company’s Neurodiversity program through which the company employs neurodiverse individuals and leverages their talents, its Elevate program which focuses on learning opportunities to promote a deeper understanding of employees in underrepresented groups, and its Returnship initiative which provides support for women re-entering the workforce. In addition, Chevron has twelve employee networks (voluntary groups of employees that come together based on shared identity or interests) and more than fifteen diversity councils across its business units that help align diversity and inclusion efforts with business strategies.
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 have indicated a high degree of employee engagement. In 2020, the company’s employee survey focused on the COVID-19 impact on employee well-being and the company’s response to the pandemic. The survey results positively reinforced actions taken by Chevron, and helped inform further actions to address the impact on employees and their families through enhanced mental health and wellness support, financial assistance for unplanned childcare needs and remote learning resources, among other efforts. The company also has long-standing 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 its Employee Assistance Program, a confidential consulting service that can help employees resolve a broad range of personal, family and work-related concerns or problems.
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, Middle East, Asia and Australia. Tabulations of segment sales and other operating revenues, earnings and income taxes for the three years ending December 31, 2020, and assets as of the end of 2020 and 2019 - for the United States and the company’s international geographic areas - are in Note 12 to the Consolidated Financial Statements beginning on page 74. Similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are in Note 13 beginning on page 77 and Note 16 on page 82. Refer to page 44 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 capital and exploratory expenditures.
Upstream
Reserves
Refer to Table V beginning on page 103 for a tabulation of the company’s proved crude oil, condensate, natural gas liquids (NGLs), synthetic oil and natural gas reserves by geographic area, at the beginning of 2018 and at each year-end from 2018 through 2020. 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, 2020, 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, 2020, 27 percent of the company’s net proved oil-equivalent reserves were located in the United States, 18 percent were located in Australia and 20 percent were located in Kazakhstan.
The net proved reserve balances at the end of each of the three years 2018 through 2020 are shown in the following table:
At December 31
2020 2019 2018
Liquids - Millions of barrels
Consolidated Companies 4,475 4,771 4,975
Affiliated Companies 1,672 1,750 1,815
Total Liquids 6,147 6,521 6,790
Natural Gas - Billions of cubic feet
Consolidated Companies 27,006 26,587 28,733
Affiliated Companies 2,916 2,870 2,843
Total Natural Gas 29,922 29,457 31,576
Oil-Equivalent - Millions of barrels1
Consolidated Companies 8,976 9,202 9,764
Affiliated Companies 2,158 2,229 2,289
Total Oil-Equivalent 11,134 11,431 12,053
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.
Net Production of Liquids and Natural Gas
The following table summarizes the net production of liquids and natural gas for 2020 and 2019 by the company and its affiliates. Worldwide oil-equivalent production of 3.083 million barrels per day in 2020 was up approximately 1 percent from 2019. Production increases from shale and tight properties and the Noble Energy, Inc. (Noble) acquisition were partially offset by production curtailments associated with OPEC and coordinating countries’ (OPEC+) restrictions and market conditions, and asset sale related decreases of 100,000 barrels per day. Refer to the “Results of Operations” section beginning on page 37 for a detailed discussion of the factors explaining the changes in production for crude oil, condensate, natural gas liquids, synthetic oil and natural gas, and refer to Table V on pages 107 through 109 for information on annual production by geographical region.
Components of Oil-Equivalent
Oil-Equivalent Liquids Natural Gas
Thousands of barrels per day (MBPD) (MBPD)1
(MBPD) (MMCFPD)
Millions of cubic feet per day (MMCFPD) 2020 2019 2020 2019 2020 2019
United States2
1,058 929 790 724 1,607 1,225
Other Americas
Argentina
25 27 21 23 24 25
Brazil
6 8 6 8 1 2
Canada3
159 135 138 119 126 95
Colombia4
2 11 - - 14 64
Total Other Americas 192 181 165 150 165 186
Africa
Angola
87 95 78 86 53 52
Equatorial Guinea2
11 - 5 - 42 -
Nigeria
183 209 140 173 260 215
Republic of Congo
46 52 44 49 13 13
Total Africa 327 356 267 308 368 280
Asia
Azerbaijan4
7 20 7 18 3 10
Bangladesh
107 110 3 4 622 638
China
32 31 15 16 100 93
Indonesia
138 109 131 101 43 52
Israel2
20 - - - 116 -
Kazakhstan
55 49 32 28 136 129
Myanmar
15 15 - - 92 93
Partitioned Zone5
18 - 17 - 3 -
Philippines4
5 26 1 3 25 136
Thailand
207 238 54 65 918 1,038
Total Asia 604 598 260 235 2,058 2,189
Australia
Australia 441 455 42 45 2,392 2,460
Total Australia 441 455 42 45 2,392 2,460
Europe
Denmark4
- 5 - 3 - 11
United Kingdom4
14 62 13 44 5 108
Total Europe 14 67 13 47 5 119
Total Consolidated Companies 2,636 2,586 1,537 1,509 6,595 6,459
Affiliates3,6
447 472 331 356 695 698
Total Including Affiliates7
3,083 3,058 1,868 1,865 7,290 7,157
1 Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil.
2 Includes production associated with the acquisition of Noble commencing October 2020.
3 Includes synthetic oil: Canada, net
54 53 54 53 - -
Venezuela, net - 3 - 3 - -
4 Chevron sold its interest in various upstream producing assets in 2019 and 2020.
5 Located between Saudi Arabia and Kuwait. Production was shut-in in May 2015; resumed in July 2020.
6 Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil in Kazakhstan; Petroboscan and Petropiar in Venezuela through June 30, 2020; and Angola LNG in Angola.
7 Volumes include natural gas consumed in operations of 603 million and 638 million cubic feet per day in 2020 and 2019, respectively. Total “as sold” natural gas volumes were 6,687 million and 6,519 million cubic feet per day for 2020 and 2019, respectively.
Production Outlook
The company estimates its average worldwide oil-equivalent production in 2021 will grow up to 3 percent compared to 2020, assuming a Brent crude oil price of $50 per barrel and excluding the impact of anticipated 2021 asset sales. This estimate is subject to many factors and uncertainties, as described beginning on page 33. Refer to the “Review of Ongoing Exploration and Production Activities in Key Areas,” beginning on page 9, for a discussion of the company’s major crude oil and natural gas development projects.
Average Sales Prices and Production Costs per Unit of Production
Refer to Table IV on page 102 for the company’s average sales price per barrel of liquids (including crude oil, condensate and natural gas liquids) and per thousand cubic feet of natural gas produced, and the average production cost per oil-equivalent barrel for 2020, 2019 and 2018.
Gross and Net Productive Wells
The following table summarizes gross and net productive wells at year-end 2020 for the company and its affiliates:
At December 31, 2020
Productive Oil Wells1
Productive Gas Wells1
Gross Net Gross Net
United States 42,933 31,380 2,859 2,322
Other Americas 1,077 687 216 135
Africa 1,732 679 50 19
Asia 14,210 12,492 3,179 1,732
Australia 533 299 101 25
Europe 29 6 - -
Total Consolidated Companies 60,514 45,543 6,405 4,233
Affiliates2
1,675 601 - -
Total Including Affiliates 62,189 46,144 6,405 4,233
Multiple completion wells included above 619 340 148 117
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 1,452 and net 490 productive oil wells for interests accounted for by the non-equity method.
Acreage
At December 31, 2020, the company owned or had under lease or similar agreements undeveloped and developed crude oil and natural gas properties throughout the world. The geographical distribution of the company’s acreage is shown in the following table:
Undeveloped2
Developed Developed and Undeveloped
Thousands of acres1
Gross Net Gross Net Gross Net
United States 4,120 3,561 4,670 3,317 8,790 6,878
Other Americas 19,418 10,592 1,169 252 20,587 10,844
Africa 7,393 4,829 2,522 1,051 9,915 5,880
Asia 18,742 7,692 1,914 1,041 20,656 8,733
Australia 10,370 6,471 2,061 812 12,431 7,283
Total Consolidated Companies 60,043 33,145 12,336 6,473 72,379 39,618
Affiliates3
702 290 102 46 804 336
Total Including Affiliates 60,745 33,435 12,438 6,519 73,183 39,954
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 2021, 2022 and 2023 if production is not established by certain required dates are 2,415, 5,404 and 3,199, 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.
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 sales contracts specify delivery of fixed and determinable quantities, as discussed below.
In the United States, the company is contractually committed to deliver 1,136 billion cubic feet of natural gas to third parties from 2021 through 2023. 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 2,800 billion cubic feet of natural gas to third parties from 2021 through 2023 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 Israel sales contracts contain formulas that generally reflect an initial base price subject to price indexation, Brent-linked or other, over the life of the contract and have a contractual floor. 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 on page 99 for details associated with the company’s development expenditures and costs of proved property acquisitions for 2020, 2019 and 2018.
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, 2020. 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 Drilling1
Net Wells Completed
at 12/31/20 2020 2019 2018
Gross Net Prod. Dry Prod. Dry Prod. Dry
United States 190 149 539 2 682 1 509 1
Other Americas 12 9 27 - 36 - 43 -
Africa 1 - 5 - 26 - 8 -
Asia 23 8 94 2 181 2 289 5
Australia - - - - - - 1 -
Europe - - 1 - 1 - 2 -
Total Consolidated Companies 226 166 666 4 926 3 852 6
Affiliates2
22 8 13 - 43 - 39 -
Total Including Affiliates 248 174 679 4 969 3 891 6
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 19 and net 6 wells drilling for interests accounted for by the non-equity method.
Exploration Activities
Refer to Table I on page 99 for detail on the company’s exploration expenditures and costs of unproved property acquisitions for 2020, 2019 and 2018.
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, 2020. “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 12/31/20 2020 2019 2018
Gross Net Prod. Dry Prod. Dry Prod. Dry
United States 1 - 4 1 10 2 13 2
Other Americas - - 2 2 - - 1 1
Africa - - - - - - - -
Asia - - - - - - 1 -
Australia - - - - - - - -
Europe - - - - - - - 1
Total Consolidated Companies 1 - 6 3 10 2 15 4
Affiliates - - - - - - - -
Total Including Affiliates 1 - 6 3 10 2 15 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.
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 2020 key upstream activities, some of which are also discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations, beginning on page 37, are presented below. The comments include references to “total production” and “net production,” which are defined under “Production” in Exhibit 99.1 on page E-7.
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, California, Colorado and the Gulf of Mexico. Acreage for the United States can be found in the table on page 7. Net daily oil-equivalent production in the United States can be found in the table on page 6.
With the acquisition of Noble in October 2020, Chevron increased its position in the Permian Basin and acquired acreage in Colorado and Wyoming.
The company’s acreage in the Permian Basin of West Texas and southeast New Mexico includes multiple stacked formations that enable production from several layers of rock in different geologic zones. Chevron has implemented a factory development strategy in the basin, which utilizes multiwell pads to drill a series of horizontal wells that are completed concurrently using hydraulic fracture stimulation. The company is also applying data analytics and technology to drive improvements in identifying well targets, in drilling and completions and in production performance. In 2020, Chevron’s net daily unconventional and conventional production in the Permian Basin averaged 294,000 barrels of crude oil, 980 million cubic feet of natural gas and 150,000 barrels of NGLs.
In 2020, Chevron was one of the largest crude oil producers in California. Construction was completed in April 2020 on a new 29-megawatt solar farm to supply power to the Lost Hills Field. In October 2020, Chevron announced participation in a carbon capture trial in California with start-up expected in 2022.
In Colorado, development in the Denver-Julesburg (DJ) Basin includes Wells Ranch and Mustang areas. Chevron’s integrated development plan provides an opportunity to efficiently produce these resources.
In Wyoming, the company has acreage in the Powder River and Green River Basins.
During 2020, net daily production in the Gulf of Mexico averaged 175,000 barrels of crude oil, 96 million cubic feet of natural gas and 11,000 barrels of NGLs. 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 2020. Stage 3 development drilling continued with the final well completed in May 2020. 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 injection is expected in 2023. The Stage 4 multiphase subsea pump project replaces the single-phase subsea pumps in both the Jack and St. Malo fields. Progress during 2020 included beginning pump module installation. Proved reserves have been recognized for the multiphase subsea pump project. The Jack and St. Malo fields have an estimated production life of 30 years.
The company has a 15.6 percent nonoperated working interest in the deepwater Mad Dog Field. Project execution continued in 2020 on the Mad Dog 2 Project. This phase is the development of the southwestern extension of the Mad Dog Field, including a new floating production platform with a design capacity of 140,000 barrels of crude oil per day. Drilling and construction of the floating production unit are progressing as planned, and first oil is expected in 2022. 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 the third production well coming online in September 2020. An additional well is expected to come online in third quarter 2021. The project has an estimated production life of 35 years.
The company has a 58 percent-owned and operated interest in the deepwater Tahiti Field. Progress continued on the Tahiti Upper Sands Project, which includes topsides facility enhancements to process high gas rates with start-up anticipated in third quarter 2021. Proved reserves have been recognized for this project. The Tahiti Field has an estimated remaining production life of more than 20 years.
Chevron holds a 25 percent nonoperated working interest in the Stampede Field, which is located in the Green Canyon area. Production ramp-up continued in 2020, with the final producing well completed in March 2020. The field has an estimated production life of 30 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 planned facility has a design capacity of 75,000 barrels of crude oil and 28 million cubic feet of natural gas per day. Development work continued in 2020 with construction of the drillship, acquisition of seismic data, detailed engineering, equipment procurement and commencement of fabrication for the production facilities. At the end of 2020, no proved reserves were recognized for this project.
Chevron has a 60 percent-owned and operated interest in the Ballymore Field located in the Mississippi Canyon area and a 40 percent nonoperated working interest in the Whale discovery located in the Perdido area. After successful appraisal programs on the Ballymore project, Chevron is planning to enter front-end engineering design (FEED) in second quarter 2021. FEED activities on the Whale project continued in 2020, with final investment decision expected in second-half 2021. At the end of 2020, proved reserves had not been recognized for these projects.
During 2020, the company participated in two exploration wells and one appraisal well in the deepwater Gulf of Mexico. In February 2020, the first well in the Esox prospect, where Chevron holds a 21.4 percent nonoperated working interest, was tied into the Tubular Bells production facility.
In March 2020, Chevron added 15 blocks in a U.S. Gulf of Mexico lease sale. Chevron subsequently added eight blocks resulting from a November 2020 U.S. Gulf of Mexico lease sale.
The company sold its assets in the Marcellus and Utica Shale areas in November 2020.
Other Americas
“Other Americas” includes Argentina, Brazil, Canada, Colombia, Mexico, Suriname and Venezuela. Acreage for "Other Americas" can be found in the table on page 7. Net daily oil-equivalent production from these countries can be found in the table on page 6.
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 Beaufort Sea region of the Northwest Territories and British Columbia.
The company holds a 20 percent nonoperated working interest in the Athabasca Oil Sands Project (AOSP) 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 emissions from the upgrader are reduced by carbon capture and storage facilities.
Chevron has a 70 percent-owned and operated interest in most of the Duvernay shale acreage. By early 2021, a total of 203 wells had been tied into production facilities.
Chevron holds a 26.9 percent nonoperated working interest in the Hibernia Field and a 23.7 percent nonoperated working interest in the unitized Hibernia Southern Extension areas offshore Atlantic Canada. The company holds a 29.6 percent nonoperated working interest in the heavy oil Hebron Field, also offshore Atlantic Canada, which has an expected economic life of 30 years.
Chevron holds a 50 percent-owned and operated interest in Flemish Pass Basin Block EL 1138. The company also holds a 25 percent nonoperated working interest in blocks EL 1145, EL 1146 and EL 1148 and a 40 percent nonoperated working interest in EL 1149.
Chevron holds a 50 percent-owned and operated interest in the Kitimat LNG and Pacific Trail Pipeline projects and a 50 percent-owned and operated interest in the Liard and Horn River shale gas basins in British Columbia. Efforts are underway to evaluate strategic alternatives for these projects.
Mexico The company owns and operates a 33.3 percent interest in Block 3 in the Perdido area of the Gulf of Mexico. Seismic interpretation progressed in 2020. Chevron holds a 37.5 percent-owned and operated interest in Block 22 where reprocessing of 3-D seismic data continued in 2020. The company also holds a 40 percent nonoperated interest in Blocks 20, 21 and 23 in the Cuenca Salina area in the deepwater Gulf of Mexico. Two exploration wells were drilled in the first half of 2020.
Argentina Chevron holds a 50 percent nonoperated interest in the Loma Campana and Narambuena concessions in the Vaca Muerta Shale. Evaluation of the nonoperated Narambuena Block continued in 2020, including a four-well appraisal program which achieved first oil in November 2020. Chevron has a 90 percent-owned and operated interest with a four-year exploratory concession in Loma del Molle Norte Block.
In April 2020, drilling and completion activity was halted due to the COVID-19 pandemic at the nonoperated Loma Campana concession in the Vaca Muerta Shale. Completion activity resumed in fourth quarter 2020 with drilling activity planned to re-start in first quarter 2021. During 2020, 17 horizontal wells were drilled. This concession expires in 2048.
Chevron also owns and operates a 100 percent interest in the El Trapial Field with both conventional production and Vaca Muerta Shale potential. The company utilizes waterflood operations to mitigate declines at the operated El Trapial Field and continues to evaluate the potential of the Vaca Muerta Shale. The eight-well drilling program completed in third quarter 2020, and first oil was achieved in October 2020. Chevron expects to complete the appraisal program in second quarter 2021. The El Trapial concession expires in 2032.
Brazil In February 2020, the company initiated the process to sell its 37.5 percent nonoperated interest in the Papa-Terra oil field.
Chevron holds between 30 to 45 percent of both operated and nonoperated interests in 11 blocks within the Campos and Santos basins. One exploration well was drilled in 2020.
Colombia In April 2020, the company completed the sale of its interests in the offshore Chuchupa and onshore Ballena natural gas fields. Chevron holds a 40 percent-owned and operated working interest in the offshore Colombia-3 and Guajira Offshore-3 Blocks. Exploration activities continued in 2020.
Suriname Chevron holds a 33.3 percent nonoperated working interest in deepwater Block 42. Exploration activities continued in 2020. Chevron, along with the operator, relinquished its 50 percent nonoperated working interest in deepwater Block 45 in September 2020.
Venezuela Chevron’s interests in Venezuela are located in western Venezuela and the Orinoco Belt. At the end of 2020, no proved reserves were recognized for these interests.
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 39.2 percent interest in Petroboscan, which operates the Boscan Field in western Venezuela and a 25.2 percent interest in Petroindependiente, which operates the LL-652 Field in Lake Maracaibo, both of which are under agreements expiring in 2026. For additional information on the company’s activities in Venezuela, refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 31 through 38 under upstream.
Africa
In Africa, the company is engaged in upstream activities in Angola, the Republic of Congo, Cameroon, Equatorial Guinea, and Nigeria. Acreage for Africa can be found in the table on page 7. Net daily oil-equivalent production from these countries can be found in the table on page 6.
Angola The company operates and holds a 39.2 percent interest in Block 0, a concession adjacent to the Cabinda coastline, and a 31 percent operated interest in a production-sharing contract (PSC) for deepwater Block 14. The Block 0 concession extends through 2030. The Sanha Lean Gas Connection Project (SLGC) reached final investment decision in January 2021. 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 2020, the Angolan government approved combining all development areas in Block 14, providing enhanced fiscal terms and extending the PSC expiration to 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 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. During 2020, work continued toward developing non-associated gas in offshore Angola, which is expected to supply the Angola LNG plant.
Angola-Republic of Congo Joint Development Area Chevron operates and holds a 31.3 percent interest in the Lianzi Unitization Zone, located in an area shared equally by Angola and the Republic of Congo. The expiration for Lianzi is 2031.
Republic of Congo Chevron has a 31.5 percent nonoperated working interest in the offshore Haute Mer permit areas (Nkossa, Nsoko and Moho-Bilondo). The permits for Nkossa, Nsoko and Moho-Bilondo expire in 2027, 2034 and 2030, respectively.
Cameroon Chevron owns and operates the YoYo Block in the Douala Basin. Preliminary development plans include a possible joint development between YoYo and Yolanda Field in Equatorial Guinea.
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 Alen natural gas and condensate field in Block O. Work continued in 2020 on the development of the Alen Gas Project, which was completed in February 2021. The company also holds a 32 percent nonoperated interest in the natural gas and condensate Alba Field.
Nigeria Chevron operates and holds a 40 percent interest in eight concessions 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 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 LPG and condensate export capacity of 58,000 barrels per day. The company is also the operator of the 33,000-barrel-per-day Escravos Gas to Liquids facility. In addition, the company holds a 36.7 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. Additionally, Chevron holds a 30 percent nonoperated working interest in the Usan Field in OML 138. The leases that contain the Usan and Agbami Fields expire in 2023 and 2024, respectively.
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 are planned to 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. Work continues to progress toward a final investment decision. At the end of 2020, no proved reserves were recognized for this project.
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 adjacent licenses OML 139 and OML 154. 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.
In December 2020, the company signed an agreement to divest its 40 percent operated interest in OML 86 and OML 88.
Middle East
In the Middle East, the company is engaged in upstream activities in Cyprus, Egypt, Israel, the Kurdistan Region of Iraq and the Partitioned Zone located between Saudi Arabia and Kuwait. Quantitative data for Egypt can be found within the Africa geography throughout this document. Quantitative data for Cyprus, Israel, the Kurdistan Region of Iraq and the Partitioned Zone can be found within the Asia geography throughout this document.
Cyprus The company holds a 35 percent-owned and operated interest in Aphrodite gas field in Block 12. Chevron operates the field with the Government of Cyprus and has a license that expires in 2044.
Egypt During 2020, Chevron acquired four oil and gas exploration blocks with a 90 percent-owned and operated interest. The acquired blocks are Block 1 in the Red Sea, North Sidi Barrani in Block 2, and North El Dabaa and the Nargis blocks in the Mediterranean Sea. The company also acquired a 27 percent nonoperated working interest in the North Cleopatra and North Marina blocks also in the Mediterranean Sea.
Israel Chevron holds a 39.7 percent-owned and operated interest in the Leviathan Field, which operates under a concession that expires in 2044. During 2020, Chevron continued to ramp up production and progress its efforts to monetize discovered resources at Leviathan Field. The company also holds a 25 percent-owned and operated interest in the Tamar gas field. Progress continues on the Tamar SW development, which consists of one well tied back to Tamar. The current term of the lease for this field expires in 2038.
Kurdistan Region of Iraq The company operates and holds a 50 percent interest in the Sarta PSC, which expires in 2047, and a 40 percent interest in the Qara Dagh PSC, which expires in October 2021. First oil was achieved from the Sarta Stage 1A project in November 2020. At the end of 2020, proved reserves have been recognized for this project. Chevron will operate the Sarta block through 2021 and plans to transfer operatorship thereafter provided certain milestones are achieved.
Partitioned Zone Chevron holds a concession to oper ate 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. Production restart was achieved in July 2020, and the company expects production to ramp up to full capacity levels in 2021.
Asia
In Asia, the company is engaged in upstream activities in Kazakhstan, Russia, Bangladesh, Myanmar, Thailand, China and Indonesia. Acreage for Asia can be found in the table on page 7. Net daily oil-equivalent production for these countries can be found in the table on page 6.
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. All of TCO’s 2020 crude oil production was exported through the Caspian Pipeline Consortium (CPC) pipeline.
The Future Growth Project and Wellhead Pressure Management Project (FGP/WPMP) at Tengiz is managed as a single integrated project. The FGP is designed to increase total daily production by about 260,000 barrels of crude oil and to expand the utilization of sour gas injection technology proven in existing operations to increase ultimate recovery from the reservoir. The WPMP is designed to maintain production levels in existing plants as reservoir pressure declines. The project advanced in 2020 with overall progress at approximately 81 percent at year-end 2020. TCO continued construction on the FGP/WPMP including completion of all fabrication and sealift activities and installing key modules and foundations at the 3rd Generation Plant. The WPMP portion is expected to start up in late 2022, with the remaining facilities expected to come online in mid-2023. COVID-19 impacts on project schedules and cost estimates are unknown at this time due to the uncertain timeline for remobilizing all personnel and safely sustaining activity levels. 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 2020. Karachaganak Expansion Project Stage 1A reached final investment decision in December 2020. At the end of 2020, proved reserves had not been recognized for future expansion.
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 2020, CPC transported an average of 1.3 million barrels of crude oil per day, composed of 1.1 million barrels per day from Kazakhstan and 0.2 million barrels per day from Russia.
Bangladesh Chevron operates and holds a 100 percent interest in Block 12 (Bibiyana Field) and Blocks 13 and 14 (Jalalabad and Moulavi Bazar fields). The rights to produce from Jalalabad expire in 2030, from Moulavi Bazar in 2033 and from Bibiyana in 2034.
Myanmar Chevron has a 28.3 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 28.3 percent nonoperated working interest in a pipeline company that transports natural gas to the Myanmar-Thailand border for delivery to power plants in Thailand.
Thailand Chevron holds operated interests in the Pattani Basin, located in the Gulf of Thailand, with ownership ranging from 35 percent to 80 percent. Concessions for producing areas within this basin expire between 2022 and 2035. 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 holds ownership ranging from 70 to 80 percent of the Erawan concession, which expires in April 2022. Chevron also has a 35 percent-owned and operated interest in the Ubon Project in Block 12/27. In late 2020, project studies were suspended pending an improved investment climate. At the end of 2020, proved reserves had not been recognized for this project.
Chevron holds between 30 and 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.
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, 24.5 percent in the Qinhuangdao (QHD) 32-6 Block, and 16.2 percent in Block 11/19 in the Bohai Bay. The PSCs for these producing assets expire between 2022 and 2028.
Philippines The company closed the sale of its 45 percent nonoperated working interest in the offshore Malampaya natural gas field in March 2020.
Indonesia Chevron has working interests through various PSCs in Indonesia. In Sumatra, the company holds a 100 percent-owned and operated interest in the Rokan PSC, which expires in August 2021. The company operates and holds a 62 percent interest in two PSCs in the Kutei Basin (Rapak and Ganal), located offshore eastern Kalimantan. Additionally, in offshore eastern Kalimantan, the company operates a 72 percent interest in the Makassar Strait PSC. The PSCs for offshore eastern Kalimantan expire in 2027 and 2028.
Chevron has concluded that the Indonesia Deepwater Development held by the Kutei Basin PSCs does not compete in its portfolio and is evaluating strategic alternatives for the company’s 62 percent-owned and operated interest.
Azerbaijan In April 2020, Chevron sold its 9.6 percent nonoperated interest in Azerbaijan International Operating Company and its 8.9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) pipeline affiliate.
United Kingdom
Net oil equivalent production for the United Kingdom can be found in the table on page 6.
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. Three additional wells were completed in 2020. The Clair Field has an estimated production life extending beyond 2050.
Australia
Chevron is Australia's largest producer of LNG. Acreage can be found in the table on page 7. Net daily oil-equivalent production can be found in the table on page 6.
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 the Gorgon Project, which includes the development of the Gorgon and Jansz-Io fields. The carbon dioxide system reached a full injection rate by first quarter 2020. Progress on the Gorgon Stage 2 project continued in 2020 with the completion of drilling of 11 subsea wells and is expected to be completed in 2022. The project's estimated economic life exceeds 40 years.
FEED work continued in 2020 on the Jansz-Io Compression Project. The project supports maintaining gas supply to the Gorgon LNG plant and maximizing the recovery of fields accessing the Jansz trunkline.
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 the Wheatstone Project. The project 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. The total production capacity for the Wheatstone and Iago fields and nearby third-party fields is expected to be approximately 1.6 billion cubic feet of natural gas and 30,000 barrels of condensate per day. The project’s estimated economic life exceeds 30 years.
Chevron has a 16.7 percent nonoperated working interest in the NWS Venture in Western Australia. In June 2020, Chevron announced the decision to market its share in the NWS Venture with the data room opening in September 2020.
The company continues to evaluate exploration and appraisal activity across the Carnarvon Basin in which it holds more than 6.6 million net acres. During 2020, the company relinquished nonoperated working interests it held in the Browse 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.
Sales of Natural Gas and Natural Gas Liquids
The company sells natural gas and NGLs from its producing operations under a variety of contractual arrangements. In addition, the company also makes third-party purchases and sales of natural gas and NGLs in connection with its supply and trading activities.
During 2020, U.S. and international sales of natural gas averaged 3.9 billion and 5.6 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, Kazakhstan, Indonesia, Israel, Myanmar, Nigeria and Thailand.
U.S. and international sales of NGLs averaged 233,000 and 120,000 barrels per day, respectively, in 2020.
Refer to “Selected Operating Data,” on page 41 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 and natural gas liquids. Refer also to “Delivery Commitments” beginning on page 7 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 2020, the company had a refining network capable of processing 1.8 million barrels of crude oil per day. Operable capacity at December 31, 2020, and daily refinery inputs for 2018 through 2020 for the company and affiliate refineries are summarized in the table on the next page.
Average crude oil distillation capacity utilization was 76 percent in 2020 and 90 percent in 2019. At the U.S. refineries, crude oil distillation capacity utilization averaged 73 percent in 2020, compared with 91 percent in 2019. Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 59 percent and 65 percent of Chevron’s U.S. refinery inputs in 2020 and 2019, respectively.
In the United States, the company continued work on projects to improve refinery flexibility and reliability. At the El Segundo Refinery in California, enhancements are underway to enable production of renewable fuels including diesel, jet and gasoline from bio-feedstocks. At the refinery in Salt Lake City, Utah, construction continued on the alkylation retrofit project with more than 100 modules installed. Project start-up is expected in second quarter 2021. The Pasadena Refinery enables processing of greater amounts of Permian light crude oil and provides integration with Chevron’s Gulf Coast Pascagoula, Mississippi refinery and Houston Blend Center.
Outside the United States, the company has three large refineries in South Korea, Singapore and Thailand. The 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. Refinery upgrades have enabled SRC to produce higher-quality gasoline that meets stricter emission standards. The 50 percent-owned, GS Caltex (GSC) operated, Yeosu Refinery in South Korea remains one of the world’s largest refineries with a total crude capacity of 800,000 barrels per day. In 2020, progress continued on the olefins mixed-feed cracker and associated polyethylene unit with first production expected second-half 2021. The company’s 60.6 percent-owned refinery in Map Ta Phut, Thailand, continues to supply high-quality petroleum products through the Caltex brand into regional markets.
Petroleum Refineries: Locations, Capacities and Inputs
Capacities and inputs in thousands of barrels per day December 31, 2020 Refinery Inputs
Locations Number Operable Capacity 2020 2019 2018
Pascagoula Mississippi 1 369 305 358 332
El Segundo California 1 290 176 241 273
Richmond California 1 257 198 236 249
Pasadena1
Texas 1 110 69 58 -
Salt Lake City Utah 1 58 45 54 51
Total Consolidated Companies - United States 5 1,084 793 947 905
Map Ta Phut Thailand 1 175 143 134 160
Cape Town2
South Africa - - - - 49
Total Consolidated Companies - International 1 175 143 134 209
Affiliates Various Locations3
2 545 441 483 494
Total Including Affiliates - International 3 720 584 617 703
Total Including Affiliates - Worldwide 8 1,804 1,377 1,564 1,608
1 In May 2019, the company acquired the Pasadena, TX refinery.
2 In September 2018, the company sold its interest in the Cape Town refinery.
3 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, 2020.
Refined Products Sales Volumes
Thousands of barrels per day 2020 2019 2018
United States
Gasoline
581 667 627
Jet Fuel
139 256 255
Diesel/Gas Oil
167 191 188
Residual Fuel Oil
33 42 48
Other Petroleum Products1
83 94 100
Total United States 1,003 1,250 1,218
International2
Gasoline
264 289 336
Jet Fuel
143 238 276
Diesel/Gas Oil
438 427 446
Residual Fuel Oil
184 167 177
Other Petroleum Products1
192 206 202
Total International 1,221 1,327 1,437
Total Worldwide2
2,224 2,577 2,655
1 Principally naphtha, lubricants, asphalt and coke.
2 Includes share of affiliates’ sales:
348 379 373
In the United States, the company markets under the Chevron and Texaco brands. At year-end 2020, the company supplied directly or through retailers and marketers approximately 8,000 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 2020, Chevron continued to grow in northwestern Mexico, expanding to nearly 230 branded stations at the end of the year. The company also operates through affiliates under various brand names. 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 June 2020, the company acquired a network of terminals and service stations in Australia aligning with Chevron's value chain optimization in the Asia-Pacific region.
Chevron markets commercial aviation fuel to 69 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 the 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 2020, the company manufactured, blended or conducted research at 10 locations around the world. Construction was completed in 2020 on a lubricant additive blending and shipping plant in Ningbo, China. Commercial production is anticipated to begin in the second quarter 2021.
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 2020, CPChem owned or had joint-venture interests in 28 manufacturing facilities and two research and development centers around the world.
CPChem holds a 51 percent interest in the US Gulf Coast II Petrochemical Project (USGC II) and a 30 percent interest in the Ras Laffan Petrochemical Project (RLPP) in Qatar. Engineering and design were completed for USGC II in November 2020 and are ongoing for the RLPP facility.
Chevron also maintains a role in the petrochemical business through the operations of GSC, the company’s 50 percent-owned affiliate. 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 polypropylene, which is used to make automotive and home appliance parts, food packaging, laboratory equipment and textiles.
In 2020, progress continued on the construction of an olefins mixed-feed cracker and associated polyethylene unit within the existing refining and petrochemical facilities in Yeosu, South Korea. First production is expected at the new plant in second-half 2021.
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.
As a result of the Noble acquisition, Chevron acquired a majority interest in Noble Midstream Partners LP (Noble Midstream). Noble Midstream is primarily focused in the DJ Basin in Colorado and Delaware Basin in Texas providing services to Chevron and third-party customers. In February 2021, Chevron announced a non-binding offer to acquire all of the outstanding common units of Noble Midstream Partners LP not already owned by Chevron or any of its affiliates.
Refer to pages 12 through 13 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.
Other Businesses
Chevron Technical Center The company’s technical center provides expertise to drive the application of technology, initiatives to transform Chevron’s digital future, and innovative breakthrough technologies to support the future of energy. The organization conducts research, develops and qualifies technology, and provides technical services and competency development. The disciplines cover earth sciences, reservoir and production engineering, drilling and completions, facilities engineering, manufacturing, process technology, catalysis, technical computing and health, environment and safety.
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.
Chevron’s Technology Ventures (CTV) unit identifies and integrates 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 venture investing, with eight funds that have supported more than 100 startups and worked with more than 200 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 fund targets the decarbonization of oil and gas, industry and commercial transportation; Emerald Ventures targets energy, water, industrial IT and advanced materials; and the HX Venture fund targets Houston, Texas high-growth start-ups.
Chevron continued its participation as a member of OGCI, a global collaboration focused on the industry’s efforts to take actions to accelerate and participate in a lower carbon future. In 2020, OGCI committed to a Global Gas Flaring Explorer web platform and set a target for OGCI members to reduce oil and gas carbon intensity.
Some of the investments the company makes in the areas described above are in new or unproven technologies and business processes, and ultimate technical or commercial successes are not certain. Refer to Note 25 on page 95 for a summary of the company’s research and development expenses.
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 is committed to improving energy efficiency in its day-to-day operations and is required to comply with the greenhouse gas-related laws and regulations to which it is subject. Refer to

Item 1A. Risk Factors
Item 1A. Risk Factors
Chevron is a global energy company and its operating and financial results are subject to a variety of risks inherent in the global oil, gas, and petrochemical businesses. Many of these risks are not within the company’s control and could materially impact the company’s results of operations and financial condition.
BUSINESS, OPERATIONAL AND ACQUISITION-RELATED RISK FACTORS
Impacts of the COVID-19 pandemic have resulted in a significant decrease in demand for Chevron’s products and caused a precipitous drop in commodity prices that has had, and may continue to have, an adverse and potentially material adverse effect on Chevron’s financial and operating results.
As of the date of this Annual Report on Form 10-K, the economic, business, and oil and gas industry impacts from the COVID-19 pandemic and the disruption to capital markets have continued to be far reaching. Crude oil prices, the single largest variable that affects the company’s results of operations, fell to historic lows, even briefly going negative, due to a combination of a severely reduced demand for crude oil, gasoline, jet fuel, diesel fuel, and other refined products resulting from government-mandated travel restrictions and the curtailment of economic activity resulting from the COVID-19 pandemic. As a result, a market imbalance has existed and may continue to exist, with oil supplies exceeding current and expected near-term demand. Although OPEC members and other countries have agreed to cut global oil supply, the commitments and actions to date have not matched the significant decrease in global demand, which has resulted in increased inventory levels in refineries, pipelines and storage facilities in prior periods and which may drive increased inventory levels in future periods.
Extended periods of low prices for crude oil are expected to have a material adverse effect on the company’s results of operations, financial condition and liquidity. Among other things, the company’s earnings, cash flows, and capital and exploratory expenditure programs may be negatively affected, as would its production volumes and proved reserves. As a result, the value of the company’s assets may also become impaired in future periods, as we saw in 2020.
The company’s operations and workforce are being impacted by the COVID-19 pandemic, causing certain operations to be curtailed to various degrees. At 50 percent-owned Tengizchevroil in Kazakhstan, COVID-19 infections have led to the demobilization of a significant portion of the workforce, adversely impacting the construction pace for completion of the FGP/WPMP project. Although infection levels in Kazakhstan improved in the third quarter 2020, allowing remobilization of the FGP/WPMP construction workforce to commence, a resurgence of infections prevented the final five percent of the planned workforce from returning to work in the fourth quarter 2020, slowing progress on the project. The ultimate effects of COVID-19 on FGP/WPMP construction remain uncertain and cannot be predicted at this time. In particular, we are currently unable to predict whether COVID-19 will have a material adverse impact on our ability to complete FGP/WPMP on schedule or within the current cost estimate for the project.
As a result of decreased demand for its products, the company made cuts to its upstream capital and exploratory expenditure program for 2020, which are expected to negatively impact future production, have led to and could lead to further negative revisions of reserves and could also lead to the further impairment of assets. Production curtailments, such as those due to the reductions imposed by OPEC+ nations in Kazakhstan, Nigeria and Angola, and other production curtailment actions taken by operators of assets for which the company has non-operated interests or due to market conditions, have exacerbated and may continue to further exacerbate these negative impacts in future periods. Within downstream, the company reduced its capital spending program and is also deferring certain discretionary maintenance activities while maintaining expenditures for asset integrity and reliability. The company has reduced the utilization rates of its refineries in response to reduced demand for its products, particularly greatly reduced demand for jet fuel due to the COVID-19 impact on travel and the aviation industry.
The company’s suppliers are also being impacted by the COVID-19 pandemic and access to materials, supplies, and contract labor has been strained. In certain cases, the company has received notices invoking force majeure provisions in supplier contracts. This strain on the financial health of the company’s suppliers could put further pressure on the company’s financial results and may negatively impact supply assurance and supplier performance. In-country conditions, including potential future waves of the COVID-19 virus 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.
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 resurgences of the pandemic, 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.
The impact of the COVID-19 pandemic is evolving, and the continuation or a resurgence of the pandemic could precipitate or aggravate the other risk factors identified in this Form 10-K, which in turn could further 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.
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 single largest variable that affects the company’s results of operations is the price of crude
oil, which can be influenced by general economic conditions, industry production and inventory levels, technology advancements, 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, and geopolitical risks. 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 and exploratory 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. 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; 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, accidents, civil unrest, political events, fires, earthquakes, system failures, cyber threats, terrorist acts and epidemic or pandemic diseases such as the COVID-19 pandemic, any of which could result in suspension of operations or harm to people or the natural environment.
Chevron’s risk management systems are designed to assess potential physical and other risks to its operations and assets and to plan for their resiliency. While capital investment reviews and decisions incorporate potential ranges of physical risks such as storm severity and frequency, sea level rise, air and water temperature, precipitation, fresh water access, wind speed, and earthquake severity, among other factors, it is difficult to predict with certainty the timing, frequency or severity of such events, any of which could have a material adverse effect on the company's results of operations or financial condition.
Cyberattacks targeting Chevron’s 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. 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 crude oil and natural gas 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 or unforeseen liability for which the company is self-insured, not fully insured or for which insurance recovery is significantly delayed could have a material adverse effect on the company’s results of operations or financial condition.
The Noble acquisition may cause our financial results to differ from our expectations or the expectations of the investment community, we may not achieve the anticipated benefits of the acquisition, and the acquisition may disrupt our current plans or operations.
The success of the Noble acquisition, which closed in October 2020, will depend, in part, on Chevron’s ability to realize the anticipated benefits of the acquisition, including the anticipated annual run-rate operating and other cost synergies and accretion to return on capital employed, free cash flow and earnings per share. Failure to realize anticipated synergies in the expected timeframe, operational challenges, the diversion of management’s attention from ongoing business concerns, and unforeseen expenses associated with the acquisition may have an adverse impact on our financial results.
One of our subsidiaries acts as the general partner of a publicly traded master limited partnership, Noble Midstream Partners LP, which may involve a potential legal liability.
One of our subsidiaries acts as the general partner of Noble Midstream, a publicly traded master limited partnership. Our control of the general partner of Noble Midstream may increase the possibility that we could be subject to claims of breach of duties owed to Noble Midstream, including claims of conflict of interest. Any liability resulting from such claims could have a material adverse effect on our future business, financial condition, results of operations and cash flows.
LEGAL, REGULATORY AND ESG-RELATED RISK FACTORS
Chevron’s business subjects the company to liability risks from litigation or government action The company produces, transports, refines and markets potentially hazardous materials, and it purchases, handles and disposes of other potentially hazardous materials in the course of its business. Chevron's operations also produce byproducts, which may be considered pollutants. Often these operations are conducted through joint ventures over which the company may have limited influence and control. Any of these activities could result in liability or significant delays in operations arising from private litigation or government action. For example, liability or delays could result from an accidental, unlawful discharge or from new conclusions about the effects of the company’s 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 14 to the Consolidated Financial Statements, beginning on page 78.
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 economic, regulatory and political 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 U.S. sanctions and other trade laws and regulations which, depending upon their scope, could adversely impact the company's operations 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.
Legislation, regulation, and other government actions 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 Chevron may be challenged by a further increase in international and domestic legislation, regulation, or other government actions relating to GHG emissions and climate change. Like any significant changes in the regulatory environment, GHG and climate change-related legislation and regulation could have the impact of curtailing profitability in the oil and gas sector or rendering the extraction of the company’s oil and gas resources economically infeasible. Although the International Energy Agency’s (IEA) World Energy Outlook scenarios anticipate oil and gas continuing to make up a significant portion of the global energy mix through 2040 and beyond, if new legislation, regulation, or other government action contributes to a decline in the demand for the company’s products, this could have a material adverse effect on the company and its financial condition.
International agreements and national, regional, and state legislation and regulatory measures that aim to limit or reduce GHG emissions are currently in various stages of implementation. For example, the Paris Agreement went into effect in November 2016, and a number of countries are studying and may adopt additional policies to meet their Paris Agreement goals. In some jurisdictions, the company is already subject to currently implemented programs such as the U.S. Renewable Fuel Standard program, the European Union Emissions Trading System, and the California cap-and-trade program and low carbon fuel standard obligations. Other 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, for example, via a carbon tax (e.g., Singapore and Canada) or via a cap-and-trade program (e.g., Mexico and China). Many governments are providing tax advantages and other incentives to promote the use of alternative energy sources or lower-carbon technologies. The landscape continues to be in a state of constant re-assessment and legal challenge with respect to these laws, regulations, and other actions, making it difficult to predict with certainty the ultimate impact they will have on the company in the aggregate.
GHG emissions-related legislation, regulations, and government actions and the effects of operating in a potentially carbon-constrained environment 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; make the company’s products more expensive; adversely affect the economic feasibility of the company’s resources; and adversely affect the company’s sales volumes, revenues, and margins. GHG emissions (e.g., carbon dioxide and methane) that could be regulated 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 consumers’ or customers’ use of the company’s hydrocarbon products. Indirect regulation of GHG emissions could include bans or restrictions on technologies that use the company’s hydrocarbon products. Many of these activities, such as consumers’ and customers’ use of the company’s products and substitute products, as well as actions taken by the company’s competitors in response to such legislation and regulations, are beyond the company’s control.
Consideration of climate change-related 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 change-related policy actions and demand response to oil and natural gas prices. The actual level of expenditure required to comply with new or potential climate change-related laws and regulations and amount of additional investments in new or existing technology or facilities, such as carbon dioxide injection, is difficult to predict with certainty and is expected to vary depending on the actual laws and regulations enacted in a jurisdiction, the company’s activities in it, and market conditions.
The ultimate effect of international agreements; national, regional, and state legislation and regulation; and government 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 the costs incurred through the pricing of the company’s products in the competitive marketplace. Further, the ultimate impact of GHG emissions and climate change-related agreements, legislation, regulation, and government actions on the company’s financial performance is highly uncertain because the company is unable to predict with certainty, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and tradeoffs that inevitably occur in connection with such processes.
Increasing attention to environmental, social, and governance (ESG) matters may impact our business Increasing attention to climate change, increasing societal expectations on companies to address climate change, and potential consumer and customer use of substitutes to Chevron’s products may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change, for example, may result in demand shifts for our hydrocarbon products and additional governmental investigations and private litigation against the company.
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. Such ratings are used by some investors to inform their investment and voting decisions. Also, some stakeholders, including but not limited to sovereign wealth, pension, and endowment funds, have been promoting divestment of fossil fuel equities and urging lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Unfavorable ESG ratings and investment community divestment initiatives 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.
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 or changes in 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. Note 16, “Properties, Plant and Equipment,” to the company’s financial statements is on page 82.

Item 3. Legal Proceedings
Item 3. Legal Proceedings
Governmental 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 refinery in Pasadena, Texas acquired by Chevron on May 1, 2019 (Pasadena Refining System, Inc. and PRSI Trading LLC) has multiple outstanding Notices of Violation (NOVs) that were issued by the Texas Commission on Environmental Quality related to air emissions at the refinery. The Pasadena refinery is currently negotiating a resolution of the NOVs with the Texas Attorney General.
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.
Noble Energy Mediterranean Ltd. (Noble Mediterranean) received a notice of intent (NOI) from Israel’s Ministry of Environmental Protection (MOEP) in April 2020 alleging breaches of the Leviathan facility’s effluent discharge permit for discharges that occurred primarily before startup of the Leviathan facility and seeking an administrative monetary sanction of 10.8 million New Israeli Shekels (NIS) (approximately 4.3 million NIS net to Noble Mediterranean’s 39.66 percent interest in the Leviathan facility), pursuant to Israel’s Prevention of Sea Pollution from Land-Based Sources Law. Upon consideration of Noble Mediterranean’s response to the NOI, the MOEP rescinded certain violations alleged in the NOI and reduced the penalty to 3.8 million NIS (approximately $1.2 million gross and $465,000 net to Noble Mediterranean’s 39.66 percent interest), which was paid on December 11, 2020.
In January 2021, the United States Department of Justice and the United States Environmental Protection Agency notified Noble Energy, Inc., Noble Midstream Partners LP and Noble Midstream Services, LLC of potential penalties for alleged Clean Water Act violations at two facilities in Weld County, Colorado relating to a 2014 flood event and requirements for a Spill Prevention and Countermeasures Plan and Facility Response Plan. The parties are negotiating a resolution of these issues with the agencies. Resolution of these alleged violations may result in the payment of a civil penalty of $1,000,000 or more.
Other Proceedings Information related to other legal proceedings is included beginning on page 78 in Note 14 to the Consolidated Financial Statements.

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” on page 27, 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, 2021, stockholders of record numbered approximately 114,000. There are no restrictions on the company’s ability to pay dividends. The information on Chevron’s dividends are contained in the Quarterly Results tabulations on page 54.
Chevron Corporation Issuer Purchases of Equity Securities for Quarter Ended December 31, 2020
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, 2020 30,243 $72.65 - $19.5
November 1 - November 30, 2020 9,850 $71.15 - $19.5
December 1 -December 31, 2020 33,819 $80.89 - $19.5
Total October 1 - December 31, 2020 73,912 $76.22 -
1Includes common shares repurchased from participants in the company's deferred compensation plans for personal income tax withholdings.
2Refer to “Liquidity and Capital Resources” on page 42 for additional detail regarding the company's authorized stock repurchase program.

Item 6. Selected Financial Data
Item 6. Selected Financial Data
The selected financial data for years 2016 through 2020 are presented on page 98.

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, Consolidated Financial Statements and Supplementary Data is presented on page 30.

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 Instrument Market Risk,” beginning on page 47 and in Note 8 to the Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning on page 72.

Item 8. Financial Statements and Supplementary Data
Item 8. Financial Statements and Supplementary Data
The index to Management’s Discussion and Analysis, Consolidated Financial Statements and Supplementary Data is presented on page 30.

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, 2020.
(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, 2020.
The company excluded Noble from our assessment of internal control over financial reporting as of December 31, 2020 because it was acquired by the company in a business combination during 2020. Total assets and total revenues of Noble, a wholly-owned subsidiary, represent eight percent and one percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2020.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2020, 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, 2020, 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
None.
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 25, 2021
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 60 Chairman of the Board and Chief Executive Officer (since Feb 2018)
Vice Chairman of the Board (Feb 2017 - Jan 2018) and Executive
Vice President, Midstream and Development (Jan 2016 - Jan 2018)
Executive Vice President, Downstream (Mar 2006 - Dec 2015) Chairman of the Board and
Chief Executive Officer
Joseph C. Geagea 61 Executive Vice President, Technology, Projects and Services
(since Jun 2015)
Senior Vice President, Technology, Projects and Services (Jan 2014 -
Jun 2015) Capital Projects; Procurement; Information Technology and Digital; Asset Performance; Health, Safety and Environment; Real Estate Services
James W. Johnson 61 Executive Vice President, Upstream (since Jun 2015)
Senior Vice President, Upstream (Jan 2014 - Jun 2015) Worldwide Exploration and Production Activities
Mark A. Nelson 57 Executive Vice President, Downstream (since Mar 2019)
Vice President, Midstream, Strategy and Policy (Feb 2018 - Feb
2019)
Vice President, Strategic Planning (Apr 2016 - Jan 2018)
President, International Products (Jun 2010 - Mar 2016) Worldwide Manufacturing, Marketing and Lubricants; Chemicals
Pierre R. Breber 56 Vice President and Chief Financial Officer (since Apr 2019)
Executive Vice President, Downstream (Jan 2016 - Mar 2019)
Executive Vice President, Gas and Midstream (Apr 2015 - Dec 2015)
Vice President, Gas and Midstream (Jan 2014 - Mar 2015) Finance
Rhonda J. Morris 55 Vice President and Chief Human Resources Officer (since Feb 2019)
Vice President, Human Resources (Oct 2016 - Jan 2019)
Vice President, Downstream Human Resources (Sep 2012 - Sep
2016) Human Resources; Diversity and Inclusion
Colin E. Parfitt 56 Vice President, Midstream (since Mar 2019)
President, Supply and Trading (Jun 2013 - Feb 2019) Supply and Trading Activities; Shipping; Pipeline; Power and Energy Management
R. Hewitt Pate 58 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 2021 Annual Meeting of Stockholders and 2021 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Exchange Act in connection with the company’s 2021 Annual Meeting (the 2021 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 2021 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 2021 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,” “CEO Pay Ratio” and “Director Compensation” in the 2021 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(e)(4) of Regulation S-K and contained under the heading “Corporate Governance - Board Committees” in the 2021 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 2021 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 2021 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 2021 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 2021 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 2021 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 2021 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

Item 14. Principal Accountant Fees and Services
Item 14. Principal Accounting 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 2021” in the 2021 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
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Financial Table of Contents
Management's Discussion and Analysis of Financial Condition and Results of Operations
Key Financial Results
Millions of dollars, except per-share amounts 2020 2019 2018
Net Income (Loss) Attributable to Chevron Corporation $ (5,543) $ 2,924 $ 14,824
Per Share Amounts:
Net Income (Loss) Attributable to Chevron Corporation
- Basic $ (2.96) $ 1.55 $ 7.81
- Diluted $ (2.96) $ 1.54 $ 7.74
Dividends $ 5.16 $ 4.76 $ 4.48
Sales and Other Operating Revenues $ 94,471 $ 139,865 $ 158,902
Return on:
Capital Employed (2.8) % 2.0 % 8.2 %
Stockholders’ Equity (4.0) % 2.0 % 9.8 %
Earnings by Major Operating Area
Millions of dollars 2020 2019 2018
Upstream
United States $ (1,608) $ (5,094) $ 3,278
International (825) 7,670 10,038
Total Upstream (2,433) 2,576 13,316
Downstream
United States (571) 1,559 2,103
International 618 922 1,695
Total Downstream 47 2,481 3,798
All Other (3,157) (2,133) (2,290)
Net Income (Loss) Attributable to Chevron Corporation1,2
$ (5,543) $ 2,924 $ 14,824
1 Includes foreign currency effects:
$ (645) $ (304) $ 611
2 Income net of tax, also referred to as “earnings” in the discussions that follow.
Refer to the “Results of Operations” section beginning on page 37 for a discussion of financial results by major operating area for the three years ended December 31, 2020.
Business Environment and Outlook
Chevron is a global energy company with substantial business activities in the following countries: Angola, Argentina, Australia, Bangladesh, Brazil, Canada, China, Egypt, Equatorial Guinea, Indonesia, Israel, Kazakhstan, Kurdistan Region of Iraq, Myanmar, 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 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 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 and exploratory expenditures, along with other measures intended to improve financial performance. Similarly, impairments or write-offs have occurred, and may occur in the future, as a result of managerial decisions not to progress certain projects in the company’s portfolio.
With ongoing global interest in addressing the risks of climate change, support for policies and advancements in lower carbon technologies is expected. In seeking to help advance a lower carbon future, Chevron is focused on lowering its carbon intensity cost efficiently, increasing renewables and offsets in support of its business, and investing in low-carbon technologies to enable commercial solutions.
Response to Market Conditions and COVID-19 During most of 2020, travel restrictions and other constraints on economic activity designed to limit the spread of the COVID-19 virus were implemented in many locations around the world. These constraints reduced demand for our products, and commodity prices fell, negatively impacting the company’s 2020 financial and operating results. While demand and commodity prices have shown signs of recovery, demand is not back to pre-pandemic levels, and financial results will likely continue to be challenged in future quarters. Due to the rapidly
Management's Discussion and Analysis of Financial Condition and Results of Operations
changing environment, there continues to be uncertainty and unpredictability around the extent to which the COVID-19 pandemic will impact our future results, which could be material.
Chevron entered this crisis well positioned with a strong balance sheet, flexible capital program and low cash flow breakeven price. To protect its long-term health and value, the company took swift action, adjusting the items it can control. The company lowered its capital expenditures 35 percent and lowered its operating expense, excluding non-recurring severance costs, by $1.4 billion compared to 2019. The company completed an enterprise-wide transformation that is expected to capture additional cost efficiencies. Additionally, the company suspended its stock repurchase program in March 2020. Taken together, these actions are consistent with our financial priorities: to protect the dividend, to prioritize capital spend that drives long-term value, and to maintain a strong balance sheet. The company expects to continue to have sufficient liquidity and access to both commercial paper and debt capital markets due to its strong balance sheet and investment grade credit ratings. Additionally, the company has access to nearly $10 billion in committed credit facilities.
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 both by 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. Note 15 provides the company’s effective income tax rate for the last three years.
Refer to the “Cautionary Statements Relevant to Forward-Looking Information” on page 2 and to “Risk Factors” in Part I, Item 1A, on pages 18 through 23 for a discussion of some of the inherent risks that could materially impact the company’s results of operations or financial condition.
The company continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value or 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’s asset sale program for 2018 through 2020 targeted before-tax proceeds of $5-10 billion. For the three year period ending December 31, 2020, assets sales proceeds totaled $7.7 billion, in the middle of the guidance range.
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.
Comments related to earnings trends for the company’s major business areas are as follows:
Upstream Earnings for the upstream segment are closely aligned with industry prices for crude oil 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 the Organization of Petroleum Exporting Countries (OPEC) or other producers, 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, and changes in tax and other applicable laws and regulations.
The company is actively managing its schedule of work, contracting, procurement, and supply chain activities to effectively manage costs and ensure supply chain resiliency and continuity in support of 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: the general level of 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, so there may be a lag before the company’s costs reflect the changes in market trends.
The spot markets and some of the current cost indexes for many materials and services have stabilized. Crude oil and natural gas prices and demand have rebounded from lows of the early pandemic though demand still has not returned to pre-pandemic levels. Drilling activity in the U.S. has risen slowly but steadily through the end of the year. The timing and
Management's Discussion and Analysis of Financial Condition and Results of Operations
trajectory of any increase in the cost of materials and services going forward will depend on the extent of the oil and gas industry recovery. Correlated with these initial signs of industry recovery and cost stabilization was a noticeable improvement in the risk of default for key suppliers. To date, there have been no material impacts to operations due to supplier defaults. Chevron is actively monitoring and engaging key suppliers to mitigate any potential business impacts.
Capital and exploratory expenditures and operating expenses could also be affected by damage to production facilities caused by severe weather or civil unrest, delays in construction, or other factors.
The chart above 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 $42 per barrel for the full-year 2020, compared to $64 in 2019. As of mid-February 2021, the Brent price was $64 per barrel. The WTI price averaged $39 per barrel for the full-year 2020, compared to $57 in 2019. As of mid-February 2021, the WTI price was $60 per barrel. The majority of the company’s equity crude production is priced based on the Brent benchmark.
Crude prices sharply declined at the end of the first and into the second quarter 2020 due to surplus supply as demand decreased following government-imposed travel restrictions and other constraints on economic activity. In the second half of 2020, the supply/demand balance slowly improved, primarily due to production cuts and demand growth, allowing prices to somewhat recover. The company’s average realization for U.S. crude oil and natural gas liquids in 2020 was $31 per barrel, down 37 percent from 2019. The company’s average realization for international crude oil and natural gas liquids in 2020 was $36 per barrel, down 38 percent from 2019.
Prices for natural gas are more closely aligned with seasonal supply-and-demand and infrastructure conditions in local markets. In the United States, prices at Henry Hub averaged $1.98 per thousand cubic feet (MCF) during 2020, compared with $2.53 per MCF during 2019. As of mid-February 2021, the Henry Hub spot price increased to $6.00 per MCF amid freezing temperatures across much of the United States.
Outside the United States, prices for natural gas 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 the remainder to be sold in the Asian spot LNG market. International natural gas realizations averaged $4.59 per MCF during 2020, compared with $5.83 per MCF during 2019. (See page 41 for the company’s average natural gas realizations for the U.S. and international regions.)
The company’s worldwide net oil-equivalent production in 2020 averaged 3.083 million barrels per day. About 14 percent of the company’s net oil-equivalent production in 2020 occurred in the OPEC-member countries of Angola, Equatorial Guinea, Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait, Republic of Congo and Venezuela.
The company estimates that net oil-equivalent production in 2021 will grow up to 3 percent compared to 2020, assuming a Brent crude oil price of $50 per barrel and excluding the impact of anticipated 2021 asset sales. This estimate is subject to many factors and uncertainties, including quotas or other actions that may be imposed by OPEC+; price effects on entitlement volumes; changes in fiscal terms or restrictions on the scope of company operations; delays in construction; reservoir performance; greater-than-expected declines in production from mature fields; start-up or ramp-up of projects; 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
Management's Discussion and Analysis of Financial Condition and Results of Operations
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, but these too are under pressure in the current market environment.
In the Partitioned Zone between Saudi Arabia and Kuwait, production was shut-in beginning in May 2015. In December 2019, the governments of Saudi Arabia and Kuwait signed a memorandum of understanding to allow production to restart in the Partitioned Zone. In mid-February 2020, pre-startup activities commenced, and production resumed in July 2020. The financial effects from the loss of production in 2019 and first half 2020 were not significant. During the fourth quarter 2020, oil equivalent production in the Partitioned Zone averaged 40 thousand barrels per day.
Chevron has interests in Venezuelan crude oil assets, including those operated by Petropiar, Petroboscan and Petroindependiente. While the operating environment in Venezuela has been deteriorating for some time, Petropiar, Petroboscan, and Petroindependiente have conducted activities consistent with the authorization provided pursuant to general licenses issued by the United States government. During the second quarter 2020, the company completed its evaluation of the carrying value of its Venezuelan investments in line with its accounting policies and concluded that given the current operating environment and overall outlook, which created significant uncertainties regarding the recovery of the company’s investment, an other than temporary loss of value had occurred, which resulted in a full impairment of its investment in the country totaling $2.6 billion and change in accounting treatment from equity method to non-equity method of accounting. As a result, the company also removed approximately 160 million barrels of proved reserves and stopped reporting production in the country effective July 2020. The company remains committed to its people, assets and operations in Venezuela.
Net proved reserves for consolidated companies and affiliated companies totaled 11.1 billion barrels of oil-equivalent at year-end 2020, a decrease of 3 percent from year-end 2019. The reserve replacement ratio in 2020 was 74 percent. The 5 and 10 year reserve replacement ratios were 99 percent and 106 percent, respectively. Refer to Table V beginning on page 103 for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2018 and each year-end from 2018 through 2020, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2020.
Response to Market Conditions and COVID-19: Upstream Travel restrictions and other constraints on global economic activity in 2020 in response to COVID-19 caused a significant decrease in demand for oil and gas. This led to lower price realizations across all commodities. While critical asset integrity and reliability activities progressed throughout the year,
Management's Discussion and Analysis of Financial Condition and Results of Operations
locations with high COVID-19 infection rates deferred non-essential work and demobilized non-essential personnel to reduce the COVID-19 exposure risk to our workforce.
Despite the challenges posed by the pandemic, progress continues on the FGP/WPMP project at Tengiz. In the second quarter the project construction workforce was demobilized to 20 percent of planned levels, which slowed the overall construction pace. In the third quarter, the rate of infections in Kazakhstan slowed, allowing remobilization of the FGP/WPMP construction workforce to begin. In the fourth quarter, staffing levels at FGP/WPMP returned to 95 percent of desired fourth quarter remobilization levels, however a worldwide resurgence of infections prevented the remaining 5 percent of the workforce from returning to work and slowed progress on the project. Extended rotations, COVID testing and isolation protocols are in place to minimize the spread of the virus. Given the uncertain timeline for remobilizing all personnel and safely sustaining activity levels, it is too early to provide meaningful information regarding impacts on project cost and schedule.
Facility maintenance turnarounds are being adjusted and, in certain cases, deferred into 2021. In some cases, turnarounds have been extended in duration and/or reduced in scope in response to the pandemic. As a result of the reduction in capital expenditures, new production is expected to be lower in the near term as drilling and completion activities are scaled back, most notably in the Permian Basin, Gulf of Mexico, and Argentina. Exploration activities and projects not yet in execution phase have been deferred, which may impact production in future years.
Production levels were curtailed in 2020 largely because of reductions imposed by OPEC+ nations in Kazakhstan, Nigeria and Angola. In the fourth quarter, OPEC+ curtailments eased slightly relative to the third quarter. Production has also been curtailed due to market conditions, most notably in Thailand. Additionally, operators of assets where the company has non-operated interests also curtailed production. Production curtailments of approximately 106 thousand barrels of oil equivalent per day were recorded in 2020. In the first quarter of 2021, we expect curtailments to be approximately 40 thousand barrels of oil equivalent per day, predominately related to OPEC+ restrictions.
Decreased capital expenditures, lower activity levels, delays in future development timing, and lower commodity prices have resulted in reductions to Chevron’s proved reserve quantities for 2020. For more information on reserves, refer to Table V beginning on page 103.
As some countries face a resurgence of the virus, regulatory and in-country conditions could impact logistics and material movement and pose a risk to business continuity. We are taking precautionary measures to reduce the risk of exposure to and spread of the COVID-19 virus through screening, testing and, when appropriate, quarantining workforce and visitors upon arrival to our operated facilities.
Refer to the “Results of Operations” section on pages 37 and 38 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, and petrochemicals. 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 laws and regulations.
The company’s most significant marketing areas are the West Coast and Gulf Coast of the United States and Asia. Chevron operates or has significant ownership interests in refineries in each of these areas.
Response to Market Conditions and COVID-19: Downstream Beginning in March 2020 and continuing into the first quarter 2021, demand for refined products (primarily jet fuel and motor gasoline) has been below prior year levels as a result of travel restrictions and other constraints on economic activity implemented in many countries to combat the spread of the COVID-19 virus. Product prices also fell sharply, and although economic activity has somewhat rebounded from lows experienced in April, refining margins continued to be at or near historic lows due to lower demand and pressure from
Management's Discussion and Analysis of Financial Condition and Results of Operations
a global oil product surplus. Chevron continued to take steps to maximize diesel production, given the decline in jet fuel and motor gasoline demand, to fuel transportation that keeps global supply chains moving. The company is actively monitoring supply and demand dynamics as every region is experiencing different recovery trends. The company is adjusting the schedule for planned maintenance activity across its refining network and idling certain processing units to adjust for lower demand, reduce costs, manage inventories and, most importantly, protect the safety of employees and contractors.
As of mid-February 2021, Chevron’s refining crude utilization was approximately 80 to 85 percent and sales were down year-over-year approximately 50 percent for jet fuel, approximately 5 percent for motor gasoline, while diesel sales were relatively flat. It is unclear how long these conditions will persist, but the company will continue to take actions necessary to protect the health and well-being of people, the environment and its operations as conditions evolve. Refer to the “Results of Operations” section on page 38 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.
Operating Developments
Key operating developments and other events during 2020 and early 2021 included the following:
Upstream
Azerbaijan Completed the sale of the company's interest in the Azeri-Chirag-Gunashli fields and Baku-Tbilisi-Ceyhan pipeline.
Colombia Completed the sale of the company's interest in the offshore Chuchupa and onshore Ballena natural gas fields.
Philippines Completed the sale of the company's interest in the Malampaya field in March.
United States Completed the acquisition of Noble Energy, Inc.
United States Completed the sale of the Appalachia natural gas business.
Downstream
Australia Completed the acquisition of Puma Energy (Australia) Holdings Pty Ltd.
Other
United States Chevron’s joint venture, CalBioGas LLC, successfully achieved first renewable natural gas production from dairy farms in California and marketed it as an alternative fuel for heavy-duty trucks and buses.
United States Announced the formation of a joint venture with Brightmark LLC to produce and market renewable natural gas.
United States Announced an investment in Zap Energy Inc., a start-up company developing a next-generation modular nuclear reactor.
United States Announced an investment in Blue Planet Systems Corporation, a startup that manufactures and develops carbonate aggregates and carbon capture technology intended to reduce the carbon intensity of industrial operations.
United States Announced an agreement with Algonquin Power & Utilities Corp. seeking to co-develop renewable power projects that will provide electricity to strategic assets across Chevron’s global portfolio. Under the four-year agreement, Chevron plans to generate more than 500 megawatts of its energy demand from renewable sources.
United States Announced a non-binding offer in February 2021 to acquire the outstanding common units of Noble Midstream Partners LP not already owned by Chevron.
Common Stock Dividends The 2020 annual dividend was $5.16 per share, making 2020 the 33rd consecutive year that the company increased its annual per share dividend payout. In January 2021, the company’s Board of Directors declared a quarterly dividend of $1.29 per share.
Common Stock Repurchase Program The company purchased $1.75 billion of its common stock in 2020 under its stock repurchase programs. The stock repurchase program was suspended in March 2020.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Results of Operations
The following section presents the results of operations and variances on an after-tax basis for the company’s business segments - Upstream and Downstream - as well as for “All Other.” Earnings are also presented for the U.S. and international geographic areas of the Upstream and Downstream business segments. Refer to Note 12, beginning on page 74, 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” on pages 31 through 36. Refer to the “Selected Operating Data” table on page 41 for a three-year comparison of production volumes, refined product sales volumes, and refinery inputs. A discussion of variances between 2019 and 2018 can be found in the “Results of Operations” section on pages 33 through 34 of the company’s 2019 Annual Report on Form 10-K filed with the SEC on February 22, 2020.
U.S. Upstream
Millions of dollars 2020 2019 2018
Earnings (Loss) $ (1,608) $ (5,094) $ 3,278
U.S. upstream reported a loss of $1.61 billion in 2020, compared with a loss of $5.09 billion in 2019. The smaller loss was largely due to the absence of fourth quarter 2019 impairment charges of $8.17 billion, primarily associated with Appalachia shale and Big Foot, partially offset by lower crude oil realizations of $3.36 billion and second quarter 2020 impairments and write-offs of $1.20 billion.
The company’s average realization for U.S. crude oil and natural gas liquids in 2020 was $30.53 per barrel compared with $48.54 in 2019. The average natural gas realization was $0.98 per thousand cubic feet in 2020, compared with $1.09 in 2019.
Net oil-equivalent production in 2020 averaged 1.06 million barrels per day, up 14 percent from 2019. Production increases from shale and tight properties in the Permian Basin and 58,000 barrels per day of production from the Noble acquisition were partially offset by normal field declines.
The net liquids component of oil-equivalent production for 2020 averaged 790,000 barrels per day, up 9 percent from 2019. Net natural gas production averaged 1.61 billion cubic feet per day in 2020, up 31 percent from 2019.
International Upstream
Millions of dollars 2020 2019 2018
Earnings (Loss)*
$ (825) $ 7,670 $ 10,038
*Includes foreign currency effects:
$ (285) $ (323) $ 545
International upstream reported a loss of $825 million in 2020, compared with earnings of $7.67 billion in 2019. The decrease was primarily due to lower crude oil and natural gas realizations of $4.6 billion and $1.2 billion, respectively,
Management's Discussion and Analysis of Financial Condition and Results of Operations
higher charges of $1.4 billion for impairments and write-offs (charges of $3.6 billion in 2020 compared to $2.2 billion in 2019), and lower crude oil sales volumes of $1.1 billion. Lower gains on asset sales of $730 million also contributed to the decrease and were largely offset by lower operating expenses of $710 million. Foreign currency effects had a favorable impact on earnings of $38 million between periods.
The company’s average realization for international crude oil and natural gas liquids in 2020 was $36.07 per barrel compared with $58.14 in 2019. The average natural gas realization was $4.59 per thousand cubic feet in 2020 compared with $5.83 in 2019.
International net oil-equivalent production was 2.03 million barrels per day in 2020, down 5 percent from 2019. The decrease was due to production curtailments associated with OPEC+ restrictions and market conditions, and asset sale related decreases of 94,000 barrels per day, partially offset by higher production entitlement effects and volumes associated with the Noble acquisition.
The net liquids component of international oil-equivalent production was 1.08 million barrels per day in 2020, down 6 percent from 2019. International net natural gas production of 5.68 billion cubic feet per day in 2020 decreased 4 percent from 2019.
U.S. Downstream
Millions of dollars 2020 2019 2018
Earnings (Loss) $ (571) $ 1,559 $ 2,103
U.S. downstream reported a loss of $571 million in 2020, compared with earnings of $1.56 billion in 2019. The decrease was primarily due to lower margins on refined product sales of $1.08 billion and lower sales volumes of $1.00 billion. Lower equity earnings from the 50 percent-owned CPChem of $220 million also contributed to the decrease. These were partially offset by lower operating expenses of $220 million.
Total refined product sales of 1.00 million barrels per day in 2020 were down 20 percent from 2019, mainly due to lower jet fuel, gasoline, and diesel demand associated with the COVID-19 pandemic.
International Downstream
Millions of dollars 2020 2019 2018
Earnings*
$ 618 $ 922 $ 1,695
*Includes foreign currency effects:
$ (152) $ 17 $ 71
International downstream earned $618 million in 2020, compared with $922 million in 2019. The decrease in earnings was largely due to lower margins on refined product sales of $160 million, primarily resulting from unfavorable inventory effects. Unfavorable tax items of $110 million also contributed to the decrease. Partially offsetting the decrease in earnings were lower operating expenses of $130 million. Foreign currency effects had an unfavorable impact on earnings of $169 million between periods.
Total refined product sales of 1.22 million barrels per day in 2020 were down 8 percent from 2019, mainly due to lower jet fuel demand associated with the COVID-19 pandemic.
All Other
Millions of dollars 2020 2019 2018
Net charges*
$ (3,157) $ (2,133) $ (2,290)
*Includes foreign currency effects:
$ (208) $ 2 $ (5)
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 2020 increased $1.02 billion from 2019. The change between periods was mainly due to the absence of the second quarter 2019 Anadarko merger termination fee, higher pension expenses, severance and Noble acquisition costs, partially offset by the absence of a prior year tax charge and favorable tax items. Foreign currency effects increased net charges by $210 million between periods.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Consolidated Statement of Income
Comparative amounts for certain income statement categories are shown below. A discussion of variances between 2019 and 2018 can be found in the “Consolidated Statement of Income” section on pages 34 through 36 of the company’s 2019 Annual Report on Form 10-K.
Millions of dollars 2020 2019 2018
Sales and other operating revenues $ 94,471 $ 139,865 $ 158,902
Sales and other operating revenues decreased in 2020 mainly due to lower refined product, crude oil and natural gas prices, and lower refined product volumes.
Millions of dollars 2020 2019 2018
Income (loss) from equity affiliates $ (472) $ 3,968 $ 6,327
Income from equity affiliates decreased in 2020 mainly due to the full impairment of Petropiar and Petroboscan in Venezuela and lower upstream-related earnings from Tengizchevroil in Kazakhstan.
Refer to Note 13, beginning on page 77, for a discussion of Chevron’s investments in affiliated companies.
Millions of dollars 2020 2019 2018
Other income $ 693 $ 2,683 $ 1,110
Other income decreased in 2020 mainly due to the absence of the receipt of the 2019 Anadarko merger termination fee, lower gains on asset sales and unfavorable swings in foreign currency effects.
Millions of dollars 2020 2019 2018
Purchased crude oil and products $ 50,488 $ 80,113 $ 94,578
Crude oil and product purchases decreased $29.6 billion in 2020, primarily due to lower crude oil and refined product prices and lower refined product and crude oil volumes.
Millions of dollars 2020 2019 2018
Operating, selling, general and administrative expenses $ 24,536 $ 25,528 $ 24,382
Operating, selling, general and administrative expenses decreased $1.0 billion in 2020. The decrease is primarily due to lower services and fees, expenses for non-operated upstream properties, materials and supplies expense and lower transportation expense, partially offset by higher severance costs.
Millions of dollars 2020 2019 2018
Exploration expense $ 1,537 $ 770 $ 1,210
Exploration expenses in 2020 increased primarily due to higher charges for well write-offs.
Millions of dollars 2020 2019 2018
Depreciation, depletion and amortization $ 19,508 $ 29,218 $ 19,419
Depreciation, depletion and amortization expenses decreased in 2020 primarily due to lower impairments.
Millions of dollars 2020 2019 2018
Taxes other than on income $ 4,499 $ 4,136 $ 4,867
Taxes other than on income increased in 2020 primarily due to higher regulatory expenses and property taxes, partially offset by lower taxes on production, payroll tax and sales and use tax.
Millions of dollars 2020 2019 2018
Interest and debt expense $ 697 $ 798 $ 748
Interest and debt expenses decreased in 2020 mainly due to lower interest rates, partially offset by higher debt balances.
Millions of dollars 2020 2019 2018
Other components of net periodic benefit costs $ 880 $ 417 $ 560
Other components of net periodic benefit costs increased in 2020 primarily due to higher pension settlement costs.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Millions of dollars 2020 2019 2018
Income tax expense (benefit) $ (1,892) $ 2,691 $ 5,715
The decrease in income tax expense in 2020 of $4.58 billion is due to the decrease in total income before tax for the company of $12.99 billion. The decrease in income before taxes for the company is primarily the result of lower crude oil prices partially offset by lower impairments and project write off charges.
U.S. income before tax decreased from a loss of $5.48 billion in 2019 to a loss of $5.70 billion in 2020. This decrease in earnings before tax was primarily driven by the effect of lower crude oil prices in the U.S. and the absence of the Anadarko merger fee, partially offset by lower impairment charges and higher production. The U.S. tax benefit increased from $1.17 billion in 2019 to $1.58 billion in 2020 primarily due to the increase in before-tax loss.
International income before tax decreased from $11.02 billion in 2019 to a loss of $1.75 billion in 2020. This decrease was primarily driven by the effect of lower crude oil and natural gas prices, lower production, higher impairments and other charges. The lower before-tax income primarily drove the $4.17 billion decrease in international income tax expense, from a charge of $3.86 billion in 2019 to a benefit of $308 million in 2020.
Refer also to the discussion of the effective income tax rate in Note 15 beginning on page 79.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Selected Operating Data1,2
2020 2019 2018
U.S. Upstream
Net Crude Oil and Natural Gas Liquids Production (MBPD) 790 724 618
Net Natural Gas Production (MMCFPD)3
1,607 1,225 1,034
Net Oil-Equivalent Production (MBOEPD) 1,058 929 791
Sales of Natural Gas (MMCFPD) 3,894 4,016 3,481
Sales of Natural Gas Liquids (MBPD) 208 130 110
Revenues from Net Production
Liquids ($/Bbl) $ 30.53 $ 48.54 $ 58.17
Natural Gas ($/MCF) $ 0.98 $ 1.09 $ 1.86
International Upstream
Net Crude Oil and Natural Gas Liquids Production (MBPD)4
1,078 1,141 1,164
Net Natural Gas Production (MMCFPD)3
5,683 5,932 5,855
Net Oil-Equivalent Production (MBOEPD)4
2,025 2,129 2,139
Sales of Natural Gas (MMCFPD) 5,634 5,869 5,604
Sales of Natural Gas Liquids (MBPD) 46 34 34
Revenues from Liftings
Liquids ($/Bbl) $ 36.07 $ 58.14 $ 64.25
Natural Gas ($/MCF) $ 4.59 $ 5.83 $ 6.29
Worldwide Upstream
Net Oil-Equivalent Production (MBOEPD)4
United States 1,058 929 791
International 2,025 2,129 2,139
Total 3,083 3,058 2,930
U.S. Downstream
Gasoline Sales (MBPD)5
581 667 627
Other Refined Product Sales (MBPD) 422 583 591
Total Refined Product Sales (MBPD) 1,003 1,250 1,218
Sales of Natural Gas Liquids (MBPD) 25 101 74
Refinery Input (MBPD)6
793 947 905
International Downstream
Gasoline Sales (MBPD)5
264 289 336
Other Refined Product Sales (MBPD) 957 1,038 1,101
Total Refined Product Sales (MBPD)7
1,221 1,327 1,437
Sales of Natural Gas Liquids (MBPD) 74 72 62
Refinery Input (MBPD)8
584 617 706
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 37 36 35
International 566 602 584
4 Includes net production of synthetic oil:
Canada 54 53 53
Venezuela affiliate - 3 24
5 Includes branded and unbranded gasoline.
6 In May 2019, the company acquired the Pasadena Refinery in Pasadena, Texas, which has an operable capacity of 110,000 barrels per day.
7 Includes sales of affiliates (MBPD):
348 379 373
8 In September 2018, the company sold its interest in the Cape Town Refinery in Cape Town, South Africa, which had an operable capacity of 110,000 barrels per day.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Liquidity and Capital Resources
Sources and uses of cash
The strength of the company’s balance sheet enabled it to fund any timing differences throughout the year between cash inflows and outflows.
Cash, Cash Equivalents, Marketable Securities and Time Deposits Total balances were $5.6 billion and $5.7 billion at December 31, 2020 and 2019, respectively. Cash provided by operating activities in 2020 was $10.6 billion, compared to $27.3 billion in 2019, primarily due to lower crude oil prices. Cash provided by operating activities was net of contributions to employee pension plans of approximately $1.2 billion in 2020 and $1.4 billion in 2019. Cash provided by investing activities included proceeds and deposits related to asset sales of $2.9 billion in 2020 and $2.8 billion in 2019.
Restricted cash of $1.1 billion and $1.2 billion at December 31, 2020 and 2019, 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, funds held in escrow for tax-deferred exchanges and refundable deposits related to pending asset sales.
Dividends Dividends paid to common stockholders were $9.7 billion in 2020 and $9.0 billion in 2019.
Debt and Finance Lease Liabilities Total debt and finance lease liabilities were $44.3 billion at December 31, 2020, up from $27.0 billion at year-end 2019.
The $17.3 billion increase in total debt and finance lease liabilities during 2020 was primarily due to the company's issuance of long-term public bonds of $8.0 billion in May 2020 and $4.0 billion in August 2020, and the assumption of debt with a fair value of $9.4 billion as part of the transaction to acquire Noble in October 2020. In January 2021, Chevron U.S.A. Inc. (CUSA) issued bonds, guaranteed by Chevron Corporation, in exchange for the Noble debt. More information on bond issuances is included in Note 18 on page 84. These amounts were partially offset by repayment of long-term notes that matured in 2020. The company’s debt and finance lease liabilities due within one year, consisting primarily of commercial paper, redeemable long-term obligations and the current portion of long-term debt, totaled $11.4 billion at December 31, 2020, compared with $13.0 billion at year-end 2019. Of these amounts, $9.825 billion and $9.75 billion were reclassified to long-term debt at the end of 2020 and 2019, respectively.
At year-end 2020, settlement of these obligations was not expected to require the use of working capital in 2021, 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 an automatic shelf registration statement that expires in August 2023 for an unspecified amount of nonconvertible debt securities issued by Chevron Corporation or CUSA.
Management's Discussion and Analysis of Financial Condition and Results of Operations
The major debt rating agencies routinely evaluate the company’s debt, and the company’s cost of borrowing can increase or decrease depending on these debt ratings. The company has outstanding public bonds issued by Chevron Corporation, CUSA, 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 flexibility to modify capital spending plans and discontinue or curtail the stock repurchase program to provide flexibility to continue paying the common stock dividend and also remain committed to retaining the company’s high-quality debt ratings.
Committed Credit Facilities Information related to committed credit facilities is included in Note 17, Short-Term Debt, on page 83.
Summarized Financial Information for Guarantee of Securities of Subsidiaries In August 2020, long-term public bonds were issued by CUSA and fully and unconditionally guaranteed on an unsecured basis by Chevron Corporation (together the “Obligor Group”). In March 2020, the U.S. Securities and Exchange Commission (SEC) issued a final rule that amended the disclosure requirements with respect to certain guaranteed securities registered or being registered in Rule 3-10 of Regulation S-X and adopted new Rule 13-01 of Regulation S-X. These amendments were effective January 4, 2021. Accordingly, as disclosed in the tables below, summary financial information is presented 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, 2020 Year Ended
December 31, 2019
(Millions of dollars) (unaudited)
Sales and other operating revenues $ 49,636 $ 82,206
Sales and other operating revenues - related party 17,044 24,336
Total costs and other deductions 57,575 87,287
Total costs and other deductions - related party 14,052 22,632
Net income (loss) $ (1,610) $ 2,173
At December 31,
2020 At December 31,
(Millions of dollars) (unaudited)
Current assets $ 9,196 $ 10,180
Current assets - related party 5,719 952
Other assets 48,993 50,595
Current liabilities 20,965 25,187
Current liabilities - related party 55,273 46,237
Other liabilities 34,983 25,622
Total net equity (deficit) $ (47,313) $ (35,319)
Common Stock Repurchase Program On February 1, 2019, the company announced that the Board of Directors authorized a new stock repurchase program with a maximum dollar limit of $25 billion and no set term limits. As of December 31, 2020, the company had purchased a total of 48.6 million shares for $5.5 billion, resulting in $19.5 billion remaining under the program authorized in February 2019. On March 24, 2020, the company announced the suspension of the stock repurchase program in response to depressed market conditions following the global outbreak of the COVID-19 pandemic. No shares were purchased under the program after this announcement.
Repurchases may be made from time to time in the open market, by block purchases, in privately negotiated transactions or in such other manner as determined by the company. The timing of the repurchases and the actual amount repurchased will depend on a variety of factors, including the market price of the company’s shares, general market and economic
Management's Discussion and Analysis of Financial Condition and Results of Operations
conditions, and other factors. The stock repurchase program does not obligate the company to acquire any particular amount of common stock, and it may be suspended or discontinued at any time.
Capital and Exploratory Expenditures
Capital and exploratory expenditures by business segment for 2020, 2019 and 2018 are as follows:
2020 2019 2018
Millions of dollars U.S. Int’l. Total U.S. Int’l. Total U.S. Int’l. Total
Upstream $ 5,130 $ 5,784 $ 10,914 $ 8,197 $ 9,627 $ 17,824 $ 7,128 $ 10,529 $ 17,657
Downstream 1,021 1,325 2,346 1,868 920 2,788 1,582 611 2,193
All Other 226 13 239 365 17 382 243 13 256
Total $ 6,377 $ 7,122 $ 13,499 $ 10,430 $ 10,564 $ 20,994 $ 8,953 $ 11,153 $ 20,106
Total, Excluding Equity in Affiliates $ 6,053 $ 3,464 $ 9,517 $ 10,062 $ 4,820 $ 14,882 $ 8,651 $ 5,739 $ 14,390
Total reported expenditures for 2020 were $13.5 billion, including $4.0 billion for the company’s share of equity-affiliate expenditures, which did not require cash outlays by the company. The acquisition of Noble is not included in the company’s capital and exploratory expenditures. For more information on the Noble acquisition, see page 96 in Note 29. In 2019, expenditures were $21.0 billion, including the company’s share of affiliates’ expenditures of $6.1 billion.
Of the $13.5 billion of expenditures in 2020, 81 percent, or $10.9 billion, related to upstream activities. Approximately 85 percent was expended for upstream operations in 2019. International upstream accounted for 53 percent of the worldwide upstream investment in 2020 and 54 percent in 2019.
The company estimates that 2021 organic capital and exploratory expenditures will be $14 billion, including $4.2 billion of spending by affiliates. This is in line with 2020 expenditures, and reflects a robust portfolio of upstream and downstream investments, highlighted by the FGP/WPMP project at the Tengiz field in Kazakhstan and the company’s Permian Basin position. In the upstream business, approximately $6.5 billion is allocated to currently producing assets, including about $2.0 billion for Permian unconventional development. Approximately $3.5 billion of the upstream program is planned for major capital projects underway, of which about 75 percent is associated with FGP/WPMP at the Tengiz field in Kazakhstan. Additionally, $1.5 billion is allocated to exploration, early stage development projects, and midstream activities. The company monitors crude oil market conditions and is able to adjust future capital outlays should oil price conditions deteriorate.
Worldwide downstream spending in 2021 is estimated to be $2.1 billion, with $1.2 billion estimated for projects in the United States.
Investments in technology businesses and other corporate operations in 2021 are budgeted at $0.4 billion.
Noncontrolling Interests The company had noncontrolling interests of $1.0 billion at December 31, 2020 and $1.0 billion at December 31, 2019. Distributions to noncontrolling interests totaled $24 million and $18 million in 2020 and 2019, respectively. Included within noncontrolling interests for 2020 is $120 million of redeemable noncontrolling interest associated with Noble Midstream.
Pension Obligations Information related to pension plan contributions is included beginning on page 87 in Note 21, Employee Benefit Plans, under the heading “Cash Contributions and Benefit Payments.”
Management's Discussion and Analysis of Financial Condition and Results of Operations
Financial Ratios and Metrics
The following represent several metrics the company believes are useful measures to monitor the financial health of the company and its performance over time:
Current Ratio Current assets divided by current liabilities, which indicates the company’s ability to repay its short-term liabilities with short-term assets. The current ratio in all periods was adversely affected by the fact that Chevron’s inventories are valued on a last-in, first-out basis. At year-end 2020, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $2.7 billion.
At December 31
Millions of dollars 2020 2019 2018
Current assets $ 26,078 $ 28,329 $ 34,021
Current liabilities 22,183 26,530 27,171
Current Ratio 1.2 1.1 1.3
Interest Coverage Ratio Income before income tax expense, plus interest and debt expense and amortization of capitalized interest, less net income attributable to noncontrolling interests, divided by before-tax interest costs. This ratio indicates the company’s ability to pay interest on outstanding debt. The company’s interest coverage ratio in 2020 was lower than 2019 due to lower income.
Year ended December 31
Millions of dollars 2020 2019 2018
Income (Loss) Before Income Tax Expense $ (7,453) $ 5,536 $ 20,575
Plus: Interest and debt expense 697 798 748
Plus: Before-tax amortization of capitalized interest 205 240 280
Less: Net income attributable to noncontrolling interests (18) (79) 36
Subtotal for calculation (6,533) 6,653 21,567
Total financing interest and debt costs $ 735 $ 817 $ 921
Interest Coverage Ratio (8.9) 8.1 23.4
Free Cash Flow The cash provided by operating activities less cash capital expenditures, which represents the cash available to creditors and investors after investing in the business.
Year ended December 31
Millions of dollars 2020 2019 2018
Net cash provided by operating activities $ 10,577 $ 27,314 $ 30,618
Less: Capital expenditures 8,922 14,116 13,792
Free Cash Flow $ 1,655 $ 13,198 $ 16,826
Debt Ratio Total debt as a percentage of total debt plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage. The company’s debt ratio was 25.2 percent at year-end 2020, compared with 15.8 percent at year-end 2019.
At December 31
Millions of dollars 2020 2019 2018
Short-term debt $ 1,548 $ 3,282 $ 5,726
Long-term debt 42,767 23,691 28,733
Total debt 44,315 26,973 34,459
Total Chevron Corporation Stockholders’ Equity 131,688 144,213 154,554
Total debt plus total Chevron Corporation Stockholders’ Equity $ 176,003 $ 171,186 $ 189,013
Debt Ratio 25.2 % 15.8 % 18.2 %
Management's Discussion and Analysis of Financial Condition and Results of Operations
Net Debt Ratio Total debt less cash and cash equivalents, time deposits, and marketable securities as a percentage of total debt less cash and cash equivalents, time deposits, and marketable securities, plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage, net of its cash balances.
At December 31
Millions of dollars 2020 2019 2018
Short-term debt $ 1,548 $ 3,282 $ 5,726
Long-term debt 42,767 23,691 28,733
Total Debt
44,315 26,973 34,459
Less: Cash and cash equivalents 5,596 5,686 9,342
Less: Time deposits - - 950
Less: Marketable securities 31 63 53
Total adjusted debt 38,688 21,224 24,114
Total Chevron Corporation Stockholders’ Equity
131,688 144,213 154,554
Total adjusted debt plus total Chevron Corporation Stockholders’ Equity $ 170,376 $ 165,437 $ 178,668
Net Debt Ratio 22.7 % 12.8 % 13.5 %
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 2020 2019 2018
Chevron Corporation Stockholders’ Equity $ 131,688 $ 144,213 $ 154,554
Plus: Short-term debt 1,548 3,282 5,726
Plus: Long-term debt 42,767 23,691 28,733
Plus: Noncontrolling interest 1,038 995 1,088
Capital Employed at December 31 $ 177,041 $ 172,181 $ 190,101
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 2020 2019 2018
Net income attributable to Chevron $ (5,543) $ 2,924 $ 14,824
Plus: After-tax interest and debt expense 658 761 713
Plus: Noncontrolling interest (18) (79) 36
Net income after adjustments (4,903) 3,606 15,573
Average capital employed $ 174,611 $ 181,141 $ 189,092
Return on Average Capital Employed (2.8) % 2.0 % 8.2 %
Return on Stockholders’ Equity (ROSE) Net income attributable to Chevron divided by average Chevron Corporation Stockholders’ Equity. Average stockholder’s equity is computed by averaging the sum of stockholder’s 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 2020 2019 2018
Net income attributable to Chevron $ (5,543) $ 2,924 $ 14,824
Chevron Corporation Stockholders’ Equity at December 31 131,688 144,213 154,554
Average Chevron Corporation Stockholders’ Equity 137,951 149,384 151,339
Return on Average Stockholders’ Equity (4.0) % 2.0 % 9.8 %
Management's Discussion and Analysis of Financial Condition and Results of Operations
Off-Balance-Sheet Arrangements, Contractual Obligations, Guarantees and Other Contingencies
Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements Information related to these matters is included on page 92 in Note 22, Other Contingencies and Commitments.
The following table summarizes the company’s significant contractual obligations:
Payments Due by Period
Millions of dollars Total1
2021 2022-2023 2024-2025 After 2025
On Balance Sheet:2
Short-Term Debt3, 4
$ 1,362 $ 1,362 $ - $ - $ -
Long-Term Debt3, 4
40,732 - 21,848 5,650 13,234
Leases
5,119 1,580 1,394 702 1,443
Interest4
9,357 866 1,469 1,105 5,917
Off Balance Sheet:
Throughput and Take-or-Pay Agreements5
13,186 817 2,045 2,236 8,088
Other Unconditional Purchase Obligations5
1,464 211 468 489 296
1.Excludes contributions for pensions and other postretirement benefit plans and ARO. Information on employee benefit plans is contained in Note 21 beginning on page 87. Information on ARO's is contained in Note 23 beginning on page 94
2.Does not include amounts related to the company’s income tax liabilities associated with uncertain tax positions. The company is unable to make reasonable estimates of the periods in which such liabilities may become payable. The company does not expect settlement of such liabilities to have a material effect on its consolidated financial position or liquidity in any single period.
3.$9.825 billion of short-term debt that the company expects to refinance is included in long-term debt. The repayment schedule above reflects the projected repayment of the entire amounts in the 2022-2023 period. The amounts represent only the principal balance.
4.Excludes finance lease liabilities.
5.Does not include commodity purchase obligations that are not fixed or determinable. These obligations are generally monetized in a relatively short period of time through sales transactions or similar agreements with third parties. Examples include obligations to purchase LNG, regasified natural gas and refinery products at indexed prices.
Direct Guarantees
Commitment Expiration by Period
Millions of dollars Total 2021 2022-2023 2024-2025 After 2025
Guarantee of nonconsolidated affiliate or joint-venture obligations
$ 391 $ 176 $ 77 $ 78 $ 60
Additional information related to guarantees is included on page 92 in Note 22, Other Contingencies and Commitments.
Indemnifications Information related to indemnifications is included on page 92 in Note 22, Other Contingencies and Commitments.
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.
Derivative Commodity Instruments Chevron is exposed to market risks related to the price volatility of crude oil, refined products, natural gas, natural gas liquids, 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, natural gas liquids, 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 2020.
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 2020 was not material to the company’s results of operations.
Management's Discussion and Analysis of Financial Condition and 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, 2020 and 2019 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, 2020.
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 2020, 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” on page 77, in Note 13, 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
MTBE Information related to methyl tertiary butyl ether (MTBE) matters is included on page 78 in Note 14 under the heading “MTBE.”
Ecuador Information related to Ecuador matters is included in Note 14 under the heading “Ecuador,” beginning on page 78.
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 2020 2019 2018
Balance at January 1 $ 1,234 $ 1,327 $ 1,429
Net Additions 179 200 197
Expenditures (274) (293) (299)
Balance at December 31 $ 1,139 $ 1,234 $ 1,327
The company records asset retirement obligations when there is a legal obligation associated with the retirement of long-lived assets and the liability can be reasonably estimated. These asset retirement obligations include costs related to environmental issues. The liability balance of approximately $13.6 billion for asset retirement obligations at year-end 2020 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 2020 environmental expenditures. Refer to Note 22 on page 93 for additional discussion of environmental remediation provisions and year-end reserves. Refer also to Note 23 on page 94 for additional discussion of the company’s asset retirement obligations.
Suspended Wells Information related to suspended wells is included in Note 19, Accounting for Suspended Exploratory Wells, beginning on page 85.
Income Taxes Information related to income tax contingencies is included on pages 79 through 82 in Note 15 and page 92 in Note 22 under the heading “Income Taxes.”
Management's Discussion and Analysis of Financial Condition and Results of Operations
Other Contingencies Information related to other contingencies is included on page 93 in Note 22 to the Consolidated Financial Statements under the heading “Other Contingencies.”
Environmental Matters
The company is subject to various international, 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. For example, international agreements and national, regional, and state legislation and regulatory measures that aim to limit or reduce greenhouse gas (GHG) emissions are currently in various stages of implementation. Consideration of GHG 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 at the national, state and local levels. Refer to “Risk Factors” in Part I, Item 1A, on pages 18 through 23 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.
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 2020 at approximately $2.0 billion for its consolidated companies. Included in these expenditures were approximately $0.5 billion of environmental capital expenditures and $1.5 billion of costs associated with the prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites, and the decommissioning and restoration of sites.
For 2021, total worldwide environmental capital expenditures are estimated at $0.5 billion. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites.
Critical Accounting Estimates and Assumptions
Management makes many estimates and assumptions in the application of accounting principles generally accepted in the United States of America (GAAP) that may have a material impact on the company’s consolidated financial statements and related disclosures and on the comparability of such information over different reporting periods. Such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on management’s experience and other information available prior to the issuance of the financial statements. Materially different results can occur as circumstances change and additional information becomes known.
The discussion in this section of “critical” accounting estimates and assumptions is according to the disclosure guidelines of the Securities and Exchange Commission (SEC), wherein:
Management's Discussion and Analysis of Financial Condition and Results of Operations
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 by management 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 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 and production costs.
The estimates of crude oil 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 2020, Chevron’s UOP Depreciation, Depletion and Amortization (DD&A) for oil and gas properties was $13.0 billion, and proved developed reserves at the beginning of 2020 were 6.4 billion barrels for consolidated companies. If the estimates of proved reserves used in the UOP calculations for consolidated operations had been lower by 5 percent across all oil and gas properties, UOP DD&A in 2020 would have increased by approximately $700 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,” beginning on page 103, for the changes in proved reserve estimates for the three years ended December 31, 2020, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” on page 111 for estimates of proved reserve values for each of the three years ended December 31, 2020.
This Oil and Gas Reserves commentary should be read in conjunction with the Properties, Plant and Equipment section of Note 1, beginning on page 64, 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 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, production profiles, and the outlook for global or regional market supply-and-demand conditions for crude oil, 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 16 on page 82 and to the section on Properties, Plant and Equipment in Note 1, “Summary of Significant Accounting Policies,” beginning on page 64.
Management's Discussion and Analysis of Financial Condition and Results of Operations
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 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 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.
In 2020, the company recorded impairments and write-offs for certain oil and gas properties primarily due to downward revisions to its oil and gas price outlook. In addition, the company fully impaired its investments in Petropiar and Petroboscan after completing an evaluation of the carrying value of its Venezuelan investments in line with its accounting policies and concluding that given the current operating environment and overall outlook, which create significant uncertainties regarding the recovery of the company’s investment, an other than temporary loss of value had occurred.
In 2019, the company recorded impairments and write-offs for certain oil and gas properties following the review and approval of its business plan and capital expenditure program. As a result of the company’s disciplined approach to capital allocation and a downward revision in its longer-term commodity price outlook, the company reduced funding to various natural gas-related upstream opportunities including Appalachia shale, Kitimat LNG and other international projects. In addition, the revised long-term oil price outlook resulted in an impairment of Big Foot.
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 2020 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 23 on page 94 for additional discussions on asset retirement obligations.
Pension and Other Postretirement Benefit Plans Note 21, beginning on page 87, 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.
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 on page 89 in Note 21 under the relevant headings. Actual rates may vary significantly from estimates because of unanticipated changes beyond the company’s control.
Management's Discussion and Analysis of Financial Condition and Results of Operations
For 2020, the company used an expected long-term rate of return of 6.5 percent and a discount rate for service costs of 3.3 percent and a discount rate for interest cost of 2.6 percent for the primary U.S. pension plan. The actual return for 2020 was 9.4 percent. For the 10 years ended December 31, 2020, actual asset returns averaged 7.9 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 6.5 percent during each year.
Total pension expense for 2020 was $1.5 billion. 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 67 percent of companywide pension expense, would have reduced total pension plan expense for 2020 by approximately $88 million. A 1 percent increase in the discount rates for this same plan would have reduced pension expense for 2020 by approximately $269 million.
The aggregate funded status recognized at December 31, 2020, was a net liability of approximately $6.2 billion. An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan. At December 31, 2020, the company used a discount rate of 2.4 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 61 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $475 million, and would have decreased the plan’s underfunded status from approximately $3.2 billion to $2.8 billion.
For the company’s OPEB plans, expense for 2020 was $57 million, and the total liability, all unfunded at the end of 2020, was $2.7 billion. For the primary U.S. OPEB plan, the company used a discount rate for service cost of 3.4 percent and a discount rate for interest cost of 2.7 percent to measure expense in 2020, and a 2.4 percent discount rate to measure the benefit obligations at December 31, 2020. Discount rate changes, similar to those used in the pension sensitivity analysis, resulted in an immaterial impact on 2020 OPEB expense and OPEB liabilities at the end of 2020.
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 88 in Note 21 for more information on the $7.4 billion of before-tax actuarial losses recorded by the company as of December 31, 2020, In addition, information related to company contributions is included on page 91 in Note 21 under the heading “Cash Contributions and Benefit Payments.”
Business Combinations - Purchase-Price Allocation Accounting for business combinations requires the allocation of the company’s purchase price to the various assets and liabilities of the acquired business at their respective fair values. The company uses all available information to make these fair value determinations. Determining the fair values of assets acquired generally involves assumptions regarding the amounts and timing of future revenues and expenditures, as well as discount rates. For additional discussion of purchase price allocations, refer to Note 29 beginning on page 96.
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 22 beginning on page 92. 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, 2020.
An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in recording these liabilities is not practicable because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss. For further information, refer to “Changes in management’s estimates and assumptions may have a material
Management's Discussion and Analysis of Financial Condition and Results of Operations
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 page 23.
New Accounting Standards
Refer to Note 4 beginning on page 69 for information regarding new accounting standards.
Quarterly Results
Unaudited
Consolidated Statement of Income
Millions of dollars, except per-share amounts
Consolidated Statement of Comprehensive Income
Millions of dollars
Consolidated Balance Sheet
Millions of dollars, except per-share amounts
Consolidated Statement of Cash Flows
Millions of dollars
Consolidated Statement of Equity
Amounts in millions of dollars
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 1
Summary of Significant Accounting Policies
General The company’s Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America. These require the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Although the company uses its best estimates and judgments, actual results could differ from these estimates as circumstances change and additional information becomes known.
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, generally limited to large, discrete or infrequently occurring transactions, the company may elect to apply fair value or cash flow hedge accounting. 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, petroleum 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
Millions of dollars, except per-share amounts
Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. All other exploratory wells and costs are expensed. Refer to Note 19, beginning on page 85, 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), 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 7, beginning on page 71, 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 23, on page 94, 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
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
reasonably certain to exercise. The company uses its incremental borrowing rate as a proxy for the discount rate based on the term of the lease unless the implicit rate is available.
Goodwill Goodwill resulting from a business combination is not subject to amortization. The company tests such goodwill at the reporting unit level for impairment annually at December 31, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount.
Environmental Expenditures Environmental expenditures that relate to ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized.
Liabilities related to future remediation costs are recorded when environmental assessments or cleanups or both are probable and the costs can be reasonably estimated. For crude oil, natural gas and mineral-producing properties, a liability for an ARO is made in accordance with accounting standards for asset retirement and environmental obligations. Refer to Note 23, on page 94, for a discussion of the company’s AROs.
For 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. 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. The company amortizes these awards on a straight-line basis.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
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, 2020, are reflected in the table below.
Currency Translation Adjustments Unrealized Holding Gains (Losses) on Securities Derivatives Defined Benefit Plans Total
Balance at December 31, 2017 $ (105) $ (5) $ (2) $ (3,477) $ (3,589)
Components of Other Comprehensive Income (Loss)1:
Before Reclassifications
(19) (5) - 28 4
Reclassifications2
- - - 603 603
Net Other Comprehensive Income (Loss)
(19) (5) - 631 607
Stranded Tax Reclassification to Retained Earnings3
- - - (562) (562)
Balance at December 31, 2018 $ (124) $ (10) $ (2) $ (3,408) $ (3,544)
Components of Other Comprehensive Income (Loss)1:
Before Reclassifications
(18) 2 (1) (1,838) (1,855)
Reclassifications2
- - 3 406 409
Net Other Comprehensive Income (Loss)
(18) 2 2 (1,432) (1,446)
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)
1 All amounts are net of tax.
2 Refer to Note 21 beginning on page 87, for reclassified components totaling $1,084 that are included in employee benefit costs for the year ended December 31, 2020. Related income taxes for the same period, totaling $252, are reflected in Income Tax Expense on the Consolidated Statement of Income. All other reclassified amounts were insignificant.
3 Stranded tax reclassification to retained earnings per ASU 2018-02.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 3
Information Relating to the Consolidated Statement of Cash Flows
Year ended December 31
2020 2019 2018
Distributions more (less) than income from equity affiliates includes the following:
Distributions from equity affiliates $ 1,543 $ 1,895 $ 2,747
(Income) loss from equity affiliates 472 (3,968) (6,327)
Distributions more (less) than income from equity affiliates $ 2,015 $ (2,073) $ (3,580)
Net decrease (increase) in operating working capital was composed of the following:
Decrease (increase) in accounts and notes receivable $ 2,423 $ 1,852 $ 437
Decrease (increase) in inventories 284 7 (424)
Decrease (increase) in prepaid expenses and other current assets (87) (323) (149)
Increase (decrease) in accounts payable and accrued liabilities (3,576) (109) (494)
Increase (decrease) in income and other taxes payable (696) 67 (88)
Net decrease (increase) in operating working capital $ (1,652) $ 1,494 $ (718)
Net cash provided by operating activities includes the following cash payments:
Interest on debt (net of capitalized interest) $ 720 $ 810 $ 736
Income taxes 2,987 4,817 4,748
Proceeds and deposits related to asset sales and returns of investment consisted of the following gross amounts:
Proceeds and deposits related to asset sales $ 2,891 $ 2,809 $ 2,000
Returns of investment from equity affiliates 77 142 392
Proceeds and deposits related to asset sales and returns of investment $ 2,968 $ 2,951 $ 2,392
Net maturities (investments) of time deposits consisted of the following gross amounts:
Investments in time deposits $ - $ - $ (950)
Maturities of time deposits - 950 -
Net maturities of (investments in) time deposits $ - $ 950 $ (950)
Net sales (purchases) of marketable securities consisted of the following gross amounts:
Marketable securities purchased $ - $ (1) $ (51)
Marketable securities sold 35 3 -
Net sales (purchases) of marketable securities $ 35 $ 2 $ (51)
Net repayment (borrowing) of loans by equity affiliates:
Borrowing of loans by equity affiliates $ (3,925) $ (1,350) $ -
Repayment of loans by equity affiliates 2,506 105 111
Net repayment (borrowing) of loans by equity affiliates $ (1,419) $ (1,245) $ 111
Net borrowings (repayments) of short-term obligations consisted of the following gross and net amounts:
Proceeds from issuances of short-term obligations $ 10,846 $ 2,586 $ 2,486
Repayments of short-term obligations (9,771) (1,430) (4,136)
Net borrowings (repayments) of short-term obligations with three months or less maturity (424) (3,977) 3,671
Net borrowings (repayments) of short-term obligations $ 651 $ (2,821) $ 2,021
Net sales (purchases) of treasury shares consists of the following gross and net amounts:
Shares issued for share-based compensation plans $ 226 $ 1,104 $ 1,147
Shares purchased under share repurchase and deferred compensation plans (1,757) (4,039) (1,751)
Net sales (purchases) of treasury shares $ (1,531) $ (2,935) $ (604)
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. "Distributions more (less) than income from equity affiliates," “Depreciation, depletion and amortization,” “Deferred income tax provision,” “Dry hole expense,” and "Net decrease (increase) in operating working capital" collectively include approximately $4.8 billion in non-cash reductions in 2020 relating to impairments and other non-cash charges. “Depreciation, depletion and amortization,” “Deferred income tax provision,” and “Dry hole expense” collectively include approximately $9.3 billion in non-cash reductions recorded in 2019 relating to impairments and other non-cash charges.
Refer also to Note 23, on page 94, 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, 2020.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Refer also to Note 29 on page 96 for a discussion of the all-stock acquisition of Noble. The cash received as a result of the acquisition is reflected on the Consolidated Statement of Cash Flows as “Cash acquired from Noble Energy, Inc.” Other changes to the Consolidated Balance Sheet resulting from the acquisition that did not affect cash are not reflected on the Consolidated Statement of Cash Flows.
The major components of “Capital expenditures” and the reconciliation of this amount to the reported capital and exploratory expenditures, including equity affiliates, are presented in the following table.
Year ended December 31
2020 2019 2018
Additions to properties, plant and equipment *
$ 8,492 $ 13,839 $ 13,384
Additions to investments 136 140 65
Current-year dry hole expenditures 327 124 344
Payments for other assets and liabilities, net
(33) 13 (1)
Capital expenditures 8,922 14,116 13,792
Expensed exploration expenditures 500 598 523
Assets acquired through finance leases and other obligations 53 181 75
Payments for other assets and liabilities, net
42 (13) -
Capital and exploratory expenditures, excluding equity affiliates
9,517 14,882 14,390
Company’s share of expenditures by equity affiliates
3,982 6,112 5,716
Capital and exploratory expenditures, including equity affiliates
$ 13,499 $ 20,994 $ 20,106
* Excludes non-cash movements of $816 in 2020, $(239) in 2019 and $25 in 2018.
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
2020 2019 2018
Cash and cash equivalents
$ 5,596 $ 5,686 $ 9,342
Restricted cash included in “Prepaid expenses and other current assets”
365 452 341
Restricted cash included in “Deferred charges and other assets”
776 773 798
Total cash, cash equivalents and restricted cash
$ 6,737 $ 6,911 $ 10,481
Note 4
New Accounting Standards
Financial Instruments - Credit Losses (Topic 326) Effective January 1, 2020, Chevron adopted Accounting Standards Update (ASU) 2016-13 and its related amendments. For additional information on the company’s expected credit losses, refer to Note 28 on page 96.
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, office buildings, and production equipment.
Details of the right-of-use assets and lease liabilities for operating and finance leases, including the balance sheet presentation, are as follows:
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
At December 31, 2020 At December 31, 2019
Operating
Leases Finance
Leases Operating
Leases Finance
Leases
Deferred charges and other assets $ 3,949 $ - $ 4,074 $ -
Properties, plant and equipment, net - 455 - 329
Right-of-use assets1
$ 3,949 $ 455 $ 4,074 $ 329
Accrued Liabilities $ 1,291 $ - $ 1,277 $ -
Short-term Debt - 186 - 18
Current lease liabilities 1,291 186 1,277 18
Deferred credits and other noncurrent obligations 2,615 - 2,608 -
Long-term Debt - 447 - 282
Noncurrent lease liabilities 2,615 447 2,608 282
Total lease liabilities
$ 3,906 $ 633 $ 3,885 $ 300
Weighted-average remaining lease term (in years) 7.2 10.4 5.2 16.0
Weighted-average discount rate 2.8 % 3.9 % 3.2 % 4.7 %
1 Includes non-cash additions of $1,353 and $164 in 2020, and $1,201 and $184 in 2019 for right-of-use assets obtained in exchange for new and modified lease liabilities for operating and finance leases, respectively. 2020 includes $566 in operating lease right-of-use assets and $566 lease liabilities associated with the Puma acquisition. 2020 also includes $124 in operating lease right-of-use assets and $148 lease liabilities, and $112 in finance lease right-of-use assets and $309 lease liabilities associated with the Noble acquisition.
Total lease costs consist of both amounts recognized in the Consolidated Statement of Income during the period and amounts capitalized as part of the cost of another asset. Total lease costs incurred for operating and finance leases were as follows:
Year-ended December 31
2020 2019
Operating lease costs1, 2
$ 2,551 $ 2,621
Finance lease costs 45 66
Total lease costs
$ 2,596 $ 2,687
1 Net rental expense of $816 for 2018.
2 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
2020 2019
Operating cash flows from operating leases $ 1,744 $ 1,574
Investing cash flows from operating leases 762 1,047
Operating cash flows from finance leases 14 13
Financing cash flows from finance leases 34 24
At December 31, 2020, the estimated future undiscounted cash flows for operating and finance leases were as follows:
At December 31, 2020
Operating Leases Finance
Leases
Year 2021 $ 1,376 $ 204
2022 779 60
2023 497 58
2024 338 56
2025 255 53
Thereafter 1,112 331
Total $ 4,357 $ 762
Less: Amounts representing interest 451 129
Total lease liabilities
$ 3,906 $ 633
Additionally, the company has $907 in future undiscounted cash flows for operating leases not yet commenced. These leases are primarily for a drill ship and drilling rigs. For those leasing arrangements where the underlying asset is not yet constructed, the lessor is primarily involved in the design and construction of the asset.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 6
Summarized Financial Data - Chevron U.S.A. Inc.
Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron Corporation. CUSA and its subsidiaries manage and operate most of Chevron’s U.S. businesses. Assets include those related to the exploration and production of crude oil, natural gas and natural gas liquids 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
2020 2019 2018
Sales and other operating revenues
$ 67,950 $ 109,314 $ 125,076
Total costs and other deductions
72,575 116,365 121,351
Net income (loss) attributable to CUSA
(2,676) (5,061) 4,334
At December 31
2020 2019
Current assets $ 10,555 $ 13,059
Other assets 48,054 50,796
Current liabilities 12,403 18,291
Other liabilities 14,102 12,565
Total CUSA net equity $ 32,104 $ 32,999
Memo: Total debt $ 7,133 $ 3,222
Note 7
Fair Value Measurements
The tables on the next page show the fair value hierarchy for assets and liabilities measured at fair value on a recurring and nonrecurring basis at December 31, 2020 and December 31, 2019.
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, 2020.
Derivatives The company records its derivative instruments - other than any commodity derivative contracts that are designated as normal purchase and normal sale - on the Consolidated Balance Sheet at fair value, with the offsetting amount to the Consolidated Statement of Income. Derivatives classified as Level 1 include futures, swaps and options contracts traded in active markets such as the New York Mercantile Exchange. Derivatives classified as Level 2 include swaps, options and forward contracts principally with financial institutions and other oil and gas companies, 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 reported impairments for certain upstream properties during 2020 primarily due to downward revisions to its oil and gas price outlook. The impact of these impairments is included in “Depreciation, depletion and amortization” on the Consolidated Statement of Income. The company reported impairments for certain upstream properties in 2019 primarily due to capital allocation decisions and a lower long-term commodity price outlook.
Investments and Advances In 2020, the company fully impaired its investments in Petropiar and Petroboscan in Venezuela. The impact of these impairments is included in “Income (loss) from equity affiliates” on the Consolidated Statement of Income. The company reported impairments for certain upstream equity companies in 2019 primarily due to capital allocation decisions and lower long-term commodity price outlook.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Assets and Liabilities Measured at Fair Value on a Recurring Basis
At December 31, 2020 At December 31, 2019
Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3
Marketable securities $ 31 $ 31 $ - $ - $ 63 $ 63 $ - $ -
Derivatives 74 37 37 - 11 1 10 -
Total assets at fair value $ 105 $ 68 $ 37 $ - $ 74 $ 64 $ 10 $ -
Derivatives 173 58 115 - 74 26 48 -
Total liabilities at fair value $ 173 $ 58 $ 115 $ - $ 74 $ 26 $ 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 2020 Total Level 1 Level 2 Level 3 Year 2019
Properties, plant and equipment, net (held and used) $ 2,443 $ - $ 20 $ 2,423 $ 2,599 $ 2,177 $ - $ - $ 2,177 $ 2,095
Properties, plant and equipment, net (held for sale) 1,418 - 1,418 - 193 1,412 - 1,412 - 8,702
Investments and advances 28 - - 28 2,555 52 - 30 22 594
Total nonrecurring assets at fair value $ 3,889 $ - $ 1,438 $ 2,451 $ 5,347 $ 3,641 $ - $ 1,442 $ 2,199 $ 11,391
At year-end 2020, the company had assets measured at fair value Level 3 using unobservable inputs of $2,451. 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. The significant Level 3 inputs were attributed to two assets, one in an international location where volumes and price were primarily based on natural gas, and the second was in a U.S. location where volumes and price were primarily based on crude.
Assets and Liabilities Not Required to Be Measured at Fair Value The company holds cash equivalents and time deposits 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 $5,596 and $5,686 at December 31, 2020, and December 31, 2019, respectively. The fair values of cash, cash equivalents and bank time deposits are classified as Level 1 and reflect the cash that would have been received if the instruments were settled at December 31, 2020.
“Cash and cash equivalents” do not include investments with a carrying/fair value of $1,141 and $1,225 at December 31, 2020, and December 31, 2019, respectively. At December 31, 2020, these investments are classified as Level 1 and include restricted funds related to certain upstream decommissioning activities, tax payments and a financing program, which are reported in “Deferred charges and other assets” on the Consolidated Balance Sheet. Long-term debt, excluding finance lease liabilities, of $30,805 and $13,659 at December 31, 2020, and December 31, 2019, respectively, had estimated fair values of $34,390 and $14,326, respectively. Long-term debt primarily includes corporate issued bonds. The fair value of corporate bonds is $32,123 and classified as Level 1. The fair value of other long-term debt is $2,267 and classified as Level 2.
The carrying values of 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, 2020 and 2019, were not material.
Note 8
Financial and Derivative Instruments
Derivative Commodity Instruments The company’s derivative commodity instruments principally include crude oil, natural gas and refined product futures, swaps, options, and forward contracts. None of the company’s derivative instruments is designated as a hedging instrument, although certain of the company’s affiliates make such designation. 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.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
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, 2020, December 31, 2019, and December 31, 2018, and their classification on the Consolidated Balance Sheet and Consolidated Statement of Income are below:
Consolidated Balance Sheet: Fair Value of Derivatives Not Designated as Hedging Instruments
At December 31
Type of Contract Balance Sheet Classification 2020 2019
Commodity Accounts and notes receivable, net
$ 73 $ 11
Commodity Long-term receivables, net
1 -
Total assets at fair value $ 74 $ 11
Commodity Accounts payable $ 172 $ 74
Commodity Deferred credits and other noncurrent obligations
1 -
Total liabilities at fair value $ 173 $ 74
Consolidated Statement of Income: The Effect of Derivatives Not Designated as Hedging Instruments
Gain/(Loss)
Type of Derivative Statement of Year ended December 31
Contract Income Classification 2020 2019 2018
Commodity Sales and other operating revenues
$ 69 $ (291) $ 135
Commodity Purchased crude oil and products
(36) (17) (33)
Commodity Other income 7 (2) 3
$ 40 $ (310) $ 105
The table below represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated Balance Sheet at December 31, 2020 and December 31, 2019.
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, 2020
Derivative Assets $ 818 $ 744 $ 74 $ - $ 74
Derivative Liabilities $ 917 $ 744 $ 173 $ - $ 173
At December 31, 2019
Derivative Assets $ 656 $ 645 $ 11 $ - $ 11
Derivative Liabilities $ 719 $ 645 $ 74 $ - $ 74
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, time deposits, 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.
The trade receivable balances, reflecting the company’s diversified sources of revenue, are dispersed among the company’s broad customer base worldwide. As a result, the company believes concentrations of credit risk are 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 pre-payments, letters of credit or other acceptable collateral instruments to support sales to customers.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 9
Assets Held for Sale
At December 31, 2020, the company classified $1,101 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 2020 were not material.
Note 10
Equity
Retained earnings at December 31, 2020 and 2019, included $26,532 and $25,319, respectively, for the company’s share of undistributed earnings of equity affiliates.
At December 31, 2020, about 67 million shares of Chevron’s common stock remained available for issuance from the 260 million shares that were reserved for issuance under the Chevron Long-Term Incentive Plan. In addition, 644,376 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 11
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 20, “Stock Options and Other Share-Based Compensation,” beginning on page 86). The table below sets forth the computation of basic and diluted EPS:
Year ended December 31
2020 2019 2018
Basic EPS Calculation
Earnings available to common stockholders - Basic1
$ (5,543) $ 2,924 $ 14,824
Weighted-average number of common shares outstanding2
1,870 1,882 1,897
Add: Deferred awards held as stock units
- - 1
Total weighted-average number of common shares outstanding 1,870 1,882 1,898
Earnings per share of common stock - Basic $ (2.96) $ 1.55 $ 7.81
Diluted EPS Calculation
Earnings available to common stockholders - Diluted1
$ (5,543) $ 2,924 $ 14,824
Weighted-average number of common shares outstanding2
1,870 1,882 1,897
Add: Deferred awards held as stock units
- - 1
Add: Dilutive effect of employee stock-based awards
- 13 16
Total weighted-average number of common shares outstanding 1,870 1,895 1,914
Earnings per share of common stock - Diluted $ (2.96) $ 1.54 $ 7.74
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.
Note 12
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; 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.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
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
2020 2019 2018
Upstream
United States $ (1,608) $ (5,094) $ 3,278
International (825) 7,670 10,038
Total Upstream (2,433) 2,576 13,316
Downstream
United States (571) 1,559 2,103
International 618 922 1,695
Total Downstream 47 2,481 3,798
Total Segment Earnings (2,386) 5,057 17,114
All Other
Interest expense (658) (761) (713)
Interest income 52 181 137
Other (2,551) (1,553) (1,714)
Net Income (Loss) Attributable to Chevron Corporation
$ (5,543) $ 2,924 $ 14,824
Segment Assets Segment assets do not include intercompany investments or receivables. Assets at year-end 2020 and 2019 are as follows:
At December 31
2020 2019
Upstream
United States $ 42,431 $ 35,926
International 144,476 145,648
Goodwill 4,402 4,463
Total Upstream 191,309 186,037
Downstream
United States 23,490 25,197
International 16,096 16,955
Total Downstream 39,586 42,152
Total Segment Assets 230,895 228,189
All Other
United States 4,017 3,475
International 4,878 5,764
Total All Other 8,895 9,239
Total Assets - United States 69,938 64,598
Total Assets - International 165,450 168,367
Goodwill 4,402 4,463
Total Assets $ 239,790 $ 237,428
Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2020, 2019 and 2018, are presented in the table on the next page. Products are transferred between operating segments at internal product values that approximate market prices.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
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.
Year ended December 311
2020 2019 2018
Upstream
United States
$ 14,577 $ 23,358 $ 22,891
International
26,804 35,628 37,822
Subtotal
41,381 58,986 60,713
Intersegment Elimination - United States
(8,068) (14,944) (13,965)
Intersegment Elimination - International
(7,002) (12,335) (13,679)
Total Upstream 26,311 31,707 33,069
Downstream
United States
32,589 55,271 59,376
International
38,936 57,654 70,095
Subtotal
71,525 112,925 129,471
Intersegment Elimination - United States
(2,150) (3,924) (2,742)
Intersegment Elimination - International
(1,292) (1,089) (1,132)
Total Downstream 68,083 107,912 125,597
All Other
United States
744 1,064 1,022
International
15 20 22
Subtotal
759 1,084 1,044
Intersegment Elimination - United States
(667) (818) (786)
Intersegment Elimination - International
(15) (20) (22)
Total All Other 77 246 236
Sales and Other Operating Revenues
United States
47,910 79,693 83,289
International
65,755 93,302 107,939
Subtotal
113,665 172,995 191,228
Intersegment Elimination - United States
(10,885) (19,686) (17,493)
Intersegment Elimination - International
(8,309) (13,444) (14,833)
Total Sales and Other Operating Revenues
$ 94,471 $ 139,865 $ 158,902
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 2020, 2019 and 2018 is as follows:
Year ended December 31
2020 2019 2018
Upstream
United States $ (570) $ (1,550) $ 811
International (415) 3,492 4,687
Total Upstream (985) 1,942 5,498
Downstream
United States (192) 392 534
International 253 170 328
Total Downstream 61 562 862
All Other (968) 187 (645)
Total Income Tax Expense (Benefit) $ (1,892) $ 2,691 $ 5,715
Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 13, on page 77. Information related to properties, plant and equipment by segment is contained in Note 16, on page 82.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 13
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
2020 2019 2020 2019 2018
Upstream
Tengizchevroil $ 22,685 $ 20,214 $ 1,238 $ 3,067 $ 3,614
Petropiar - 1,396 (1,396) 80 317
Petroboscan - 1,139 (1,112) (11) 357
Caspian Pipeline Consortium 835 883 159 155 170
Angola LNG Limited 2,258 2,423 (166) (26) 172
Noble Midstream equity affiliates 895 - (9) - -
Other 980 881 146 (478) 19
Total Upstream 27,653 26,936 (1,140) 2,787 4,649
Downstream
Chevron Phillips Chemical Company LLC 6,181 6,241 630 880 1,034
GS Caltex Corporation 3,547 3,796 (185) 13 373
Other 1,389 1,443 223 288 273
Total Downstream 11,117 11,480 668 1,181 1,680
All Other
Other (14) (14) - - (2)
Total equity method $ 38,756 $ 38,402 $ (472) $ 3,968 $ 6,327
Other non-equity method investments 296 286
Total investments and advances $ 39,052 $ 38,688
Total United States $ 7,978 $ 7,203 $ 709 $ 641 $ 1,033
Total International $ 31,074 $ 31,485 $ (1,181) $ 3,327 $ 5,294
Descriptions of major 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, 2020, the company’s carrying value of its investment in TCO was about $100 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 Future Growth and Wellhead Pressure Management Project with a balance of $4,825.
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. At December 31, 2020, the underlying equity in Petropiar’s net assets was approximately $1,500.
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. At December 31, 2020, the underlying equity in Petroboscan’s net assets was approximately $1,100. The company also has an outstanding long-term loan to Petroboscan of $560 at year-end 2020.
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.
Noble Midstream Equity Affiliates Noble Midstream, a fully consolidated subsidiary of Chevron, has equity investments in entities which operate midstream assets in the United States. At December 31, 2020, equity investments included
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Advantage Pipeline LLC (50 percent), Delaware Crossing LLC (50 percent), EPIC Crude Holdings (30 percent), EPIC Y-Grade (15 percent), EPIC Propane (15 percent), and Saddlehorn Pipeline Company, LLC (20 percent).
Chevron Phillips Chemical Company LLC Chevron owns 50 percent of Chevron Phillips Chemical Company LLC. The other half is owned by Phillips 66.
GS Caltex Corporation Chevron owns 50 percent of GS Caltex Corporation, a joint venture with GS Energy in South Korea. The joint venture imports, refines and markets petroleum products, petrochemicals and lubricants.
Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $6,038, $8,006 and $10,378 with affiliated companies for 2020, 2019 and 2018, respectively. “Purchased crude oil and products” includes $3,003, $5,694 and $6,598 with affiliated companies for 2020, 2019 and 2018, respectively.
“Accounts and notes receivable” on the Consolidated Balance Sheet includes $807 and $810 due from affiliated companies at December 31, 2020 and 2019, respectively. “Accounts payable” includes $244 and $506 due to affiliated companies at December 31, 2020 and 2019, 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 $5,153, $4,331 and $3,402 at December 31, 2020, 2019 and 2018, respectively.
Affiliates Chevron Share
Year ended December 31 2020 2019 2018 2020 2019 2018
Total revenues $ 49,093 $ 66,473 $ 84,469 $ 21,641 $ 32,628 $ 40,679
Income before income tax expense 5,682 13,197 16,693 2,550 5,954 6,755
Net income attributable to affiliates 4,704 9,809 13,321 2,034 4,366 6,384
At December 31
Current assets $ 17,087 $ 30,791 $ 32,657 $ 7,328 $ 12,998 $ 12,813
Noncurrent assets 97,468 97,177 87,614 43,247 41,531 36,369
Current liabilities 12,164 26,032 26,006 5,052 10,610 9,843
Noncurrent liabilities 25,586 21,593 20,000 5,884 5,068 4,446
Total affiliates’ net equity $ 76,805 $ 80,343 $ 74,265 $ 39,639 $ 38,851 $ 34,893
Note 14
Litigation
MTBE Chevron and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive. Chevron is a party to six pending lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners. Resolution of these lawsuits and claims may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. The company’s ultimate exposure related to pending lawsuits and claims is not determinable. The company no longer uses MTBE in the manufacture of gasoline in the United States.
Ecuador
Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was a minority member of an oil production consortium with Ecuadorian state-owned Petroecuador from 1967 until 1992. After termination of the consortium and a third-party environmental audit, Ecuador and the consortium parties entered into a settlement agreement specifying Texpet’s remediation obligations. Following Texpet’s completion of a three-year remediation program, Ecuador certified the remediation as proper and released Texpet and its affiliates from environmental liability. In May 2003, plaintiffs alleging environmental harm from the consortium’s activities sued Chevron in the Superior Court in Lago Agrio, Ecuador. In February 2011, that court entered a judgment against Chevron for approximately $9,500 plus additional punitive damages. An appellate panel affirmed, and Ecuador’s National Court of Justice ratified the judgment but nullified the punitive damages, resulting in a judgment of approximately $9,500. Ecuador’s highest Constitutional Court rejected Chevron’s final appeal in July 2018.
In February 2011, Chevron sued the Lago Agrio plaintiffs and several of their lawyers and supporters 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 court ruled that the Ecuadorian judgment had been procured through fraud, bribery, and corruption, and prohibited the RICO defendants from seeking to enforce the Ecuadorian judgment in the United States or profiting from their illegal acts. The Court of Appeals for the Second Circuit affirmed, and the U.S. Supreme Court denied certiorari in June 2017, rendering final the U.S. judgment in favor of Chevron. The Lago Agrio plaintiffs sought to
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
have the Ecuadorian judgment recognized and enforced in Canada, Brazil, and Argentina. All of those recognition and enforcement actions were dismissed and resolved in Chevron’s favor. Chevron and Texpet filed an arbitration claim against Ecuador in September 2009 before an arbitral tribunal administered by the Permanent Court of Arbitration in The Hague, under the United States-Ecuador Bilateral Investment Treaty. In August 2018, the Tribunal issued an award holding that the Ecuadorian judgment was based on environmental claims that Ecuador had settled and released, and that it was procured through fraud, bribery, and corruption. 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 status of enforceability from the Ecuadorian judgment and to compensate Chevron for any injuries resulting from the judgment. The third and final phase of the arbitration, to determine the amount of compensation Ecuador owes to Chevron, is ongoing. In September 2020, the District Court of The Hague denied Ecuador’s request to set aside the Tribunal’s award, stating that it now is “common ground” between Ecuador and Chevron that the Ecuadorian judgment is fraudulent. In December 2020, Ecuador appealed the District Court’s decision to The Hague Court of Appeals. In a separate proceeding, Ecuador also admitted that the Ecuadorian judgment is fraudulent in a public filing with the Office of the United States Trade Representative in July 2020.
Management’s Assessment The ultimate outcome of the foregoing matters, including any financial effect on Chevron, remains uncertain. Chevron continues to believe that the Ecuadorian judgment is illegitimate and unenforceable and that it does not provide any basis upon which an estimate of a reasonably possible loss or range of loss can be made.
Note 15
Taxes
Income Taxes
Year ended December 31
2020 2019 2018
Income tax expense (benefit)
U.S. federal
Current $ (182) $ (73) $ (181)
Deferred (1,315) (1,074) 738
State and local
Current 65 153 183
Deferred (152) (172) (16)
Total United States (1,584) (1,166) 724
International
Current 1,833 4,577 4,662
Deferred (2,141) (720) 329
Total International (308) 3,857 4,991
Total income tax expense (benefit) $ (1,892) $ 2,691 $ 5,715
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:
2020 2019 2018
Income (loss) before income taxes
United States $ (5,700) $ (5,483) $ 4,730
International (1,753) 11,019 15,845
Total income (loss) before income taxes (7,453) 5,536 20,575
Theoretical tax (at U.S. statutory rate of 21% ) (1,565) 1,163 4,321
Effect of U.S. tax reform - 3 (26)
Equity affiliate accounting effect 211 (687) (1,526)
Effect of income taxes from international operations*
(39) 2,196 3,132
State and local taxes on income, net of U.S. federal income tax benefit
(65) (18) 162
Prior year tax adjustments, claims and settlements (236) 192 (51)
Tax credits (33) (18) (163)
Other U.S.*
(165) (140) (134)
Total income tax expense (benefit) $ (1,892) $ 2,691 $ 5,715
Effective income tax rate 25.4 % 48.6 % 27.8 %
* Includes one-time tax costs (benefits) associated with changes in uncertain tax positions and valuation allowances.
The 2020 decrease in income tax expense of $4,583 is a result of the year-over-year decrease in total income before income tax expense, which is primarily due to lower crude oil prices in 2020, partially offset by lower impairment and write off
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
charges. The company’s effective tax rate changed from 49 percent in 2019 to 25 percent in 2020. The change in effective tax rate is a consequence of mix effect 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
2020 2019
Deferred tax liabilities
Properties, plant and equipment $ 16,603 $ 17,251
Investments and other 5,617 5,372
Total deferred tax liabilities 22,220 22,623
Deferred tax assets
Foreign tax credits (10,585) (9,840)
Asset retirement obligations/environmental reserves (4,721) (4,329)
Employee benefits (3,856) (3,454)
Deferred credits (1,056) (1,083)
Tax loss carryforwards (6,701) (5,262)
Other accrued liabilities (228) (441)
Inventory (633) (662)
Operating leases (1,234) (1,211)
Miscellaneous (3,685) (2,796)
Total deferred tax assets (32,699) (29,078)
Deferred tax assets valuation allowance 17,762 15,965
Total deferred taxes, net $ 7,283 $ 9,510
Deferred tax liabilities decreased by $403 from year-end 2019. The decrease to Properties, plant and equipment temporary differences was partially offset with an increase to Investments and other. The Properties, plant and equipment decrease was primarily due to upstream impairments. Deferred tax assets increased by $3,621 from year-end 2019. This increase was primarily related to increases in tax loss carryforwards for various locations, miscellaneous items related to foreign exchange and foreign tax credits acquired with the purchase of Noble.
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 2020, the company had gross tax loss carryforwards of approximately $19,763 and tax credit carryforwards of approximately $1,056, 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 2021 through 2034. U.S. foreign tax credit carryforwards of $10,585 will expire between 2021 and 2030.
At December 31, 2020 and 2019, deferred taxes were classified on the Consolidated Balance Sheet as follows:
At December 31
2020 2019
Deferred charges and other assets $ (5,286) $ (4,178)
Noncurrent deferred income taxes 12,569 13,688
Total deferred income taxes, net $ 7,283 $ 9,510
Income 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.
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. Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for possible future remittances totaled approximately $52,100 at December 31, 2020. 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 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.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
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, 2020, 2019 and 2018. 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.
2020 2019 2018
Balance at January 1 $ 4,987 $ 5,070 $ 4,828
Foreign currency effects 2 1 (6)
Additions based on tax positions taken in current year 253 94 239
Additions for tax positions taken in prior years
437 313 153
Reductions for tax positions taken in prior years
(216) (194) (131)
Settlements with taxing authorities in current year
(429) (78) (13)
Reductions as a result of a lapse of the applicable statute of limitations
(16) (219) -
Balance at December 31 $ 5,018 $ 4,987 $ 5,070
Approximately 83 percent of the $5,018 of unrecognized tax benefits at December 31, 2020, 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, 2020. For these jurisdictions, the latest years for which income tax examinations had been finalized were as follows: United States - 2013, Nigeria - 2007, Australia - 2009 and Kazakhstan - 2012.
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. However, it is reasonably possible that developments on tax matters in certain tax jurisdictions may result in significant increases or decreases in the company’s total unrecognized tax benefits 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.
On the Consolidated Statement of Income, the company reports interest and penalties related to liabilities for uncertain tax positions as “Income tax expense.” As of December 31, 2020, accrual benefit of $(95) for anticipated interest and penalty were included on the Consolidated Balance Sheet, compared with accrual charges of $30 as of year-end 2019. Income tax expense (benefit) associated with interest and penalties was $(124), $(3) and $8 in 2020, 2019 and 2018, respectively.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Taxes Other Than on Income
Year ended December 31
2020 2019 2018
United States
Excise and similar taxes on products and merchandise $ 4,566 $ 4,990 $ 4,830
Consumer excise taxes collected on behalf of third parties (4,566) (4,990) (4,830)
Import duties and other levies 7 2 15
Property and other miscellaneous taxes
2,248 1,785 1,577
Payroll taxes 235 254 246
Taxes on production 317 355 325
Total United States 2,807 2,396 2,163
International
Excise and similar taxes on products and merchandise 2,367 2,801 3,031
Consumer excise taxes collected on behalf of third parties (2,367) (2,801) (3,031)
Import duties and other levies 39 35 37
Property and other miscellaneous taxes
1,461 1,435 2,370
Payroll taxes 117 125 132
Taxes on production 75 145 165
Total International 1,692 1,740 2,704
Total taxes other than on income $ 4,499 $ 4,136 $ 4,867
Note 16
Properties, Plant and Equipment1
At December 31 Year ended December 31
Gross Investment at Cost Net Investment Additions at Cost2
Depreciation Expense3
2020 2019 2018 2020 2019 2018 2020 2019 2018 2020 2019 2018
Upstream
United States $ 96,555 $ 82,117 $ 88,155 $ 38,175 $ 31,082 $ 39,526 $ 13,067 $ 7,751 $ 6,434 $ 6,841 $ 15,222 $ 5,328
International 209,846 206,292 215,329 102,010 102,639 113,603 11,069 3,664 4,865 11,121 12,618 12,726
Total Upstream 306,401 288,409 303,484 140,185 133,721 153,129 24,136 11,415 11,299 17,962 27,840 18,054
Downstream
United States 26,499 25,968 24,685 11,101 11,398 10,838 638 1,452 1,259 851 869 751
International 7,993 7,480 7,237 3,395 3,114 3,023 573 355 278 283 256 282
Total Downstream 34,492 33,448 31,922 14,496 14,512 13,861 1,211 1,807 1,537 1,134 1,125 1,033
All Other
United States 4,195 4,719 4,667 1,916 2,236 2,186 194 324 224 403 243 320
International 144 146 171 21 25 31 5 9 6 9 10 12
Total All Other 4,339 4,865 4,838 1,937 2,261 2,217 199 333 230 412 253 332
Total United States 127,249 112,804 117,507 51,192 44,716 52,550 13,899 9,527 7,917 8,095 16,334 6,399
Total International 217,983 213,918 222,737 105,426 105,778 116,657 11,647 4,028 5,149 11,413 12,884 13,020
Total $ 345,232 $ 326,722 $ 340,244 $ 156,618 $ 150,494 $ 169,207 $ 25,546 $ 13,555 $ 13,066 $ 19,508 $ 29,218 $ 19,419
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 2020. Australia had PP&E of $48,060, $51,359 and $53,768 in 2020, 2019 and 2018, 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 $709, $49 and $343 in 2020, 2019 and 2018, respectively.
3Depreciation expense includes accretion expense of $560, $628 and $654 in 2020, 2019 and 2018, respectively, and impairments of $2,792, $10,797 and $735 in 2020, 2019 and 2018, respectively.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 17
Short-Term Debt
At December 31
2020 2019
Commercial paper1
$ 5,612 $ 4,654
Notes payable to banks and others with originating terms of one year or less
15 228
Current maturities of long-term debt 2,600 5,054
Current maturities of long-term finance leases
186 18
Redeemable long-term obligations
Long-term debt 2,960 3,078
Subtotal
11,373 13,032
Reclassified to long-term debt (9,825) (9,750)
Total short-term debt $ 1,548 $ 3,282
1 Weighted-average interest rates at December 31, 2020 and 2019, were 0.15% and 1.69%, respectively.
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, 2020, the company had no interest rate swaps on short-term debt.
At December 31, 2020, the company had $9,825 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 London Interbank Offered Rate 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, 2020.
The company classified $9,825 and $9,750 of short-term debt as long-term at December 31, 2020 and 2019, respectively. Settlement of these obligations is not expected to require the use of working capital within one year, and the company has both the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 18
Long-Term Debt
Total long-term debt including finance lease liabilities at December 31, 2020, was $42,767. The company’s long-term debt outstanding at year-end 2020 and 2019 was as follows:
At December 31
2020 2019
Weighted Average Interest Rate (%)1
Range of Interest Rates (%)2
Principal Principal
Notes due 2021 2.100 $ 1,350 $ 1,350
Floating rate notes due 2021 0.913 0.751 - 1.171
650 650
Debentures due 2021 8.875 40 40
Notes due 2022 2.179 0.333 - 2.498
3,800 3,400
Floating rate notes due 2022 0.594 0.324 - 0.762
1,000 650
Notes due 2023 2.377 0.426 - 7.250
4,800 3,000
Floating rate notes due 2023 0.676 0.414 - 1.114
800 -
Notes due 2024 3.291 2.895 - 3.900
1,650 1,000
Notes due 2025 1.724 0.687 - 3.326
4,000 750
Notes due 2026 2.954 2,250 2,250
Notes due 2027 2.379 1.018 - 8.000
2,000 -
Notes due 2028 3.850 600 -
Notes due 2029 3.250 500 -
Notes due 2030 2.236 1,500 -
Debentures due 2031 8.625 108 108
Debentures due 2032 8.414 8.000 - 8.625
222 222
Notes due 2040 2.978 500 -
Notes due 2041 6.000 850 -
Notes due 2043 5.250 1,000 -
Notes due 2044 5.050 850 -
Notes due 2047 4.950 500 -
Notes due 2049 4.200 500 -
Notes due 2050 2.763 2.343 - 3.078
1,750 -
Debentures due 2097 7.250 84 -
Bank loans due 2021 - 2023 1.530 1.240 - 2.004
1,948 -
3.400% loan3
3.400 218 218
Medium-term notes, maturing from 2021 to 2038 6.131 0.000 - 8.875
37 38
Notes due 2020 - 5,054
Total including debt due within one year 33,507 18,730
Debt due within one year (2,600) (5,054)
Fair market valuation adjustment of Noble long-term debt 1,690 -
Reclassified from short-term debt 9,825 9,750
Unamortized discounts and debt issuance costs (102) (17)
Finance lease liabilities4
447 282
Total long-term debt $ 42,767 $ 23,691
1 Weighted-average interest rate at December 31, 2020
2 Range of interest rates at December 31, 2020.
3 Maturity date is conditional upon the occurrence of certain events. 2022 is the earliest period in which the loan may become payable
4 For details on finance lease liabilities, see Note 5 beginning on page 69
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 $33,507 matures as follows: 2021 - $2,600; 2022 - $5,548; 2023 - $6,475; 2024 - $1,650; 2025 - $4,000; and after 2025 - $13,234.
The company completed bond issuances of $8,000 and $4,000 in May and August 2020, respectively. Chevron also assumed total debt, including finance lease obligations, with a fair value of approximately $9,400, associated with the acquisition of Noble on October 5, 2020.
Included in the debt assumed from Noble were senior notes, with an aggregate principal amount of $5,800, with interest rates ranging from 3.250 percent to 8.000 percent and maturity dates ranging from 2023 to 2049. On January 6, 2021, Chevron announced that the aggregate principal amount of $5,697 of prior Noble senior notes were exchanged for new
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
senior notes issued by CUSA, guaranteed by Chevron, and having the same interest rates and maturity dates as the Noble senior notes. The aggregate principal amount of $5,697 prior Noble notes were validly tendered and accepted and subsequently terminated. Following such termination, $103 aggregate principal amount remains outstanding across ten series of senior notes issued by Noble, for which Chevron provided no guarantee, and the indentures were modified to eliminate any financial reporting or credit rating requirements. In February 2021, the indenture governing Noble’s 7.250 percent senior debentures due 2097 was modified to provide a guarantee by Chevron and eliminate any financial reporting or credit rating requirements.
See Note 7, beginning on page 71, for information concerning the fair value of the company’s long-term debt.
Note 19
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.
The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended December 31, 2020:
2020 2019 2018
Beginning balance at January 1 $ 3,041 $ 3,563 $ 3,702
Additions to capitalized exploratory well costs pending the determination of proved reserves
28 244 207
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
(102) (500) (13)
Capitalized exploratory well costs charged to expense
(667) (125) (333)
Other*
212 (141) -
Ending balance at December 31 $ 2,512 $ 3,041 $ 3,563
* 2020 represents fair value of well costs acquired in the Noble acquisition. 2019 represents property sales.
The following table provides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling. The aging of the former Noble wells is based on the date the drilling was completed, rather than Chevron’s October 2020 acquisition of Noble.
At December 31
2020 2019 2018
Exploratory well costs capitalized for a period of one year or less
$ 26 $ 214 $ 202
Exploratory well costs capitalized for a period greater than one year
2,486 2,827 3,361
Balance at December 31 $ 2,512 $ 3,041 $ 3,563
Number of projects with exploratory well costs that have been capitalized for a period greater than one year*
17 22 30
* Certain projects have multiple wells or fields or both.
Of the $2,486 of exploratory well costs capitalized for more than one year at December 31, 2020, $1,197 is related to 7 projects that had drilling activities underway or firmly planned for the near future. The $1,289 balance is related to 10 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 $1,289 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability: (a) $826 (seven projects) - undergoing front-end engineering and design with final investment decision expected within four years; (b) $463 (three projects) - development alternatives under review. While progress was being made on all 17 projects, the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations associated with the projects. More than half of these decisions are expected to occur in the next five years.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
The $2,486 of suspended well costs capitalized for a period greater than one year as of December 31, 2020, represents 89 exploratory wells in 17 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 $ 342 17
2010-2014 1,457 54
2015-2019 687 18
Total $ 2,486 89
Aging based on drilling completion date of last suspended well in project: Amount Number of projects
2003-2012 $ 371 4
2013-2016 1,627 8
2017-2020 488 5
Total $ 2,486 17
Note 20
Stock Options and Other Share-Based Compensation
Compensation expense for stock options for 2020, 2019 and 2018 was $94 ($74 after tax), $81 ($64 after tax) and $105 ($83 after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance shares and restricted stock units was $96 ($76 after tax), $313 ($266 after tax) and $60 ($47 after tax) for 2020, 2019 and 2018, respectively. No significant stock-based compensation cost was capitalized at December 31, 2020, or December 31, 2019.
Cash received in payment for option exercises under all share-based payment arrangements for 2020, 2019 and 2018 was $226, $1,090 and $1,159, respectively. Actual tax benefits realized for the tax deductions from option exercises were $8, $43 and $43 for 2020, 2019 and 2018, respectively.
Cash paid to settle performance shares, restricted stock units and stock appreciation rights was $95, $119 and $157 for 2020, 2019 and 2018, respectively. Cash paid in 2020 included $11 million for Noble awards paid under change-in-control plan provisions.
Awards under the Chevron Long-Term Incentive Plan (LTIP) may take the form of, but are not limited to, stock options, restricted stock, restricted stock units, stock appreciation rights, performance shares and nonstock grants. From April 2004 through May 2023, no more than 260 million shares may be issued under the LTIP. For awards issued on or after May 29, 2013, no more than 50 million of those shares may be in a form other than a stock option, stock appreciation right or award requiring full payment for shares 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. Forfeitures for performance shares, restricted stock units, and stock appreciation rights are recognized as they occur. Forfeitures for stock options are estimated using historical forfeiture data dating back to 1990.
Noble Share-Based Plans (Noble Plans) On the closing of the acquisition of Noble in October 2020, outstanding stock options granted under various Noble Plans were exchanged for fully vested Chevron options at a conversion rate of 0.1191 Chevron shares for each Noble share. These awards retained the same provision as the original Noble Plans. Awards issued may be exercised for up to 5 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, phantom stock units, and performance shares that 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, phantom stock units and performance shares become vested on the termination date.
Fair Value and Assumptions The fair market values of stock options and stock appreciation rights granted in 2020, 2019 and 2018 were measured on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions:
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Year ended December 31
2020 2019 2018
Expected term in years1
6.6 6.6 6.5
Volatility2
20.8 % 20.5 % 21.2 %
Risk-free interest rate based on zero coupon U.S. treasury note
1.5 % 2.6 % 2.6 %
Dividend yield 4.0 % 3.8 % 3.8 %
Weighted-average fair value per option granted $ 13.00 $ 15.82 $ 18.18
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, including Noble, during 2020 is presented below:
Shares (Thousands) Weighted-Average
Exercise Price Averaged Remaining Contractual Term (Years) Aggregate Intrinsic Value
Outstanding at January 1, 2020 86,641 $ 103.22
Granted 8,281 $ 150.98
Exercised (2,739) $ 78.92
Forfeited (2,033) $ 110.72
Outstanding at December 31, 2020 90,150 $ 108.17 4.11 $ 23
Exercisable at December 31, 2020 80,860 $ 107.65 3.59 $ 23
The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2020, 2019 and 2018 was $92, $516 and $506, respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.
As of December 31, 2020, there was $57 of total unrecognized before-tax compensation cost related to nonvested share-based compensation arrangements granted under the plan. That cost is expected to be recognized over a weighted-average period of 1.7 years.
At January 1, 2020, the number of LTIP performance shares outstanding was equivalent to 4,386,784 shares. During 2020, 2,064,598 performance shares were granted, 676,282 shares vested with cash proceeds distributed to recipients and 1,340,303 shares were forfeited. At December 31, 2020, performance shares outstanding were 4,434,797. The fair value of the liability recorded for these instruments was $385, and was measured using the Monte Carlo simulation method.
At January 1, 2020, the number of restricted stock units outstanding was equivalent to 2,512,345 shares. During 2020, 1,253,337 restricted stock units were granted, 165,007 units vested with cash proceeds distributed to recipients and 296,742 units were forfeited. At December 31, 2020, restricted stock units outstanding were 3,303,933. The fair value of the liability recorded for the vested portion of these instruments was $197, valued at the stock price as of December 31, 2020. In addition, outstanding stock appreciation rights that were granted under LTIP totaled approximately 4.1 million equivalent shares as of December 31, 2020. The fair value of the liability recorded for the vested portion of these instruments was $34.
Note 21
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
Millions of dollars, except per-share amounts
The funded status of the company’s pension and OPEB plans for 2020 and 2019 follows:
Pension Benefits
2020 2019 Other Benefits
U.S. Int’l. U.S. Int’l. 2020 2019
Change in Benefit Obligation
Benefit obligation at January 1 $ 14,465 $ 5,680 $ 11,726 $ 4,820 $ 2,520 $ 2,430
Service cost 497 130 406 139 38 36
Interest cost 353 175 397 199 71 96
Plan participants’ contributions - 3 - 4 59 72
Plan amendments - - - 29 - -
Actuarial (gain) loss 1,782 550 2,922 673 191 125
Foreign currency exchange rate changes - 158 - 121 (1) 2
Benefits paid (2,045) (368) (1,035) (302) (214) (240)
Divestitures/Acquisitions 22 - 49 - - (1)
Curtailment 92 (21) - (3) (14) -
Benefit obligation at December 31 15,166 6,307 14,465 5,680 2,650 2,520
Change in Plan Assets
Fair value of plan assets at January 1 10,177 4,791 8,532 4,142 - -
Actual return on plan assets 848 500 1,548 566 - -
Foreign currency exchange rate changes - 174 - 115 - -
Employer contributions 950 263 1,096 266 155 168
Plan participants’ contributions - 3 - 4 59 72
Benefits paid (2,045) (368) (1,035) (302) (214) (240)
Divestitures/Acquisitions - - 36 - - -
Fair value of plan assets at December 31 9,930 5,363 10,177 4,791 - -
Funded status at December 31 $ (5,236) $ (944) $ (4,288) $ (889) $ (2,650) $ (2,520)
Amounts recognized on the Consolidated Balance Sheet for the company’s pension and OPEB plans at December 31, 2020 and 2019, include:
Pension Benefits
2020 2019 Other Benefits
U.S. Int’l. U.S. Int’l. 2020 2019
Deferred charges and other assets $ 24 $ 547 $ 23 $ 413 $ - $ -
Accrued liabilities (258) (76) (239) (71) (153) (174)
Noncurrent employee benefit plans (5,002) (1,415) (4,072) (1,231) (2,497) (2,346)
Net amount recognized at December 31 $ (5,236) $ (944) $ (4,288) $ (889) $ (2,650) $ (2,520)
For the years ended December 31, 2020 and December 31, 2019, the increase in benefit obligations was primarily due to actuarial losses caused by lower discount rates used to value the obligations.
Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $7,278 and $6,357 at the end of 2020 and 2019, respectively. These amounts consisted of:
Pension Benefits
2020 2019 Other Benefits
U.S. Int’l. U.S. Int’l. 2020 2019
Net actuarial loss $ 5,714 $ 1,401 $ 5,135 $ 1,269 $ 260 $ 74
Prior service (credit) costs 3 86 5 102 (186) (228)
Total recognized at December 31 $ 5,717 $ 1,487 $ 5,140 $ 1,371 $ 74 $ (154)
The accumulated benefit obligations for all U.S. and international pension plans were $13,608 and $5,758, respectively, at December 31, 2020, and $12,781 and $5,203, respectively, at December 31, 2019.
Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2020 and 2019, was:
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Pension Benefits
2020 2019
U.S. Int’l. U.S. Int’l.
Projected benefit obligations $ 15,103 $ 2,084 $ 14,401 $ 1,554
Accumulated benefit obligations 13,545 1,622 12,718 1,268
Fair value of plan assets 9,842 600 10,091 278
The components of net periodic benefit cost and amounts recognized in the Consolidated Statement of Comprehensive Income for 2020, 2019 and 2018 are shown in the table below:
Pension Benefits
2020 2019 2018 Other Benefits
U.S. Int’l. U.S. Int’l. U.S. Int’l. 2020 2019 2018
Net Periodic Benefit Cost
Service cost $ 497 $ 130 $ 406 $ 139 $ 480 $ 141 $ 38 $ 36 $ 42
Interest cost 353 175 397 199 370 206 71 96 94
Expected return on plan assets (650) (209) (565) (231) (636) (253) - - -
Amortization of prior service costs (credits) 2 10 2 11 2 10 (28) (28) (28)
Recognized actuarial losses 385 45 239 21 304 29 3 (3) 15
Settlement losses 620 37 259 3 411 33 - - -
Curtailment losses (gains) 92 2 - 16 - 3 (27) - -
Total net periodic benefit cost 1,299 190 738 158 931 169 57 101 123
Changes Recognized in Comprehensive Income
Net actuarial (gain) loss during period 1,584 230 1,939 338 151 12 190 128 (248)
Amortization of actuarial loss (1,005) (98) (498) (24) (715) (62) (4) 3 (15)
Prior service (credits) costs during period - - - 29 - 23 - (1) 3
Amortization of prior service (costs) credits (2) (17) (2) (30) (2) (13) 42 28 28
Total changes recognized in other
comprehensive income
577 115 1,439 313 (566) (40) 228 158 (232)
Recognized in Net Periodic Benefit Cost and Other Comprehensive Income
$ 1,876 $ 305 $ 2,177 $ 471 $ 365 $ 129 $ 285 $ 259 $ (109)
Assumptions The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31:
Pension Benefits
2020 2019 2018 Other Benefits
U.S. Int’l. U.S. Int’l. U.S. Int’l. 2020 2019 2018
Assumptions used to determine benefit obligations:
Discount rate 2.4 % 2.4 % 3.1 % 3.2 % 4.2 % 4.4 % 2.6 % 3.2 % 4.4 %
Rate of compensation increase 4.5 % 4.0 % 4.5 % 4.0 % 4.5 % 4.0 % N/A N/A N/A
Assumptions used to determine net periodic benefit cost:
Discount rate for service cost 3.3 % 3.2 % 4.4 % 4.4 % 3.7 % 3.9 % 3.5 % 4.6 % 3.9 %
Discount rate for interest cost 2.6 % 3.2 % 3.7 % 4.4 % 3.0 % 3.9 % 3.0 % 4.2 % 3.5 %
Expected return on plan assets 6.5 % 4.5 % 6.8 % 5.6 % 6.8 % 5.5 % N/A N/A N/A
Rate of compensation increase 4.5 % 4.0 % 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 2020, the company used an expected long-term rate of return of 6.50 percent for U.S. pension plan assets, which account for 65 percent of the company’s pension plan assets. In both 2019 and 2018, the company used a long-term rate of return of 6.75 percent for these plans.
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
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 at the end of 2020 were 2.4 for the main U.S. pension plan and 2.4 for the main U.S. OPEB plan. The discount rates for these plans at the end of 2019 were 3.1 and 3.1 percent, respectively, while in 2018 they were 4.2 and 4.3 percent for these plans, respectively.
Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2020, for the main U.S. OPEB plan, the assumed health care cost-trend rates start with 6.1 percent in 2021 and gradually decline to 4.5 percent for 2027 and beyond. For this measurement at December 31, 2019, the assumed health care cost-trend rates started with 6.8 percent in 2020 and gradually declined to 4.5 percent for 2025 and beyond.
Plan Assets and Investment Strategy
The fair value measurements of the company’s pension plans for 2020 and 2019 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, 2019
Equities
U.S.1
$ 1,769 $ 1,769 $ - $ - $ - $ 471 $ 471 $ - $ - $ -
International 1,958 1,958 - - - 422 421 - 1 -
Collective Trusts/Mutual Funds2
1,079 52 - - 1,027 184 6 - - 178
Fixed Income
Government 523 - 523 - - 265 144 121 - -
Corporate 1,444 - 1,444 - - 493 - 490 3 -
Bank Loans 120 - 113 7 - - - - - -
Mortgage/Asset Backed 1 - 1 - - 4 - 4 - -
Collective Trusts/Mutual Funds2
963 - - - 963 2,230 5 - - 2,225
Mixed Funds3
- - - - - 84 7 77 - -
Real Estate4
1,089 - - - 1,089 277 - - 55 222
Alternative Investments 924 - - - 924 - - - - -
Cash and Cash Equivalents 235 228 7 - - 338 334 2 - 2
Other5
72 (5) 29 44 4 23 - 21 2 -
Total at December 31, 2019 $ 10,177 $ 4,002 $ 2,117 $ 51 $ 4,007 $ 4,791 $ 1,388 $ 715 $ 61 $ 2,627
At December 31, 2020
Equities
U.S.1
$ 2,286 $ 2,286 $ - $ - $ - $ 443 $ 443 $ - $ - $ -
International 2,211 2,210 - 1 - 373 373 - - -
Collective Trusts/Mutual Funds2
1,107 48 - - 1,059 192 7 - - 185
Fixed Income
Government 231 - 231 - - 240 125 115 - -
Corporate 778 - 778 - - 578 10 568 - -
Bank Loans 129 - 127 2 - - - - - -
Mortgage/Asset Backed 1 - 1 - - 4 - 4 - -
Collective Trusts/Mutual Funds2
1,901 13 - - 1,888 2,520 4 - - 2,516
Mixed Funds3
- - - - - 127 38 89 - -
Real Estate4
1,018 - - - 1,018 448 - - 45 403
Alternative Investments - - - - - - - - - -
Cash and Cash Equivalents 221 209 12 - - 417 408 3 - 6
Other5
47 (19) 22 41 3 21 (2) 19 4 -
Total at December 31, 2020 $ 9,930 $ 4,747 $ 1,171 $ 44 $ 3,968 $ 5,363 $ 1,406 $ 798 $ 49 $ 3,110
1U.S. equities include investments in the company’s common stock in the amount of $4 at December 31, 2020, and $6 at December 31, 2019.
2Collective Trusts/Mutual Funds for U.S. plans are entirely index funds; for International plans, they are mostly unit trust and index funds.
3Mixed funds are composed of funds that invest in both equity and fixed-income instruments in order to diversify and lower risk.
4The year-end valuations of the U.S. real estate assets are based on third-party appraisals that occur at least once a year for each property in the portfolio.
5The “Other” asset class includes net payables for securities purchased but not yet settled (Level 1); dividends and interest- and tax-related receivables (Level 2); insurance contracts (Level 3); and investments in private-equity limited partnerships (NAV).
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below:
Equity Fixed Income
International Corporate Bank Loans Real Estate Other Total
Total at December 31, 2018 $ 1 $ 21 $ 5 $ 56 $ 46 $ 129
Actual Return on Plan Assets:
Assets held at the reporting date (1) 1 - - (1) (1)
Assets sold during the period - - - - - -
Purchases, Sales and Settlements - (19) - (1) 1 (19)
Transfers in and/or out of Level 3 1 - 2 - - 3
Total at December 31, 2019 $ 1 $ 3 $ 7 $ 55 $ 46 $ 112
Actual Return on Plan Assets:
Assets held at the reporting date - - - - 1 1
Assets sold during the period - - - (10) - (10)
Purchases, Sales and Settlements - (3) (5) - (2) (10)
Transfers in and/or out of Level 3 - - - - - -
Total at December 31, 2020 $ 1 $ - $ 2 $ 45 $ 45 $ 93
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 91 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 40-65 percent, Fixed Income 20-40 percent, Real Estate 0-15 percent, Alternative Investments 0-5 percent and Cash 0-25 percent. For the U.K. pension plan, the U.K. Board of Trustees has established the following asset allocation guidelines: Equities 10-30 percent, Fixed Income 55-85 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 2020, the company contributed $950 and $263 to its U.S. and international pension plans, respectively. In 2021, the company expects contributions to be approximately $1,050 to its U.S. plans and $200 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 $153 in 2021; $155 was paid in 2020.
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
2021 $ 1,779 $ 658 $ 153
2022 919 220 162
2023 1,069 225 158
2024 1,097 243 154
2025 1,068 250 151
2026-2030 4,856 1,400 706
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 $281, $284 and $270 in 2020, 2019 and 2018, respectively.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Benefit Plan Trusts Prior to its acquisition by Chevron, Texaco established a benefit plan trust for funding obligations under some of its benefit plans. At year-end 2020, 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, 2020 and 2019, trust assets of $36 and $35, 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 $462, $826 and $1,048 in 2020, 2019 and 2018, 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 20, beginning on page 86.
Note 22
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 15, beginning on page 79, 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 two guarantees to equity affiliates totaling $391. Of this amount, $137 is associated with a financing arrangement with an equity affiliate. Over the approximate 1-year remaining term of this guarantee, the maximum amount will be reduced as payments are made by the affiliate. The remaining amount of $254 is associated with certain payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 7-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 either guarantee.
Indemnifications In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets that were sold in 1997. The acquirer of those assets shared in certain environmental remediation costs up to a maximum obligation of $200, which had been reached at December 31, 2009. Under the indemnification agreement, after reaching the $200 obligation, Chevron is solely responsible until April 2022, when the indemnification expires. The environmental conditions or events that are subject to these indemnities must have arisen prior to the sale of the assets in 1997.
Although the company has provided for known obligations under this indemnity that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity.
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 approximate amounts of required payments under these various commitments are: 2021 - $1,000; 2022 - $1,200; 2023 - $1,300; 2024 - $1,300; 2025 - $1,400; 2026 and after - $8,400. A portion of these commitments may
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
ultimately be shared with project partners. Total payments under the agreements were approximately $500 in 2020, $800 in 2019 and $1,400 in 2018.
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, including MTBE, by the company or other parties. Such contingencies may exist for various operating, closed and divested sites, including, but not limited to, 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, 2020, was $1,139. Included in this balance was $247 related to remediation activities at approximately 145 sites for which the company had been identified as a potentially responsible party under the provisions of the 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 2020 environmental reserves balance of $892, $611 is related to the company’s U.S. downstream operations, $47 to its international downstream operations, $233 to upstream operations and $1 to other businesses. 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 2020 had a recorded liability that was material to the company’s results of operations, consolidated financial position or liquidity.
Refer to Note 23 on page 94 for a discussion of the company’s asset retirement obligations.
Other Contingencies Governmental and other entities in California and other jurisdictions have filed legal proceedings against fossil fuel producing companies, including Chevron, purporting to seek legal and equitable relief to address alleged impacts of climate change. Further such proceedings are likely to be filed by other parties. The unprecedented legal theories set forth in these proceedings entail the possibility of damages liability and injunctions against the production of all fossil fuels that, while we believe remote, could have a material adverse effect on the company’s results of operations and financial condition. Management believes that these proceedings are legally and factually meritless and detract from constructive efforts to address the important policy issues presented by climate change, and will vigorously defend against such proceedings.
Seven coastal parishes and the State of Louisiana have filed 43 separate 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.
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,
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
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 23
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.
The following table indicates the changes to the company’s before-tax asset retirement obligations in 2020, 2019 and 2018:
2020 2019 2018
Balance at January 1 $ 12,832 $ 14,050 $ 14,214
Liabilities assumed in the Noble acquisition 630 - -
Liabilities incurred 10 32 96
Liabilities settled (1,661) (1,694) (830)
Accretion expense 560 628 654
Revisions in estimated cash flows 1,245 (184) (84)
Balance at December 31 $ 13,616 $ 12,832 $ 14,050
In the table above, the amount associated with “Revisions in estimated cash flows” in 2020 reflects increased cost estimates to decommission wells, equipment and facilities. The long-term portion of the $13,616 balance at the end of 2020 was $11,877.
Note 24
Revenue
Revenue from contracts with customers is presented in “Sales and other operating revenue” 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 12 beginning on page 74 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 $7,631 and $9,247 at December 31, 2020 and December 31, 2019, 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.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 25
Other Financial Information
Earnings in 2020 included after-tax gains of approximately $765 relating to the sale of certain properties. Of this amount, approximately $30 and $735 related to downstream and upstream, respectively. Earnings in 2019 included after-tax gains of approximately $1,500 relating to the sale of certain properties, of which approximately $50 and $1,450 related to downstream and upstream assets, respectively. Earnings in 2018 included after-tax gains of approximately $630 relating to the sale of certain properties, of which approximately $365 and $265 related to downstream and upstream assets, respectively. Earnings in 2020 included after-tax charges of approximately $4,800 for impairments and other asset write-offs related to upstream. Earnings in 2019 included after-tax charges of approximately $10,400 for impairments and other asset write-offs related to upstream. Earnings in 2018 included after-tax charges of approximately $2,000 for impairments and other asset write-offs related to upstream.
Other financial information is as follows:
Year ended December 31
2020 2019 2018
Total financing interest and debt costs $ 735 $ 817 $ 921
Less: Capitalized interest 38 19 173
Interest and debt expense $ 697 $ 798 $ 748
Research and development expenses $ 435 $ 500 $ 453
Excess of replacement cost over the carrying value of inventories (LIFO method)
$ 2,749 $ 4,513 $ 5,134
LIFO profits (losses) on inventory drawdowns included in earnings $ (147) $ (9) $ 26
Foreign currency effects*
$ (645) $ (304) $ 611
* Includes $(152), $(28) and $416 in 2020, 2019 and 2018, respectively, for the company’s share of equity affiliates’ foreign currency effects.
The company has $4,402 in goodwill on the Consolidated Balance Sheet, all of which is in the upstream segment and primarily related to the 2005 acquisition of Unocal. The company tested this goodwill for impairment during 2020, and no impairment was required.
Note 26
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 13, on page 77, for a discussion of CPChem operations. Summarized financial information for 100 percent of CPChem is presented in the table below:
Year ended December 31
2020 2019 2018
Sales and other operating revenues $ 8,407 $ 9,333 $ 11,310
Costs and other deductions 7,221 7,863 9,812
Net income attributable to CPChem 1,260 1,760 2,069
At December 31
2020 2019
Current assets $ 2,816 $ 2,554
Other assets 14,210 14,314
Current liabilities 1,394 1,247
Other liabilities 3,380 3,174
Total CPChem net equity $ 12,252 $ 12,447
Note 27
Restructuring and Reorganization Costs
In 2020, the company recorded severance accruals and adjustments for employee reduction programs related to enterprise-wide restructuring, which are expected to be substantially completed by the end of 2021.
A before-tax charge of $859 ($670 after-tax) was recorded in 2020, with $690 reported as "Operating expenses" and $169 reported as “Selling, general and administrative expenses" on the Consolidated Statement of Income. Approximately $127 ($97 after-tax) is associated with terminations in U.S. Upstream, $288 ($228 after-tax) in International Upstream, $112 ($85 after-tax) in U.S. Downstream, $69 ($54 after-tax) in International Downstream and $263 ($206 after-tax) in All Other.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
During 2020, the company made payments of $396 associated with these liabilities. The following table summarizes the accrued severance liability, which is classified as current on the Consolidated Balance Sheet.
Amounts Before Tax
Balance at January 1, 2020 $ 7
Accruals/Adjustments 859
Payments (396)
Balance at December 31, 2020 $ 470
Note 28
Financial Instruments - Credit Losses
Chevron adopted Accounting Standards Update (ASU) 2016-13, Financial Instruments - Credit Losses, and its related amendments at the effective date of January 1, 2020. The standard replaces the “incurred loss model” and requires an estimate of expected credit losses, measured over the contractual life of a financial instrument, that considers forecast of future economic conditions in addition to information about past events and current conditions. The cumulative-effect adjustment to the opening retained earnings at January 1, 2020 was a reduction of $25, representing a decrease to the net accounts and notes receivable balances shown on the company’s consolidated balance sheet on page 61. Chevron’s expected credit loss allowance balance was $671 as of December 31, 2020 and $849 as of December 31, 2019, with a majority of the allowance relating to non-trade receivable balances. A reduction in the allowance for non-trade receivables of $550 was recorded in the second quarter as an agreement was reached with a government joint venture partner that resulted in the write-off of the associated receivable balances. Additionally, new allowances of $265 were recorded in the second and third quarters associated with other than trade receivables.
The majority of the company’s receivable balance is concentrated in trade receivables, with a balance of $9.5 billion as of December 31, 2020, 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 pre-payments, 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. The company continues to monitor credit risk in response to the COVID-19 pandemic and the significant reduction in crude prices resulting from decreased demand associated with government-mandated travel restrictions.
Chevron's non-trade receivable balance was $3.3 billion as of December 31, 2020, 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.
Equity affiliate loans are also considered non-trade and during the second quarter 2020 review, a $560 allowance was recognized within “Investments and advances” on the Consolidated Balance Sheet.
Note 29
Acquisition of Noble Energy, Inc.
On October 5, 2020, the company acquired Noble Energy, Inc., an independent oil and gas exploration and production company. Noble’s principal upstream operations are in the United States, the Eastern Mediterranean and West Africa. Noble’s operations also include an integrated midstream business in the United States. The acquisition of Noble provides the company with low-cost proved reserves, attractive undeveloped resources and cash-generating assets.
The aggregate purchase price of Noble was $4,109, with approximately 58 million shares of Chevron common stock issued as consideration in the transaction, representing approximately 3 percent of shares of Chevron common stock outstanding
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
immediately after the acquisition. As part of the transaction, the company recognized long-term debt and finance leases with a fair value of $9,231.
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. Oil and gas properties were valued using a discounted cash flow approach that incorporated internally generated price assumptions and production profiles together with appropriate operating cost and development cost assumptions. Debt assumed in the acquisition was valued based on observable market prices for Noble’s debt. As a result of measuring the assets acquired and the liabilities assumed at fair value, there was no goodwill or bargain purchase recognized.
The following table summarizes the values assigned to assets acquired and liabilities assumed:
At October 5, 2020
Current assets $ 1,105
Investments and long-term receivables 1,282
Properties (includes $14,935 for oil and gas properties)
16,703
Other assets 607
Total assets acquired 19,697
Current liabilities 1,829
Long-term debt and finance leases 9,231
Deferred income taxes 2,355
Other liabilities 1,394
Total liabilities assumed 14,809
Noncontrolling interest and redeemable noncontrolling interest 779
Net assets acquired $ 4,109
The following unaudited pro forma summary presents the results of operations as if the acquisition of Noble had occurred January 1, 2019:
Year ended December 31
2020 2019
Sales and other operating revenues $ 96,980 $ 144,303
Net income $ (9,890) $ 1,412
The pro forma summary uses estimates and assumptions based on information available at the time. Management believes the estimates and assumptions to be reasonable; however, actual results may differ significantly from this pro forma financial information. The pro forma information does not reflect any synergistic savings that might be achieved from combining the operations and is not intended to reflect the actual results that would have occurred had the companies actually been combined during the periods presented.
Five-Year Financial Summary
Unaudited
Supplemental Information on Oil and Gas Producing Activities - Unaudited
In accordance with FASB and SEC disclosure requirements for oil and gas producing activities, this section provides supplemental information on oil and gas exploration and producing activities of the company in seven separate tables. Tables I through IV provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables V through VII present information on the company’s
Table I - Costs Incurred in Exploration, Property Acquisitions and Development1
Consolidated Companies Affiliated Companies
Other Australia/
Millions of dollars U.S. Americas Africa Asia Oceania Europe Total TCO Other
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
Year Ended December 31, 2019
Exploration
Wells $ 571 $ 44 $ 9 $ 2 $ 4 $ 4 $ 634 $ - $ -
Geological and geophysical 82 118 21 5 11 1 238 - -
Other 140 52 35 29 44 6 306 - 8
Total exploration 793 214 65 36 59 11 1,178 - 8
Property acquisitions2
Proved 81 34 - 93 - - 208 - -
Unproved 68 150 - 17 1 - 236 - -
Total property acquisitions 149 184 - 110 1 - 444 - -
Development3
7,072 1,216 279 1,020 518 199 10,304 5,112 158
Total Costs Incurred4
$ 8,014 $ 1,614 $ 344 $ 1,166 $ 578 $ 210 $ 11,926 $ 5,112 $ 166
Year Ended December 31, 2018
Exploration
Wells $ 508 $ 74 $ 25 $ 55 $ - $ 14 $ 676 $ - $ -
Geological and geophysical 84 41 4 5 7 1 142 - -
Other 190 46 35 33 49 23 376 - -
Total exploration 782 161 64 93 56 38 1,194 - -
Property acquisitions2
Proved 160 - 7 117 - - 284 - -
Unproved 52 494 2 27 - - 575 - -
Total property acquisitions 212 494 9 144 - - 859 - -
Development3
6,245 856 711 1,095 845 278 10,030 4,963 200
Total Costs Incurred4
$ 7,239 $ 1,511 $ 784 $ 1,332 $ 901 $ 316 $ 12,083 $ 4,963 $ 200
1 Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. Includes capitalized amounts related to asset retirement obligations. See Note 23, “Asset Retirement Obligations,” on page 94.
2 Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired in nonmonetary transactions.
3 Includes $897, $246 and $114 of costs incurred on major capital projects prior to assignment of proved reserves for consolidated companies in 2020, 2019, and 2018, respectively.
4 Reconciliation of consolidated and affiliated companies total cost incurred to Upstream capital and exploratory (C&E) expenditures - $ billions:
2020 2019 2018
Total cost incurred $ 26.6 $ 17.2 $ 17.2
Noble acquisition (14.9) - - See Note 29 for additional information
Non-oil and gas activities - 0.3 0.6 (Primarily; LNG and transportation activities.)
ARO reduction/(build) (0.8) 0.3 (0.1)
Upstream C&E $ 10.9 $ 17.8 $ 17.7 Reference page 44 Upstream total
Supplemental Information on Oil and Gas Producing Activities - Unaudited
estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows. The amounts for consolidated companies are organized by geographic areas including the United States, Other Americas, Africa, Asia, Australia/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 13, beginning on page 77, 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 Australia/
Millions of dollars U.S. Americas Africa Asia Oceania Europe Total TCO Other
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
At December 31, 2019
Unproved properties $ 4,620 $ 2,492 $ 151 $ 1,081 $ 1,986 $ - $ 10,330 $ 108 $ -
Proved properties and
related producing assets
82,199 24,189 45,756 56,648 22,032 2,082 232,906 10,757 4,311
Support equipment 2,287 311 1,098 2,075 18,610 - 24,381 1,981 -
Deferred exploratory wells 533 147 405 513 1,322 121 3,041 - -
Other uncompleted projects 5,080 505 1,176 926 1,023 15 8,725 16,503 743
Gross Capitalized Costs 94,719 27,644 48,586 61,243 44,973 2,218 279,383 29,349 5,054
Unproved properties valuation 3,964 1,271 120 842 109 - 6,306 65 -
Proved producing properties - Depreciation and depletion
56,911 12,644 33,613 44,871 6,064 404 154,507 6,018 1,912
Support equipment depreciation 1,635 226 772 1,605 2,272 - 6,510 1,053 -
Accumulated provisions 62,510 14,141 34,505 47,318 8,445 404 167,323 7,136 1,912
Net Capitalized Costs $ 32,209 $ 13,503 $ 14,081 $ 13,925 $ 36,528 $ 1,814 $ 112,060 $ 22,213 $ 3,142
At December 31, 2018
Unproved properties $ 4,687 $ 2,463 $ 201 $ 1,299 $ 1,986 $ - $ 10,636 $ 108 $ -
Proved properties and
related producing assets
75,013 21,796 44,876 57,168 22,047 12,634 233,534 9,892 4,336
Support equipment 2,216 317 1,096 2,149 17,712 124 23,614 1,858 -
Deferred exploratory wells 782 160 405 632 1,323 261 3,563 - -
Other uncompleted projects 4,730 3,704 1,744 1,292 1,462 300 13,232 12,311 605
Gross Capitalized Costs 87,428 28,440 48,322 62,540 44,530 13,319 284,579 24,169 4,941
Unproved properties valuation 820 694 164 623 107 - 2,408 61 -
Proved producing properties - Depreciation and depletion
45,712 12,984 31,102 43,735 4,631 10,014 148,178 5,276 1,730
Support equipment depreciation 1,466 220 738 1,674 1,531 119 5,748 947 -
Accumulated provisions 47,998 13,898 32,004 46,032 6,269 10,133 156,334 6,284 1,730
Net Capitalized Costs $ 39,430 $ 14,542 $ 16,318 $ 16,508 $ 38,261 $ 3,186 $ 128,245 $ 17,885 $ 3,211
Supplemental Information on Oil and Gas Producing Activities - Unaudited
Table III - Results of Operations for Oil and Gas Producing Activities1
The company’s results of operations from oil and gas producing activities for the years 2020, 2019 and 2018 are shown in the following table. Net income (loss) from exploration and production activities as reported on page 75 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 net income amounts on page 75.
Consolidated Companies Affiliated Companies
Other Australia/
Millions of dollars U.S. Americas Africa Asia Oceania 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)
Year Ended December 31, 2019
Revenues from net production
Sales $ 2,259 $ 863 $ 668 $ 7,410 $ 4,332 $ 592 $ 16,124 $ 5,603 $ 780
Transfers 11,043 2,160 6,534 1,311 2,596 655 24,299 - -
Total 13,302 3,023 7,202 8,721 6,928 1,247 40,423 5,603 780
Production expenses excluding taxes (3,567) (1,020) (1,460) (2,703) (616) (343) (9,709) (475) (247)
Taxes other than on income (595) (64) (101) (16) (221) (2) (999) (57) (10)
Proved producing properties:
Depreciation and depletion (11,659) (1,380) (2,548) (3,165) (2,192) (85) (21,029) (870) (211)
Accretion expense2
(191) (21) (148) (133) (53) (37) (583) (5) (8)
Exploration expenses (293) (211) (73) (93) (60) (10) (740) - (8)
Unproved properties valuation (3,268) (591) (2) (388) (2) - (4,251) (4) -
Other income (expense)3
(51) (44) (121) 413 53 1,373 1,623 1 (157)
Results before income taxes (6,322) (308) 2,749 2,636 3,837 2,143 4,735 4,193 139
Income tax (expense) benefit 1,311 (27) (1,731) (1,212) (1,161) (311) (3,131) (1,261) (73)
Results of Producing Operations $ (5,011) $ (335) $ 1,018 $ 1,424 $ 2,676 $ 1,832 $ 1,604 $ 2,932 $ 66
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 23, “Asset Retirement Obligations,” on page 94.
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
Table III - Results of Operations for Oil and Gas Producing Activities1, continued
Consolidated Companies Affiliated Companies
Other Australia/
Millions of dollars U.S. Americas Africa Asia Oceania Europe Total TCO Other
Year Ended December 31, 2018
Revenues from net production
Sales $ 2,162 $ 1,008 $ 829 $ 5,880 $ 4,229 $ 619 $ 14,727 $ 5,987 $ 1,369
Transfers 11,645 1,808 7,829 3,206 3,413 1,071 28,972 - -
Total 13,807 2,816 8,658 9,086 7,642 1,690 43,699 5,987 1,369
Production expenses excluding taxes (3,203) (1,009) (1,564) (2,653) (557) (424) (9,410) (447) (295)
Taxes other than on income (540) (70) (112) (22) (250) (2) (996) 160 (210)
Proved producing properties:
Depreciation and depletion (4,583) (998) (3,368) (3,714) (2,103) (411) (15,177) (711) (306)
Accretion expense2
(186) (26) (149) (146) (50) (52) (609) (4) (3)
Exploration expenses (777) (191) (52) (58) (56) (41) (1,175) (3) (6)
Unproved properties valuation (516) (42) (3) (135) - - (696) - -
Other income (expense)3
336 4 97 (33) 31 (161) 274 70 (280)
Results before income taxes 4,338 484 3,507 2,325 4,657 599 15,910 5,052 269
Income tax (expense) benefit (886) (400) (2,131) (1,088) (1,415) (233) (6,153) (1,519) 341
Results of Producing Operations $ 3,452 $ 84 $ 1,376 $ 1,237 $ 3,242 $ 366 $ 9,757 $ 3,533 $ 610
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 23, “Asset Retirement Obligations,” on page 94.
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 Australia/
U.S. Americas Africa Asia Oceania Europe Total TCO Other
Year Ended December 31, 2020
Average sales prices
Liquids, per barrel $ 30.53 $ 35.41 $ 38.06 $ 39.77 $ 38.03 $ 34.20 $ 34.12 $ 24.25 $ 24.07
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
Year Ended December 31, 2019
Average sales prices
Liquids, per barrel $ 48.54 $ 54.85 $ 62.27 $ 59.53 $ 60.15 $ 61.80 $ 54.47 $ 49.14 $ 45.25
Natural gas, per thousand cubic feet 1.07 2.24 1.84 4.73 7.54 4.43 4.86 0.79 0.99
Average production costs, per barrel2
10.48 15.97 11.90 12.74 4.08 14.28 10.62 3.53 7.93
Year Ended December 31, 2018
Average sales prices
Liquids, per barrel $ 58.17 $ 58.27 $ 69.75 $ 63.55 $ 68.78 $ 66.31 $ 62.45 $ 56.20 $ 56.41
Natural gas, per thousand cubic feet 1.86 2.62 2.55 4.48 8.78 7.54 5.54 0.77 3.19
Average production costs, per barrel2
11.18 17.32 11.29 12.15 3.95 14.21 10.78 3.59 9.29
1The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
2Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel.
Supplemental Information on Oil and Gas Producing Activities - Unaudited
Table V Reserve Quantity Information
Summary of Net Oil and Gas Reserves
2020 2019 2018
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. 1,157 - 346 2,503 1,121 - 258 2,998 1,061 - 179 2,396
Other Americas 168 597 6 222 174 540 5 397 156 545 3 393
Africa 497 - 68 1,629 525 - 67 1,472 568 - 60 1,316
Asia 358 - - 7,864 406 - - 3,382 470 - - 4,021
Australia/Oceania 115 - 4 8,951 136 - 4 10,697 127 - 5 10,084
Europe 23 - - 8 21 - - 8 81 - 3 205
Total Consolidated 2,318 597 424 21,177 2,383 540 334 18,954 2,463 545 250 18,415
Affiliated Companies
TCO 565 - 53 1,057 584 - 59 1,135 638 - 62 1,179
Other 2 - 12 322 114 - 10 308 65 55 11 308
Total Consolidated and Affiliated Companies 2,885 597 489 22,556 3,081 540 403 20,397 3,166 600 323 19,902
Proved Undeveloped
Consolidated Companies
U.S. 593 - 247 1,747 807 - 244 1,730 813 - 349 4,313
Other Americas 92 - 2 107 146 - 11 339 185 - 19 470
Africa 57 - 36 1,208 88 - 33 1,286 110 - 38 1,499
Asia 45 - - 319 107 - - 299 109 - - 289
Australia/Oceania 26 - - 2,434 30 - - 3,961 29 - - 3,647
Europe 38 - - 14 48 - - 18 65 - - 100
Total Consolidated 851 - 285 5,829 1,226 - 288 7,633 1,311 - 406 10,318
Affiliated Companies
TCO 985 - 49 961 889 - 44 869 866 - 39 755
Other 1 - 5 576 45 - 5 558 2 72 5 601
Total Consolidated and Affiliated Companies 1,837 - 339 7,366 2,160 - 337 9,060 2,179 72 450 11,674
Total Proved Reserves 4,722 597 828 29,922 5,241 540 740 29,457 5,345 672 773 31,576
Reserves Governance The company has adopted a comprehensive reserves and resource 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 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. Proved undeveloped reserves are the quantities expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.
Proved reserves are estimated by company asset teams composed of earth scientists and engineers. As part of the internal control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired by the Manager of Global Reserves, an organization that is separate from the Upstream operating organization. The
Supplemental Information on Oil and Gas Producing Activities - Unaudited
Manager of Global Reserves has more than 30 years’ 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 operating 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 volumes 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 upstream 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.
The acquisition of Noble was completed on October 5, 2020. Given the timing of the acquisition, Chevron has continued to rely on legacy Noble reserves staff and processes for reviewing reserves with input and guidance from the Chevron Reserves Advisory Committee. The processes include internal reviews and an external audit. Accordingly, Chevron continued to retain Netherland, Sewell & Associates, Inc. (NSAI), a third-party petroleum consulting firm, that completed an audit of the legacy Noble acquisition proved reserves at December 31, 2020 (representing approximately 15% of Chevron’s total reserves). Based upon their evaluation NSAI issued an unqualified audit opinion, and this report is attached as Exhibit 99.3 to this Annual Report on Form 10-K.
Technologies Used in Establishing Proved Reserves Additions In 2020, 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 4,007
Revisions (699)
Improved Recovery 1
Extension & Discoveries 123
Purchases 329
Sales (95)
Transfers to Proved Developed (262)
Quantity at December 31 3,404
Supplemental Information on Oil and Gas Producing Activities - Unaudited
In 2020, Revisions include a reduction of 392 million BOE in the United States, primarily from the Midland and Delaware basins where 300 million BOE was attributed to demotions due to capital reductions, commodity price effects and performance revisions, and 75 million BOE from the Gulf of Mexico, primarily from commodity price effects at Anchor. In Australia, there was a net reduction of 269 million BOE, primarily from demotion of compression volumes related to capital and approval delays at Jansz Io, partially offset by positive revisions at Gorgon (Gorgon and Jansz Io make up the Gorgon Project). A reduction of 85 million BOE was recorded in Canada, primarily from commodity price effects at Kaybob Duvernay. In Nigeria, there was a reduction of 67 million BOE, primarily from gas volume changes based on reduced demand and development plan changes at Meren. In Venezuela, there was a demotion of 48 million BOE, due to impairment and accounting methodology change. These negative revisions were partially offset by an increase of 143 million BOE in Kazakhstan, primarily from entitlement effects at TCO and Karachaganak.
In 2020, Extensions and Discoveries of 108 million BOE in the United States were primarily due to portfolio optimizations where future drilling in various fields is being targeted toward liquids-rich reservoirs with higher execution efficiencies in the Midland and Delaware basins.
The differences in 2020 Extensions and Discoveries of 124 million BOE, between the net quantities of Proved reserves of 247 million BOE as reflected on pages 106 to 109 and net quantities of Proved Undeveloped of 123 million BOE, are primarily due to proved extensions and discoveries that were not recognized as PUDs in the prior year but rather were recognized directly as proved developed.
Purchases of 329 million BOE in 2020 include 326 million BOE from the Noble acquisition, primarily in Israel and the DJ basin in the United States.
Sales of 95 million BOE in 2020 include 77 million BOE from the sale of the company’s interest in Azerbaijan.
Transfers to proved developed reserves in 2020 include 178 million BOE in the United States, primarily from the Midland and Delaware basin developments and 84 million BOE in Canada, Kazakhstan, and other international locations. These transfers are the consequence of development expenditures on completing wells and facilities.
During 2020, investments totaling approximately $6.3 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. In Asia, expenditures during the year totaled approximately $3.4 billion, primarily related to development projects of the TCO affiliate in Kazakhstan. The United States accounted for about $2.1 billion related primarily to various development activities in the Midland and Delaware basins and the Gulf of Mexico. In Africa, about $0.3 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, such as 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 2020, the company held approximately 1.6 billion BOE of proved undeveloped reserves that have remained undeveloped for five years or more. The majority of these reserves are in three locations where the company has a proven track record of developing major projects. In Australia, approximately 400 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 and infrastructure optimization. In Africa, approximately 200 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 1.3 billion BOE of proved undeveloped reserves with about 900 million BOE that have remained undeveloped for five years or more, with the majority related to the TCO affiliate in Kazakhstan. At TCO, further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with reservoir depletion and facility constraints.
Annually, the company assesses whether any changes have occurred in facts or circumstances, such as changes to development plans, regulations or government policies, that would warrant a revision to reserve estimates. In 2020, decreases in commodity prices negatively impacted the economic limits of oil and gas properties, resulting in proved reserve decreases, and positively 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
Supplemental Information on Oil and Gas Producing Activities - Unaudited
sections. Over the past three years, the ratio of proved undeveloped reserves to total proved reserves has ranged between 31 percent and 38 percent.
Proved Reserve Quantities For the three years ending December 31, 2020, 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.
At December 31, 2020, proved reserves for the company were 11.1 billion BOE. The company’s estimated net proved reserves of liquids including crude oil, condensate and synthetic oil for the years 2018, 2019 and 2020 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 2018 through 2020 are discussed below and shown in the table on the following page:
Revisions In 2018, improved field performance at various Gulf of Mexico fields and in the Midland and Delaware basins were primarily responsible for the 121 million barrel increase in the United States. Improved field performance at various fields, including Agbami in Nigeria and Moho-Bilondo in the Republic of Congo, were responsible for the 61 million barrel increase in Africa. Reserves in Other Americas increased by 59 million barrels, primarily due to improved field performance at the Hebron field in Canada. In Asia, improved performance across numerous assets resulted in the 37 million barrel increase.
In 2019, portfolio optimizations, where future drilling in various fields in the Midland and Delaware basins is being targeted away from reservoirs with higher gas-to-oil ratios and lower execution efficiencies, and planned divestments in the Appalachian basin, were primarily responsible for the 153 million barrel decrease in the United States. Operational issues with the Petropiar upgrader in Venezuela resulted in a decrease in reserves of synthetic oil of 126 million barrels and an increase of crude oil and condensate reserves of 105 million barrels. Reservoir management and entitlement effects were mainly responsible for 75 million barrels increase in the TCO affiliate in Kazakhstan. Improved field performance at various fields, including Moho-Bilondo in the Republic of Congo, Mafumeria in Angola, and Sonam in Nigeria, were responsible for the 42 million barrel increase in Africa.
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 the TCO affiliate were primarily responsible for the 180 million barrels increase. Entitlement effects primarily contributed to an increase of 77 million barrels synthetic oil at the Athabasca Oil sands in Canada and 74 million barrels at multiple locations in Asia.
Extensions and Discoveries In 2018, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 359 million barrel increase in the United States. Extensions and discoveries in the Duvernay Shale in Canada and Loma Campana in Argentina were primarily responsible for the 31 million barrel increase in Other Americas.
In 2019, portfolio optimizations, where future drilling in various fields in the Midland and Delaware basins is being targeted towards liquids-rich reservoirs with higher execution efficiencies, and extensions and discoveries in the deepwater fields in the Gulf of Mexico, were primarily responsible for the 394 million barrel increase in the United States. Extensions and discoveries in Loma Campana in Argentina were primarily responsible for the 39 million barrel increase in Other Americas.
In 2020, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 105 million barrels increase in the United States.
Purchases In 2018, purchases of 31 million barrels in the United States were primarily in the Midland and Delaware basins.
In 2020, the acquisition of Noble assets contributed 227 million barrels in the DJ basin, Midland and Delaware basins in the United States.
Sales In 2019, sales of 69 million barrels in Europe were in the United Kingdom and Denmark.
In 2020, sale of 99 million barrels in Asia were in Azerbaijan.
Supplemental Information on Oil and Gas Producing Activities - Unaudited
Net Proved Reserves of Crude Oil, Condensate and Synthetic Oil
Consolidated Companies Affiliated Companies Total
Consolidated
Other Australia/ Synthetic Synthetic and Affiliated
Millions of barrels U.S. Americas1
Africa Asia Oceania Europe Oil2
Total TCO Oil Other3
Companies
Reserves at January 1, 2018 1,573 280 743 631 153 142 543 4,065 1,630 159 83 5,937
Changes attributable to:
Revisions 121 59 61 37 17 19 21 335 (28) (23) (7) 277
Improved recovery 5 - - 1 - 4 - 10 - - - 10
Extensions and discoveries 359 31 1 - - - - 391 - - - 391
Purchases 31 - - - - - - 31 - - - 31
Sales (26) - (5) - - - - (31) - - - (31)
Production (189) (29) (122) (90) (14) (19) (19) (482) (98) (9) (9) (598)
Reserves at December 31, 20184
1,874 341 678 579 156 146 545 4,319 1,504 127 67 6,017
Changes attributable to:
Revisions (153) (25) 42 19 25 6 14 (72) 75 (126) 105 (18)
Improved recovery 7 - - - - - - 7 - - - 7
Extensions and discoveries 394 39 1 1 1 2 - 438 - - - 438
Purchases 19 2 - - - - - 21 - - - 21
Sales - (4) - - - (69) - (73) - - - (73)
Production (213) (33) (108) (86) (16) (16) (19) (491) (106) (1) (13) (611)
Reserves at December 31, 20194
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, 20204
1,750 260 554 403 141 61 597 3,766 1,550 - 3 5,319
1Ending reserve balances in North America were 166, 230 and 269 and in South America were 94, 90 and 72 in 2020, 2019 and 2018, respectively.
2Reserves associated with Canada.
3Ending reserve balances in Africa were 3, 3 and 3 and in South America were 0, 156 and 64 in 2020, 2019 and 2018, respectively.
4Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to page E-7 for the definition of a PSC). PSC-related reserve quantities are 9 percent, 11 percent and 14 percent for consolidated companies for 2020, 2019 and 2018, respectively.
Noteworthy changes in natural gas liquids proved reserves for 2018 through 2020 are discussed below and shown in the table on the following page:
Revisions In 2018, improved field performance in the Midland and Delaware basins were primarily responsible for the 34 million barrel increase in the United States.
In 2019, portfolio optimizations and low price realizations in various fields in the Midland and Delaware basins and planned divestments in the Appalachian basin were mainly responsible for the 120 million barrel decrease in the United States.
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.
Extensions and Discoveries In 2018, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 173 million barrel increase in the United States.
In 2019, extensions and discoveries in the Midland and Delaware basins and deepwater fields in the Gulf of Mexico were primarily responsible for the 140 million barrel increase in the United States.
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.
Purchases In 2020, the acquisition of Noble assets contributed 198 million barrels primarily in the Denver Julesburg basin, Midland and Delaware basins and Eagle Ford Shale in the United States.
Supplemental Information on Oil and Gas Producing Activities - Unaudited
Net Proved Reserves of Natural Gas Liquids
Consolidated Companies Affiliated Companies Total
Consolidated
Other Australia/ and Affiliated
Millions of barrels U.S. Americas1
Africa Asia Oceania Europe Total TCO Other2
Companies
Reserves at January 1, 2018 343 17 96 - 6 3 465 119 21 605
Changes attributable to:
Revisions 34 1 7 - - 1 43 (11) (3) 29
Improved recovery - - - - - - - - - -
Extensions and discoveries 173 5 - - - - 178 - - 178
Purchases 19 - - - - - 19 - - 19
Sales (6) - - - - - (6) - - (6)
Production (35) (1) (5) - (1) (1) (43) (7) (2) (52)
Reserves at December 31, 20183
528 22 98 - 5 3 656 101 16 773
Changes attributable to:
Revisions (120) (4) 6 - - - (118) 10 2 (106)
Improved recovery - - - - - - - - - -
Extensions and discoveries 140 - - - - - 140 - - 140
Purchases 5 - - - - - 5 - - 5
Sales - - - - - (2) (2) - - (2)
Production (51) (2) (4) - (1) (1) (59) (8) (3) (70)
Reserves at December 31, 20193
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
1Reserves associated with North America.
2Reserves associated with Africa.
3Year-end reserve quantities related to production-sharing contracts (PSC) (refer to page E-7 for the definition of a PSC) are not material for 2020, 2019 and 2018, respectively.
Noteworthy changes in natural gas proved reserves for 2018 through 2020 are discussed below and shown in the table above:
Revisions In 2018, reservoir performance, well test and surveillance data at Wheatstone and the greater Gorgon area were responsible for the 1.0 TCF increase in Australia. The Bibiyana Field in Bangladesh and the Pattani Field in Thailand were primarily responsible for the 347 BCF increase in Asia. Improved performance in the Midland and Delaware basins were primarily responsible for the 258 BCF increase in the United States.
In 2019, strong performances at Wheatstone and the greater Gorgon areas were mainly responsible for 1.7 TCF increase in Australia. In the TCO affiliate in Kazakhstan, reservoir management and entitlement effects were mainly responsible for 223 BCF increase. Portfolio optimizations and low price realizations in various fields of the Midland and Delaware basins and planned divestments in the Appalachian basin were mainly responsible for the 2.6 TCF decrease in the United States.
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.
Extensions and Discoveries In 2018, extensions and discoveries of 1.6 TCF in the United States were primarily in the Appalachian region and the Midland and Delaware basins.
In 2019, extensions and discoveries of 1.0 TCF in the United States were primarily in the Midland and Delaware basins.
In 2020, extensions and discoveries of 385 BCF in the United States were primarily in the Midland and Delaware basins.
Supplemental Information on Oil and Gas Producing Activities - Unaudited
Purchases In 2020, the acquisition of Noble assets contributed 5.4 TCF in Israel in Asia, 1.5 TCF in the Denver Julesburg basin, Midland and Delaware basins and Eagle Ford Shale in the United States and 441 BCF in Equatorial Guinea in Africa.
Sales In 2019, sales of 240 BCF in Europe were in the United Kingdom and Denmark.
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.
Net Proved Reserves of Natural Gas
Consolidated Companies Affiliated Companies Total
Consolidated
Other Australia/ and Affiliated
Billions of cubic feet (BCF) U.S. Americas1
Africa Asia Oceania Europe Total TCO Other2
Companies
Reserves at January 1, 2018 5,180 795 2,906 4,773 13,559 301 27,514 2,183 1,039 30,736
Changes attributable to:
Revisions 258 (3) 25 347 1,012 68 1,707 (108) (38) 1,561
Improved recovery 2 2 - - 1 - 5 - - 5
Extensions and discoveries 1,627 138 - 5 - 1 1,771 - 3 1,774
Purchases 144 - 1 - - - 145 - - 145
Sales (125) - (5) - - - (130) - - (130)
Production3
(377) (69) (112) (815) (841) (65) (2,279) (141) (95) (2,515)
Reserves at December 31, 20184
6,709 863 2,815 4,310 13,731 305 28,733 1,934 909 31,576
Changes attributable to:
Revisions (2,565) (107) 46 165 1,732 3 (726) 223 39 (464)
Improved recovery - - - - - - - - - -
Extensions and discoveries 1,008 49 - 5 93 1 1,156 - 20 1,176
Purchases 24 - - - - - 24 - - 24
Sales (1) (2) - - - (240) (243) - - (243)
Production3
(447) (67) (103) (799) (898) (43) (2,357) (153) (102) (2,612)
Reserves at December 31, 20194
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, 20204
4,250 329 2,837 8,183 11,385 22 27,006 2,018 898 29,922
1Ending reserve balances in North America and South America were 234, 462, 582 and 95, 274, 281 in 2020, 2019 and 2018, respectively.
2Ending reserve balances in Africa and South America were 898, 802, 799 and 0, 64, 110 in 2020, 2019 and 2018, respectively.
3Total “as sold” volumes are 2,447, 2,379 and 2,289 for 2020, 2019 and 2018, respectively.
4Includes reserve quantities related to production-sharing contracts (PSC) (refer to page E-7 for the definition of a PSC). PSC-related reserve quantities are 10 percent, 10 percent and 10 percent for consolidated companies for 2020, 2019 and 2018, respectively.
Supplemental Information on Oil and Gas Producing Activities - Unaudited
Table VI - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves
The standardized measure of discounted future net cash flows is calculated in accordance with SEC and FASB requirements. This includes using the average of first-day-of-the-month oil and gas prices for the 12-month period prior to the end of the reporting period, estimated future development and production costs assuming the continuation of existing economic conditions, estimated costs for asset retirement obligations (includes costs to retire existing wells and facilities in addition to those future wells and facilities necessary to produce proved undeveloped reserves), and estimated future income taxes based on appropriate statutory tax rates. Discounted future net cash flows are calculated using 10 percent mid-period discount factors. Estimates of proved-reserve quantities are imprecise and change over time as new information becomes available. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. The valuation requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and do not represent management’s estimate of the company’s future cash flows or value of its oil and gas reserves. In the following table, the caption “Standardized Measure Net Cash Flows” refers to the standardized measure of discounted future net cash flows.
Consolidated Companies Affiliated Companies Total
Consolidated
Other Australia/ and Affiliated
Millions of dollars U.S. Americas Africa Asia Oceania Europe Total TCO Other Companies
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
At December 31, 2019
Future cash inflows from production $ 122,012 $ 45,701 $ 45,706 $ 43,386 $ 95,845 $ 4,466 $ 357,116 $ 85,179 $ 12,309 $ 454,604
Future production costs (32,349) (18,324) (17,982) (14,646) (14,141) (1,428) (98,870) (22,302) (2,487) (123,659)
Future development costs (15,987) (4,219) (3,643) (5,070) (5,458) (341) (34,718) (14,340) (705) (49,763)
Future income taxes (15,780) (6,491) (17,562) (11,147) (22,874) (1,078) (74,932) (14,561) (3,855) (93,348)
Undiscounted future net cash flows 57,896 16,667 6,519 12,523 53,372 1,619 148,596 33,976 5,262 187,834
10 percent midyear annual discount for timing of estimated cash flows
(26,422) (9,312) (1,629) (3,652) (26,536) (650) (68,201) (16,990) (2,096) (87,287)
Standardized Measure
Net Cash Flows
$ 31,474 $ 7,355 $ 4,890 $ 8,871 $ 26,836 $ 969 $ 80,395 $ 16,986 $ 3,166 $ 100,547
At December 31, 2018
Future cash inflows from production $ 132,512 $ 52,470 $ 56,856 $ 54,012 $ 109,116 $ 11,959 $ 416,925 $ 100,518 $ 16,928 $ 534,371
Future production costs (34,679) (20,691) (18,850) (17,359) (16,296) (6,609) (114,484) (24,580) (4,665) (143,729)
Future development costs (17,322) (5,106) (4,112) (5,494) (7,757) (1,393) (41,184) (14,069) (1,692) (56,945)
Future income taxes (17,369) (7,553) (23,593) (14,514) (25,519) (1,676) (90,224) (18,561) (4,496) (113,281)
Undiscounted future net cash flows 63,142 19,120 10,301 16,645 59,544 2,281 171,033 43,308 6,075 220,416
10 percent midyear annual discount for timing of estimated cash flows
(29,103) (11,136) (2,646) (4,822) (28,276) (419) (76,402) (22,025) (2,662) (101,089)
Standardized Measure
Net Cash Flows
$ 34,039 $ 7,984 $ 7,655 $ 11,823 $ 31,268 $ 1,862 $ 94,631 $ 21,283 $ 3,413 $ 119,327
Supplemental Information on Oil and Gas Producing Activities - Unaudited
Table VII - Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves
The changes in present values between years, which can be significant, reflect changes in estimated proved-reserve quantities and prices and assumptions used in forecasting production volumes and costs. Changes in the timing of production are included with “Revisions of previous quantity estimates.”
Total Consolidated and
Millions of dollars Consolidated Companies Affiliated Companies Affiliated Companies
Present Value at January 1, 2018 $ 65,847 $ 14,166 $ 80,013
Sales and transfers of oil and gas produced net of production costs (33,535) (6,813) (40,348)
Development costs incurred 9,723 5,044 14,767
Purchases of reserves 99 - 99
Sales of reserves (622) - (622)
Extensions, discoveries and improved recovery less related costs 5,503 14 5,517
Revisions of previous quantity estimates 15,480 (2,255) 13,225
Net changes in prices, development and production costs 39,241 17,251 56,492
Accretion of discount 9,413 2,084 11,497
Net change in income tax (16,518) (4,795) (21,313)
Net Change for 2018 28,784 10,530 39,314
Present Value at December 31, 2018 $ 94,631 $ 24,696 $ 119,327
Sales and transfers of oil and gas produced net of production costs (29,436) (5,823) (35,259)
Development costs incurred 10,497 5,120 15,617
Purchases of reserves 406 - 406
Sales of reserves (579) - (579)
Extensions, discoveries and improved recovery less related costs 5,697 43 5,740
Revisions of previous quantity estimates 621 2,122 2,743
Net changes in prices, development and production costs (25,056) (11,637) (36,693)
Accretion of discount 13,538 3,584 17,122
Net change in income tax 10,077 2,046 12,123
Net Change for 2019 (14,235) (4,545) (18,780)
Present Value at December 31, 2019 $ 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
PART IV

Item 15. Exhibits and Financial Statement Schedules
Item 15. Exhibits 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, 2020
Consolidated Statement of Comprehensive Income for the three years ended December 31, 2020
Consolidated Balance Sheet at December 31, 2020 and 2019
Consolidated Statement of Cash Flows for the three years ended December 31, 2020
Consolidated Statement of Equity for the three years ended December 31, 2020
Notes to the Consolidated Financial Statements
64 to 97
(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, 2020.
(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 2020 2019 2018
Employee Termination Benefits
Balance at January 1 $ 7 $ 19 $ 62
Additions (reductions) charged to expense 859 6 5
Payments (396) (18) (48)
Balance at December 31 $ 470 $ 7 $ 19
Expected Credit Losses
Beginning allowance balance for expected credit losses $ 849 $ 980 $ 606
Current period provision 573 (128) 379
Write-offs charged against the allowance, if any (751) (3) (5)
Recoveries of amounts previously written-off, if any - - -
Balance at December 31 $ 671 $ 849 $ 980
Deferred Income Tax Valuation Allowance1
Balance at January 1 $ 15,965 $ 15,973 $ 16,574
Additions to deferred income tax expense2
2,892 1,336 2,000
Reduction of deferred income tax expense (1,095) (1,344) (2,601)
Balance at December 31 $ 17,762 $ 15,965 $ 15,973
1 See also Note 15 to the Consolidated Financial Statements, beginning on page 79.
2 Includes $974 of additions associated with the purchase of Noble.
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 on September 30, 2020 filed as Exhibit 3.1 to Chevron Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, 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.
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 Options 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 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.
21.1*
Subsidiaries of Chevron Corporation (page E-1).
22.1 Subsidiary Issuer of Guaranteed Securities, filed as Exhibit 22.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, and incorporated herein by reference.
23.1*
Consent of PricewaterhouseCoopers LLP (page E-2).
23.2*
Consent of PricewaterhouseCoopers LLP for Tengizchevroil.
23.3* Consent of Independent Petroleum Engineers and Geologists - Netherland, Sewell & Associates, Inc.
24.1*
Power of Attorney for certain directors of Chevron Corporation, authorizing the signing of the Annual Report on Form 10-K on their behalf.
31.1*
Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Executive Officer (page E-3).
31.2*
Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Financial Officer (page E-4).
32.1**
Rule 13a-14(b)/15d-14(b) Certification by the company’s Chief Executive Officer (page E-5).
32.2**
Rule 13a-14(b)/15d-14(b) Certification by the company’s Chief Financial Officer (page E-6).
99.1*
Definitions of Selected Energy and Financial Terms (pages E-7 through E-8).
99.2*
Tengizchevroil LLP Consolidated Financial Statements for the fiscal year ended December 31, 2020.
99.3* Report of Netherland, Sewell & Associates, Inc.
101.SCH*
iXBRL Schema Document.
101.CAL*
iXBRL Calculation Linkbase Document.
101.DEF*
iXBRL Definition Linkbase Document.
101.LAB*
iXBRL Label Linkbase Document.
101.PRE*
iXBRL Presentation Linkbase Document.
104*
Cover Page Interactive Data File (contained in Exhibit 101)
Attached as Exhibit 101 to this report are documents formatted in iXBRL (Inline Extensible Business Reporting Language). The financial information contained in the iXBRL-related documents is “unaudited” or “unreviewed.”
______________________________
+ 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 25th day of February, 2021.
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 25th day of February, 2021.
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 IV*
Charles W. Moorman IV
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