What changed in this filing

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Item 9A. Controls and Procedures

2022-02-24 compared with 2021-02-25 · 628 added, 755 removed, 2716 unchanged (34% of the section changed)

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Based on the results of this evaluation, the company’s management concluded that internal control over financial reporting was effective as of December 31, 2021.

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, 2021, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein.

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Other Information

Rule 10b5-1 Plan Elections

Wirth, Chairman of the Board, entered into a pre-arranged stock trading plan in November 2021.

Wirth’s plan provides for the potential exercise of vested stock options and the associated sale of up to 93,000 shares of Chevron common stock between February 2022 and March 2023.

Breber, Vice President and Chief Financial Officer, entered into a pre-arranged stock trading plan in November 2021.

Breber’s plan provides for the potential exercise of vested stock options and the associated sale of up to 18,500 shares of Chevron common stock between February 2022 and January 2023.

Morris, Vice President and Chief Human Resources Officer, and her spouse each entered into pre-arranged stock trading plans in November 2021.

The plans for Ms.

Morris and her spouse provide for the potential exercise of vested stock options and the associated sale of up to 17,300 and 11,300 shares of Chevron common stock, respectively, between February 2022 and January 2023.

Parfitt, Vice President, Midstream, entered into a pre-arranged stock trading plan in November 2021.

Parfitt’s plan provides for the potential exercise of vested stock options and the associated sale of up to 55,500 shares of Chevron common stock between February 2022 and January 2023.

Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

Directors, Executive Officers and Corporate Governance

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Vice President, Midstream and Development (Jan 2016 - Jan 2018)

Executive Vice President, Downstream (Mar 2006 - Dec 2015) Chairman of the Board and

Chairman of the Board and

Chief Executive Officer

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;

Information Technology and Digital;

Asset Performance;

Health, Safety and Environment;

Real Estate Services

Geagea 62 Executive Vice President and Senior Advisor to Chairman and CEO

(since Aug 2021)

Executive Vice President, Technology, Projects and Services

(Jun 2015 - Aug 2021) Advisor to the Chairman and CEO

Johnson 62 Executive Vice President, Upstream (since Jun 2015)

Senior Vice President, Upstream (Jan 2014 - Jun 2015) Worldwide Exploration and Production Activities

Worldwide Exploration and Production Activities

Nelson 58 Executive Vice President, Downstream (since Mar 2019)

Vice President, Midstream, Strategy and Policy (Feb 2018 - Feb

Vice President, Strategic Planning (Apr 2016 - Jan 2018)

President, International Products (Jun 2010 - Mar 2016) Worldwide Manufacturing, Marketing and Lubricants;

Vice President, Strategic Planning (Apr 2016 - Jan 2018) Worldwide Manufacturing, Marketing and Lubricants;

Bonner 47 Vice President (since Aug 2021), Chief Technology Officer and

President of Chevron Technical Center (since Feb 2021)

General Director of Tengizchevroil (Dec 2018 - Jan 2021)

General Manager of Operations of Tengizchevroil (Nov 2015 - Nov

Information Technology;

Global Reserves;

Asset Performance and Process Safety;

Facilities Designs and Solutions;

Capital Projects;

Health, Safety and Environment;

Downstream Technology

Breber 57 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

Executive Vice President, Downstream (Jan 2016 - Mar 2019) Finance

Morris 56 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;

Vice President, Human Resources (Oct 2016 - Jan 2019) Human Resources;

Diversity and Inclusion

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Liquidity and Capital Resources

Financ ial Ratios and Metrics

Off-Balance-Sheet Arrangements, Contractual Obligations, Guarantees and Other Contingencies

Financial Ratios and Metrics

Financial and Derivative Instrument Market Risk

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Reports of Management

Report of Independent Registered Public Accounting Firm

Report of Independent Registered Public Accounting Firm (PCAOB ID:

Consolidated Statement of Income

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Summarized Financial Data – Chevron U.S.A.

Summarized Financial Data - Tengizchevroil LLP

Summarized Financial Data - Chevron Phillips

Chemical Company LLC

Fair Value Measurements

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Assets Held for Sale

Earnings Per Shar e

Earnings Per Sha re

Operating Segments and Geographic Data

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Other Financial Information

Summarized Financial Data - Chevron Phillips

Chemical Company LLC

Restructuring and Reorganization Costs

Financial Instruments - Credit Losses

Acquisition of Noble Energy, Inc.

Five-Year Financial Summary

Supplemental Information on Oil and Gas Producing Activities

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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.

Chevron Corporation is a global energy company with substantial business activities in the following countries:

Angola, Argentina, Australia, Bangladesh, Brazil, Canada, China, Egypt, Equatorial Guinea, Israel, Kazakhstan, Kurdistan Region of Iraq, 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.

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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

Periods of sustained lower commodity prices could result in the impairment or write-off of specific assets in future periods and cause the company to adjust operating expenses, including employee reductions, and capital and exploratory expenditures, along with other measures intended to improve financial performance.

Governments, companies, communities, and other stakeholders are increasingly supporting efforts to address climate change, recognizing that individuals and society benefit from access to affordable, reliable, and ever-cleaner energy.

International initiatives and national, regional and state legislation and regulations that aim to directly or indirectly reduce GHG emissions are in various stages of adoption and implementation.

These policies, some of which support the global net zero emissions ambitions of the Paris Agreement, can change the amount of energy consumed, the rate of energy-demand growth, the energy mix, and the relative economics of one fuel versus another.

Implementation of these policies can be dependent on, and can affect the pace of, technological advancements, the granting of necessary permits by governing authorities, the availability of cost-effective, verifiable carbon credits, the availability of suppliers that can meet sustainability and other standards, evolving regulatory requirements affecting ESG standards or other disclosures, and evolving standards for tracking and reporting on emissions and emission reductions and removals.

Beyond the legislative and regulatory landscape, ever changing customer and consumer behavior can also influence energy demand by affecting preferences and use of the company’s products or competitors’ products, now and in the future.

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.

Chevron supports the Paris Agreement’s global approach to governments addressing climate change and is committed to taking actions to help lower the carbon intensity of its operations while continuing to meet the need for energy that supports society.

Chevron integrates climate change-related issues and the regulatory and other responses to these issues into its strategy and planning, capital investment reviews, and risk management tools and processes, where it believes they are applicable.

They are also factored into the company’s long-range supply, demand, and energy price forecasts.

These forecasts reflect estimates of long-range effects from climate change-related policy actions, such as renewable fuel penetration and energy efficiency standards, 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 capture and storage, is difficult to predict with certainty and is expected to vary depending on the actual laws and regulations enacted or customer and consumer preference in a jurisdiction, the company’s activities in it, and market conditions.

As discussed in more detail below, the company has announced planned capital spend of $10 billion through 2028 in lower carbon investments.

Although the future is uncertain, many published outlooks conclude that fossil fuels will remain a significant part of an energy system that increasingly incorporates lower carbon sources of supply.

The company will continue to develop oil and gas resources to meet customers’ demand for energy.

At the same time, Chevron believes that the future of energy is lower carbon.

The company will continue to maintain flexibility in its portfolio to be responsive to changes in policy, technology, and customer preferences.

Chevron aims to grow its traditional oil and gas business, lower the carbon intensity of its operations and grow lower carbon businesses in renewable fuels, hydrogen, carbon capture and offsets.

To grow its lower carbon businesses, Chevron plans to target sectors of the economy where emissions are harder to abate or that cannot be easily electrified, while leveraging the company’s capabilities, assets and customer relationships.

The company’s traditional oil and gas business may increase or decrease depending upon regulatory or market forces, among other factors.

In 2021, Chevron announced the following aspiration and targets that are aligned with its lower carbon strategy:

2050 Net Zero Upstream Aspiration Chevron aspires to achieve net zero for Upstream production Scope 1 and 2 GHG Emissions on an equity basis by 2050.

The company believes accomplishing this aspiration depends on, among other things, partnerships with multiple stakeholders, continuing progress on commercially viable technology, government policy, successful negotiations for carbon capture and storage and nature-based projects, availability of cost-effective, verifiable offsets in the global market, and granting of necessary permits by governing authorities.

2028 Upstream Production GHG Intensity Targets These metrics include Scope 1, direct emissions, and Scope 2, indirect emissions from imported electricity and steam, and are net of emissions from exported electricity and steam.

The targeted 2028 reductions from 2016 on an equity ownership basis include a:

• 40 percent reduction in oil production GHG intensity to 24 kilograms (kg) carbon dioxide equivalent per barrel of oil-equivalent (CO 2 e/boe),

• 26 percent reduction in gas production GHG intensity to 24 kg CO 2 e/boe,

• 53 percent reduction in methane intensity to 2 kg CO 2 e/boe, and

• 66 percent reduction in flaring GHG intensity to 3 kg CO 2 e/boe.

The company also targets no routine flaring by 2030.

We have set 2016 as our baseline to align with the year the Paris Agreement entered into force, and the company plans to update the metrics every five years in line with the Paris Agreement stocktakes.

We believe these updates will provide additional transparency on the company’s progress toward its net zero aspiration.

2028 Portfolio Carbon Intensity Target The company also introduced a portfolio carbon intensity (PCI) metric, which is a measure of the carbon intensity across the full value chain of Chevron’s entire business.

This metric encompasses the company’s Upstream and Downstream business and includes Scope 1 (direct emissions), Scope 2 (indirect emissions from imported electricity and steam), and certain Scope 3 (primarily emissions from use of sold products) emissions.

The company’s PCI target is 71 grams (g) carbon dioxide equivalent (CO e) per megajoules (MJ) by 2028, a greater than five percent reduction from 2016.

Planned Lower-Carbon Capital Spend through 2028 The company increased its planned capital spend to approximately $10 billion through 2028 to advance its lower carbon strategy, which includes approximately $2 billion to lower the carbon intensity of its traditional oil and gas operations, and approximately $8 billion for lower carbon investments in renewable fuels, hydrogen and carbon capture and offsets.

We anticipate setting additional capital spending targets as the company

Management's Discussion and Analysis of Financial Condition and Results of Operations

progresses toward its 2050 Upstream production Scope 1 and 2 net zero aspiration and further grows its lower carbon business lines.

Refer to “Risk Factors” in Part I, Item 1A, on pages 20 through 25 for further discussion of greenhouse gas regulation and climate change and the associated risks to Chevron’s business, including the risks impacting Chevron’s lower carbon strategy and its aspirations, targets and plans.

Response to Market Conditions and COVID-19 Commodity prices and demand for most of our products have largely recovered from the impacts of COVID-19 in 2020.

However, some countries face a resurgence of the virus and its variants (e.g., Delta, Omicron) that could impact demand for some of our products (e.g., jet fuel), workforce availability, timing of project start-ups and materials movement and pose a risk to our business and future financial results.

Chevron’s operations have continued with a combination of on-site and at-home work, while monitoring local vaccine and transmission rates.

In refining, the company continued to take steps to maximize diesel and motor gasoline production, given the decline in jet fuel demand.

In TCO, progress continued on FGP/WPMP.

Staffing is at targeted levels and at the end of December 2021, over 90 percent of the TCO workforce on-site was fully vaccinated.

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.

This is mainly due to 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.

Note 17 Taxes 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 20 through 25 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.

The company continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value and to acquire assets or operations complementary to its asset base to help augment the company’s financial performance and value growth.

Asset dispositions and restructurings may result in significant gains or losses in future periods.

The company’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.

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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.

Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry production and inventory levels, technology advancements, production quotas or other actions imposed by OPEC+ countries, actions of regulators, weather-related damage and disruptions, competing fuel prices, natural and human causes beyond the company’s control such as the COVID-19 pandemic, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty.

Any of these factors could also inhibit the company’s production capacity in an affected region.

The company closely monitors developments in the countries in which it operates and holds investments and seeks to manage risks in operating its facilities and businesses.

The longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts, and changes in tax and other applicable laws and regulations.

The longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts, the pace of energy transition, and changes in tax, environmental and other applicable laws and regulations.

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

severe weather or civil unrest, delays in construction, global and local supply chain distribution issues, 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 changes in market trends.

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.

Prices for goods and services in various sectors have risen over the past year.

A key factor behind this trend is the accelerated demand for goods and transportation as companies restock materials and expand working inventories as a hedge against future disruptions.

Shifts in the labor market continue to create issues for companies seeking to fill positions.

Geographic mismatches between skills required and available labor, reductions in the overall labor supply, and perceptions of working conditions have resulted in tight labor markets.

and international drilling activity continues to accelerate, continued upward market pressure is expected for oil and gas industry inputs (such as rigs and well services).

The pace of economic growth and shifting spending patterns may lead to more cross-industry competition for resources, which could impact the cost of certain non-oil and gas industry goods and services.

The chart above shows the trend in benchmark prices for Brent crude oil, West Texas Intermediate (WTI) crude oil and U.S.

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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.

Crude prices increased in 2021 driven by production curtailment by OPEC+ countries and steadily increasing demand for transportation fuels.

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.

crude oil and natural gas liquids in 2021 was $56 per barrel, up 84 percent from 2020.

The company’s average realization for international crude oil and natural gas liquids in 2021 was $65 per barrel, up 79 percent from 2020.

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 $3.85 per thousand cubic feet (MCF) during 2021, compared with $1.98 per MCF during 2020.

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.

As of mid-February 2022, the Henry Hub spot price was $3.93 per MCF.

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.

Most of the equity LNG offtake from the operated Australian LNG projects is committed under binding long-term contracts, with some sold in the Asian spot LNG market.

International natural gas realizations averaged $5.93 per MCF during 2021, compared with $4.59 per MCF during 2020.

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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.

The company’s worldwide net oil-equivalent production in 2021 was a record 3.099 million barrels per day.

About 27 percent of the company’s net oil-equivalent production in 2021 occurred in OPEC+ member countries of Angola, Equatorial Guinea, Kazakhstan, Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait and Republic of Congo.

The company estimates that its net oil-equivalent production in 2022 will be flat to down 3 percent compared to 2021, assuming a Brent crude oil price of $60 per barrel and excluding the impact of asset sales that may close in 2022.

This estimate is subject to many factors and uncertainties, including quotas or other actions that may be imposed by OPEC+;

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fluctuations in demand for crude oil and natural gas in various markets;

weather conditions that may shut in production;

weather conditions that may shut in

Management's Discussion and Analysis of Financial Condition and Results of Operations

civil unrest;

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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;

storage constraints or economic conditions that could lead to shut-in production;

or other disruptions to operations.

The outlook for future production levels is also affected by the size and number of economic investment opportunities and the time lag between initial exploration and the beginning of production.

The company has increased its investment emphasis on short-cycle projects, 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 company has increased its investment emphasis on short-cycle projects.

In January 2022, Chevron announced its intent to begin the process of exiting from its nonoperated interests in Myanmar.

At December 31, 2021, the carrying value of the company’s assets was approximately $200 million.

Net proved reserves for consolidated companies and affiliated companies totaled 11.3 billion barrels of oil-equivalent at year-end 2021, an increase of 1 percent from year-end 2020.

The reserve replacement ratio in 2021 was 112 percent.

The 5 and 10 year reserve replacement ratios were 103 percent and 100 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 Table V for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2019 and each year-end from 2019 through 2021, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2021.

Refer to the “Results of Operations” section on pages 39 and 40 for additional discussion of the company’s upstream business.

Downstream Earnings for the downstream segment are closely tied to margins on the refining, manufacturing and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil, fuel and lubricant additives, 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.

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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.

Other factors beyond the company’s control include the general level of inflation and energy costs to operate the company’s refining, marketing and petrochemical assets, and changes in tax, environmental, and other applicable laws and regulations.

The company’s most significant marketing areas are the West Coast and Gulf Coast of the United States and Asia Pacific.

Chevron operates or has significant ownership interests in refineries in each of these areas.

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

Additionally, the company has a small but growing presence in renewable fuels.

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 40 for additional discussion of the company’s downstream operations.

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Key operating developments and other events during 2021 and early 2022 included the following:

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.

Australia Completed the acquisition of Puma Energy (Australia) Holdings Pty Ltd.

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.

Angola Chevron’s affiliate, Cabinda Gulf Oil Company Limited (CABGOC), signed an agreement to extend the Block 0 concession for 20 years, through 2050.

Australia Sanctioned the Jansz-Io compression project, a part of the Gorgon development and an important source of natural gas supply to the Gorgon LNG facility.

Brazil Completed the sale of the company's 37.5 percent nonoperated interest in the Papa-Terra oil field.

Equatorial Guinea Announced the start-up and first LNG cargo from the Alen Gas Monetization Project.

Japan Announced the signing of a binding Sale and Purchase Agreement with Hokkaido Gas Co., Ltd.

for the delivery of about a half million tons of LNG over a period of five years, starting in 2022.

United States Entered FEED for the Ballymore project, which is being developed as a subsea tieback to the existing Blind Faith facility, in the deepwater Gulf of Mexico.

United States Sanctioned the Whale project in the deepwater Gulf of Mexico.

Finland Announced an agreement to acquire Neste Oyj’s Group III base oil business, including its related sales and marketing business, and brand NEXBASE TM .

South Korea Chevron’s 50 percent owned affiliate, GS Caltex, started up an olefins mixed-feed cracker and associated polyethylene unit at its Yeosu refinery ahead of schedule and under budget.

United States Announced the commissioning and start-up of the world’s first commercial-scale ISOALKY™ process unit at the Salt Lake City Refinery.

This proprietary technology uses ionic liquids to produce a high octane gasoline blending component as a cost-effective alternative to conventional alkylation technologies and offers environmental and process safety advantages.

United States Began producing renewable diesel at the El Segundo, California refinery by co-processing bio-feedstock.

United States Announced establishment of its first branded Compressed Natural Gas (CNG) station, as part of its plan to sell RNG through more than 30 CNG stations in California by 2025.

United States Acquired an equity interest in American Natural Gas LLC (now Beyond6, LLC) and its network of 60 compressed natural gas stations across the United States to grow its RNG value chain.

United States Announced the second expansion of its joint venture, Brightmark RNG Holdings LLC, to own projects across the United States to produce and market dairy biomethane, a RNG.

First gas delivery at the Lawnhurst site in New York was announced in November.

United States Announced the launch of Havoline® PRO-RS™ Renewable Full Synthetic Motor Oil made with 25 percent sustainably sourced plant-based oils.

United States Celebrated the opening of the 1,000th ExtraMile Convenience store.

United States Chevron’s 50 percent owned affiliate, CPChem, announced the first commercial sales of their Marlex® Anew™ Circular Polyethylene, which uses advanced recycling technology to process pyrolysis oil, a feedstock made from difficult-to-recycle waste plastics.

United States Announced the signing of definitive transaction agreements to create a joint venture with Bunge North America, Inc., to own and operate soybean processing facilities.

Management's Discussion and Analysis of Financial Condition and Results of Operations

United States Announced the launch of Chevron’s $300 million Future Energy Fund II focused on technologies that have the potential to enable affordable, reliable, and ever-cleaner energy for all.

United States Announced plans with partners to develop carbon negative bioenergy in Mendota, California.

United States Announced memorandums of understanding with Toyota Motors North America, Inc.

to explore a strategic alliance to catalyze and lead the development of commercially viable, large-scale businesses in hydrogen;

with Cummins Inc.

to explore a strategic alliance to develop commercially viable business opportunities in hydrogen and other alternative energy sources;

with Delta Air Lines, Inc.

and Google LLC to track sustainable aviation fuel test batch emissions data using cloud-based technology;

and with Progress Rail Locomotive Inc., a Caterpillar company, and BNSF Railway Company to demonstrate hydrogen-fueled locomotives.

United States Acquired all of the publicly held common units representing limited partner interests in Noble Midstream Partners LP not already owned by Chevron and its affiliates.

United States Announced a collaboration agreement with Caterpillar Inc.

to develop hydrogen demonstration projects in transportation and stationary power applications, including prime power.

United States Announced a letter of intent with Gevo, Inc.

to jointly invest in building and operating one or more new facilities that process inedible corn to produce sustainable aviation fuel.

United States Announced agreement on a framework to acquire an equity interest in ACES Delta, LLC that owns the Advanced Clean Energy Storage project.

This project aims to produce, store and transport green hydrogen at utility scale.

United States Announced a framework with Enterprise Product Partners L.P.

to study and evaluate opportunities for carbon dioxide capture, utilization, and storage from their respective business operations in the U.S.

Midcontinent and Gulf Coast.

United States Invested in companies to access lower-carbon technologies, including Baseload Capital AB (low-temperature geothermal and heat power), Starfire Energy (carbon-free ammonia and carbon-free hydrogen), Ocergy, Inc.

(floating offshore and wind turbine technology), Mainspring (lower-carbon generators for electric grids), Raygen (solar-hydro plant with storage), Boomitra (soil carbon offset platform), Natel Energy (hydro-power based technology), Raven SR Inc.

(modular waste-to-green hydrogen and renewable synthetic fuel facilities), Sapphire Technologies (waste energy recovery systems), Hydrogenious LOHC Technologies (liquid organic hydrogen carriers), gr3n SA (plastics recycling technology), Malta Inc.

(thermal energy storage) and Ionomr Innovations Inc.

(ion-exchange membranes and polymers).

Common Stock Dividends The 2021 annual dividend was $5.31 per share, making 2021 the 34th consecutive year that the company increased its annual per share dividend payout.

In January 2022, the company’s Board of Directors increased its quarterly dividend by $0.08 per share, approximately six percent, to $1.42 per share payable in March 2022.

Common Stock Repurchase Program The company resumed stock repurchases in third quarter 2021 and purchased $1.4 billion of its common stock in 2021 under its stock repurchase program.

The company currently expects to repurchase $1.25 billion of its common stock during the first quarter of 2022.

Results of Operations

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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 Note 14 Operating Segments and Geographic Data for a discussion of the company’s “reportable segments.” This section should also be read in conjunction with the discussion in “Business Environment and Outlook” on pages 32 through 37.

Refer to the “Selected Operating Data” table on page 42 for a three-year comparison of production volumes, refined product sales volumes, and refinery inputs.

A discussion of variances between 2020 and 2019 can be found in the “Results of Operations” section on pages 37 through 38 of the company’s 2020 Annual Report on Form 10-K filed with the SEC on February 25, 2021.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Millions of dollars 2021 2020 2019

Earnings (Loss) $ 7,319 $ (1,608) $ (5,094)

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.

upstream reported earnings of $7.3 billion in 2021, compared with a loss of $1.6 billion in 2020.

The increase was due to higher realizations of $6.9 billion, the absence of 2020 impairments and write-offs of $1.2 billion, higher sales volumes of $760 million, and higher asset sales gains of $640 million.

The company’s average realization for U.S.

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Net oil-equivalent production in 2021 averaged 1.14 million barrels per day, up 8 percent from 2020.

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 increase was due to an additional 162,000 barrels per day of production from the Noble Energy acquisition, partially offset by a 63,000 barrels per day decrease related to the Appalachian asset sale.

The net liquids component of oil-equivalent production for 2021 averaged 858,000 barrels per day, up 9 percent from 2020.

Net natural gas production averaged 1.61 billion cubic feet per day in 2020, up 31 percent from 2019.

Net natural gas production averaged 1.69 billion cubic feet per day in 2021, an increase of 5 percent from 2020.

International Upstream

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$ 302 $ (285) $ (323)

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.

International upstream reported earnings of $8.5 billion in 2021, compared with a loss of $825 million in 2020.

The increase was primarily due to higher realizations of $7.6 billion, along with the absence of 2020 impairments and write-offs of $3.6 billion and severance charges of $290 million.

Partially offsetting these increases are higher tax charges of $630 million, the absence of 2020 asset sales gains of $550 million, and higher depreciation expenses of $670 million and lower sales volumes of $540 million.

Foreign currency effects had a favorable impact on earnings of $587 million between periods.

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International net oil-equivalent production was 1.96 million barrels per day in 2021, down 3 percent from 2020.

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.

The decrease was primarily due to the absence of 69,000 barrels per day following expiration of the Rokan concession in

Management's Discussion and Analysis of Financial Condition and Results of Operations

Indonesia, unfavorable entitlement effects, normal field declines and the effect of asset sales, partially offset by 113,000 barrels per day associated with the Noble Energy acquisition and lower production curtailments.

The net liquids component of international oil-equivalent production was 956,000 barrels per day in 2021, a decrease of 11 percent from 2020.

International net natural gas production of 6.02 billion cubic feet per day in 2021 increased 6 percent from 2020.

Millions of dollars 2021 2020 2019

Earnings (Loss) $ 2,389 $ (571) $ 1,559

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.

downstream reported earnings of $2.4 billion in 2021, compared with a loss of $571 million in 2020.

The increase was primarily due to higher margins on refined product sales of $1.6 billion, higher earnings from 50 percent-owned CPChem of $1.0 billion and higher sales volumes of $470 million, partially offset by higher operating expenses of $150 million.

Total refined product sales of 1.14 million barrels per day in 2021 increased 14 percent from 2020, mainly due to higher gasoline, jet fuel, and diesel demand as travel restrictions associated with the COVID-19 pandemic continue to ease.

International Downstream

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International downstream earned $525 million in 2021, compared with $618 million in 2020.

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.

The decrease in earnings was largely due to lower margins on refined product sales of $330 million and higher operating expenses of $100 million, partially offset by a favorable swing in foreign currency effects of $337 million between periods.

Total refined product sales of 1.32 million barrels per day in 2021 were up 8 percent from 2020, mainly due to the second quarter 2020 acquisition of Puma Energy (Australia) Holdings Pty Ltd.

and higher diesel and gasoline demand, partially offset by lower jet fuel demand.

Millions of dollars 2021 2020 2019

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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

Net charges in 2021 decreased $50 million from 2020.

The change between periods was mainly due to the absence of 2020 severance, Noble acquisition and mining remediation costs, and lower corporate charges, partially offset by higher employee benefit costs and a loss on early retirement of debt.

Foreign currency effects decreased net charges by $27 million between periods.

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.

A discussion of variances between 2020 and 2019 can be found in the “Consolidated Statement of Income” section on pages 39 and 40 of the company’s 2020 Annual Report on Form 10-K.

Millions of dollars 2021 2020 2019

Sales and other operating revenues $ 155,606 $ 94,471 $ 139,865

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.

Sales and other operating revenues increased in 2021 mainly due to higher refined product, crude oil, and natural gas prices and sales volumes .

Management's Discussion and Analysis of Financial Condition and Results of Operations

Millions of dollars 2021 2020 2019

Income (loss) from equity affiliates $ 5,657 $ (472) $ 3,968

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.

Income from equity affiliates improved in 2021 mainly due to the absence of the full impairment of Petropiar and Petroboscan in Venezuela in 2020, higher upstream-related earnings from Tengizchevroil in Kazakhstan and Angola LNG, and higher downstream-related earnings from CPChem and GS Caltex in Korea.

Refer to Note 15 Investments and Advances for a discussion of Chevron’s investments in affiliated companies.

Millions of dollars 2021 2020 2019

Other income $ 1,202 $ 693 $ 2,683

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.

Other income increased in 2021 mainly due to a favorable swing in foreign currency effects and higher gains on asset sales, partially offset by losses on the early retirement of debt.

Millions of dollars 2021 2020 2019

Purchased crude oil and products $ 89,372 $ 50,488 $ 80,113

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.

Crude oil and product purchases increased in 2021 primarily due to higher crude oil, natural gas, and refined product prices and higher refined product volumes.

Millions of dollars 2021 2020 2019

Operating, selling, general and administrative expenses $ 24,740 $ 24,536 $ 25,528

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.

Operating, selling, general and administrative expenses increased in 2021 primarily due to higher employee benefit and transportation costs partially offset by the absence of 2020 severance accruals.

Millions of dollars 2021 2020 2019

Exploration expense $ 549 $ 1,537 $ 770

Exploration expenses in 2020 increased primarily due to higher charges for well write-offs.

Exploration expenses in 2021 decreased primarily due to lower charges for well write-offs .

Millions of dollars 2021 2020 2019

Depreciation, depletion and amortization $ 17,925 $ 19,508 $ 29,218

Depreciation, depletion and amortization expenses decreased in 2020 primarily due to lower impairments.

Depreciation, depletion and amortization expenses decreased in 2021 primarily due to lower impairment charges, partially offset by higher rates and production .

Millions of dollars 2021 2020 2019

Taxes other than on income $ 6,840 $ 4,499 $ 4,136

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.

Taxes other than on income increased in 2021 primarily due to higher regulatory expenses, taxes on production and excise taxes, which was primarily driven by higher refined product sales in Australia.

Millions of dollars 2021 2020 2019

Interest and debt expense $ 712 $ 697 $ 798

Interest and debt expenses decreased in 2020 mainly due to lower interest rates, partially offset by higher debt balances.

Interest and debt expenses increased in 2021 mainly due to interest expense associated with debt acquired in the Noble Energy acquisition.

Millions of dollars 2021 2020 2019

Other components of net periodic benefit costs $ 688 $ 880 $ 417

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

Other components of net periodic benefit costs decreased in 2021 primarily due to lower interest costs.

Millions of dollars 2021 2020 2019

Income tax expense (benefit) $ 5,950 $ (1,892) $ 2,691

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.

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.

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.

The increase in income tax expense in 2021 of $7.84 billion is due to the increase in total income before tax for the company of $29.09 billion.

The increase in income before taxes for the company is primarily the result of higher upstream realizations, the absence of 2020 impairments and write-offs, and higher downstream margins.

income before tax increased from a loss of $5.70 billion in 2020 to income of $9.67 billion in 2021.

This $15.37 billion increase in income was primarily driven by higher upstream realizations, higher downstream margins and the absence of 2020 impairments and write-offs.

The increase in income had a direct impact on the company’s U.S.

income tax resulting in an increase to tax expense of $3.18 billion between year-over-year periods, from a tax benefit of $1.58 billion in 2020 to a charge of $1.60 billion in 2021.

Management's Discussion and Analysis of Financial Condition and Results of Operations

International income before tax increased from a loss of $1.75 billion in 2020 to income of $11.97 billion in 2021.

This $13.72 billion increase in income was primarily driven by higher upstream realizations and the absence of 2020 impairments and write-offs.

The increased income primarily drove the $4.66 billion increase in international income tax expense between year-over-year periods, from a tax benefit of $308 million in 2020 to a charge of $4.35 billion in 2021.

Refer also to the discussion of the effective income tax rate in Note 17 Taxes .

Selected Operating Data 1,2

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7 Includes sales of affiliates (MBPD):

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.

Sources and Uses of Cash The strength of the company’s balance sheet enables it to fund any timing differences throughout the year between cash inflows and outflows.

Cash, Cash Equivalents and Marketable Securities Total balances were $5.7 billion and $5.6 billion at December 31, 2021 and 2020, respectively.

Cash provided by operating activities in 2021 was $29.2 billion, compared to $10.6 billion in 2020, primarily due to higher crude oil and natural gas prices.

Cash provided by operating activities was net of contributions to employee pension plans of approximately $1.8 billion in 2021 and $1.2 billion in 2020.

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Restricted cash of $1.2 billion and $1.1 billion at December 31, 2021 and 2020, 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.

These amounts are generally associated with upstream decommissioning activities, tax payments and funds held in escrow for tax-deferred exchanges.

Dividends Dividends paid to common stockholders were $10.2 billion in 2021 and $9.7 billion in 2020.

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.

(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.

Debt and Finance Lease Liabilities Total debt and finance lease liabilities were $31.4 billion at December 31, 2021, down from $44.3 billion at year-end 2020.

The $12.9 billion decrease in total debt and finance lease liabilities during 2021 was primarily due to the repayment of long-term notes that matured during the year, the early retirement of long-term notes and the credit facility held by Noble Midstream Partners LP, and the elimination of borrowings under the company’s commercial paper program.

The company completed a tender offer, with the objective of lowering future interest expenses, and redeemed bonds with a book value (including fair market price adjustments) of $3.4 billion in October 2021.

The company’s debt and finance lease liabilities due within one year, consisting primarily of the current portion of long-term debt and redeemable long-term obligations, totaled $8.0 billion at December 31, 2021, compared with $11.4 billion at year-end 2020.

Of these amounts, $7.8 billion and $9.8 billion were reclassified to long-term debt at the end of 2021 and 2020, respectively.

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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.

The company has outstanding public bonds issued by Chevron Corporation,

Management's Discussion and Analysis of Financial Condition and Results of Operations

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.

4 unchanged sentences

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.

During extended periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, the company has the ability to modify its capital spending plans and discontinue or curtail the stock repurchase program.

This provides the flexibility to continue paying the common stock dividend and remain committed to retaining the company’s high-quality debt ratings.

Committed Credit Facilities Information related to committed credit facilities is included in Note 19 Short-Term Debt .

Summarized Financial Information for Guarantee of Securities of Subsidiaries CUSA issued bonds that are fully and unconditionally guaranteed on an unsecured basis by Chevron Corporation (together, the “Obligor Group”).

The tables below contain summary financial information for Chevron Corporation, as Guarantor, excluding its consolidated subsidiaries, and CUSA, as the issuer, excluding its consolidated subsidiaries.

The summary financial information of the Obligor Group is presented on a combined basis, and transactions between the combined entities have been eliminated.

Financial information for non-guarantor entities has been excluded.

December 31, 2020 Year Ended

December 31, 2019

Year Ended December 31, 2021 Year Ended December 31, 2020

(Millions of dollars) (unaudited)

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Total net equity (deficit) $ (58,902) $ (47,313)

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.

Common Stock Repurchase Program The Board of Directors authorized a stock repurchase program in 2019, with a maximum dollar limit of $25 billion and no set term limits.

During 2021, the company purchased 12.9 million shares for $1.4 billion under the program.

As of December 31, 2021, the company had purchased a total of 61.5 million shares for $6.8 billion, resulting in $18.2 billion remaining under the program.

The company currently expects to repurchase $1.25 billion of its common stock during the first quarter of 2022.

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 timing of the repurchases and the actual amount repurchased will depend on a variety of factors, including the market price of the company’s shares, general market and economic conditions, and other factors.

The stock repurchase program does not obligate the company to acquire any particular amount of common stock, and it may be suspended or discontinued at any time.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Capital and Exploratory Expenditures

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Total reported expenditures for 2021 were $11.7 billion, including $3.2 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 2020, expenditures were $13.5 billion, including the company’s share of affiliates’ expenditures of $4.0 billion.

The acquisition of Noble is not included in the company’s capital and exploratory expenditures.

Of the $11.7 billion of expenditures in 2021, 82 percent, or $9.6 billion, related to upstream activities.

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International upstream accounted for 51 percent of the worldwide upstream investment in 2021 and 53 percent in 2020.

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.

The company estimates that 2022 organic capital and exploratory expenditures will be approximately $15 billion, including $3.6 billion of spending by affiliates, an increase of over 25 percent from 2021 expenditures.

This includes approximately $800 million in lower carbon spending that aims to reduce the carbon intensity of the company’s operations and grow its lower carbon businesses.

In the upstream business, approximately $8 billion is allocated to currently producing assets, including about $3 billion for Permian Basin unconventional development and approximately $1.5 billion for other shale and tight assets worldwide.

Additionally, $3 billion of the upstream program is planned for major capital projects underway, of which about $2 billion is associated with the FGP/WPMP at the Tengiz field in Kazakhstan.

Finally, approximately $1.5 billion is allocated to exploration, early-stage development projects, midstream activities and carbon reduction opportunities.

Worldwide downstream spending in 2022 is estimated to be $2.3 billion, including capital targeted to grow renewable fuels and products businesses.

Investments in technology businesses and other corporate operations in 2022 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.”

The company monitors crude oil market conditions and can adjust future capital outlays should oil price conditions deteriorate.

Noncontrolling Interests The company had noncontrolling interests of $873 million at December 31, 2021 and $1.0 billion at December 31, 2020.

Distributions to noncontrolling interests net of contributions totaled $36 million and $24 million in 2021 and 2020, respectively.

Included within noncontrolling interests at December 31, 2021 is $135 million of redeemable noncontrolling interest.

Pension Obligations Information related to pension plan contributions is included in Note 23 Employee Benefit Plans , under the heading “Cash Contributions and Benefit Payments.”

Contractual Obligations Information related to the company’s significant contractual obligations is included in Note 19 Short-Term Debt , in Note 20 Long-Term Debt and in Note 5 Lease Commitments .

The aggregate amount of interest due on these obligations, excluding leases, is:

after 2026 – $3,143.

Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements Information related to these off-balance sheet matters is included in Note 24 Other Contingencies and Commitments , under the heading “Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements.”

Direct Guarantees Information related to guarantees is included in Note 24 Other Contingencies and Commitments under the heading “Guarantees.”

Indemnifications Information related to indemnifications is included in Note 24 Other Contingencies and Commitments under the heading “Indemnifications.”

Management's Discussion and Analysis of Financial Condition and Results of Operations

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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.

The company’s interest coverage ratio in 2021 was higher than 2020 due to higher income.

Year ended December 31

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Debt Ratio Total debt as a percentage of total debt plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage.

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

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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.

Net Debt Ratio Total debt less cash and cash equivalents and marketable securities as a percentage of total debt less cash and cash equivalents and marketable securities, plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage, net of its cash balances.

At December 31

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Cash and cash equivalents 5,640 5,596 5,686

Time deposits — — 950

Marketable securities 35 31 63

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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.

Average stockholders’ equity is computed by averaging the sum of stockholders’ equity at the beginning and end of the year.

ROSE is a ratio intended to measure earnings as a percentage of shareholder investments.

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Return on Average Stockholders’ Equity 11.5 % (4.0) % 2.0 %

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 Total 1

2021 2022-2023 2024-2025 After 2025

On Balance Sheet:

Short-Term Debt 3, 4

$ 1,362 $ 1,362 $ — $ — $ —

Long-Term Debt 3, 4

40,732 — 21,848 5,650 13,234

5,119 1,580 1,394 702 1,443

9,357 866 1,469 1,105 5,917

Off Balance Sheet:

Throughput and Take-or-Pay Agreements 5

13,186 817 2,045 2,236 8,088

Other Unconditional Purchase Obligations 5

1,464 211 468 489 296

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

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.

$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.

Excludes finance lease liabilities.

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

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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.

Management's Discussion and Analysis of Financial Condition and Results of Operations

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.

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The change in fair value of Chevron’s derivative commodity instruments in 2021 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.

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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.

Refer to “Other Information” in Note 15 Investments and Advances for further discussion.

Management believes these agreements have been negotiated on terms consistent with those that would have been negotiated with an unrelated party.

Litigation and Other Contingencies

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.

Ecuador Information related to Ecuador matters is included in Note 16 Litigation under the heading “Ecuador.”

Climate Change Information related to climate change-related matters is included in Note 16 Litigation under the heading “Climate Change.”

Louisiana Information related to Louisiana coastal matters is included in Note 16 Litigation under the heading “Louisiana.”

Environmental The following table displays the annual changes to the company’s before-tax environmental remediation reserves, including those for U.S.

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Balance at December 31 $ 960 $ 1,139 $ 1,234

Management's Discussion and Analysis of Financial Condition and Results of Operations

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.

The liability balance of approximately $12.8 billion for asset retirement obligations at year-end 2021 is related primarily to upstream properties.

For the company’s other ongoing operating assets, such as refineries and chemicals facilities, no provisions are made for exit or cleanup costs that may be required when such assets reach the end of their useful lives unless a decision to sell or otherwise decommission the facility has been made, as the indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the asset retirement obligation.

Refer to the discussion below for additional information on environmental matters and their impact on Chevron, and on the company’s 2021 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.”

Refer to Note 24 Other Contingencies and Commitments under the heading “Environmental” for additional discussion of environmental remediation provisions and year-end reserves.

Refer also to Note 25 Asset Retirement Obligations for additional discussion of the company’s asset retirement obligations.

Suspended Wells Information related to suspended wells is included in Note 21 Accounting for Suspended Exploratory Wells .

Income Taxes Information related to income tax contingencies is included in Note 17 Taxes and in Note 24 Other Contingencies and Commitments under the heading “Income Taxes.”

Other Contingencies Information related to other contingencies is included in Note 24 Other Contingencies and Commitments under the heading “Other Contingencies.”

Environmental Matters

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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.

In addition, legislation and regulations intended to address hydraulic fracturing also continue to evolve in many jurisdictions where we operate.

Refer to “Risk Factors” in Part I, Item 1A, on pages 20 through 25 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.

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Using definitions and guidelines established by the American Petroleum Institute, Chevron estimated its worldwide environmental spending in 2021 at approximately $1.9 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.

Included in these expenditures were approximately $0.3 billion of environmental capital expenditures and $1.6 billion of costs associated

Management's Discussion and Analysis of Financial Condition and Results of Operations

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 2022, total worldwide environmental capital expenditures are estimated at $0.5 billion.

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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

The discussion in this section of “critical” accounting estimates and assumptions is according to the disclosure guidelines of the SEC, wherein:

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;

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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.

Variables impacting Chevron’s estimated volumes of crude oil and natural gas reserves include field performance, available technology, commodity prices, and development, production and carbon costs.

The estimates of crude oil 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.

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During 2021, Chevron’s UOP Depreciation, Depletion and Amortization (DD&A) for oil and gas properties was $13.7 billion, and proved developed reserves at the beginning of 2021 were 6.9 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.

If the estimates of proved reserves used in the UOP calculations for consolidated operations had been lower by five percent across all oil and gas properties, UOP DD&A in 2021 would have increased by approximately $700 million.

Impairment - Oil and gas reserves are used in assessing oil and gas producing properties for impairment.

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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.

Refer to Table V , “Reserve Quantity Information,”, for the changes in proved reserve estimates for the three years ended December 31, 2021, and to Table VII , “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” for estimates of proved reserve values for each of the three years ended December 31, 2021.

Management's Discussion and Analysis of Financial Condition and Results of Operations

This Oil and Gas Reserves commentary should be read in conjunction with the Properties, Plant and Equipment section of Note 1 Summary of Significant Accounting Policies , which includes a description of the “successful efforts” method of accounting for oil and gas exploration and production activities.

Impairment of Properties, Plant and Equipment and Investments in Affiliates The company assesses its properties, plant and equipment (PP&E) for possible impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable.

If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of 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.

If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of the carrying value of the asset over its estimated fair value.

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters, such as future commodity prices, operating expenses, carbon costs, production profiles, the pace of the energy transition, and the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas, 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

Refer also to the discussion of impairments of properties, plant and equipment in Note 18 Properties, Plant and Equipment and to the section on Properties, Plant and Equipment in Note 1 Summary of Significant Accounting Policies .

The company performs impairment assessments when triggering events arise to determine whether any write-down in the carrying value of an asset or asset group is required.

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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.

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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;

Refer to Note 25 Asset Retirement Obligations for additional discussions on asset retirement obligations.

Pension and Other Postretirement Benefit Plans Note 23 Employee Benefit Plans includes information on the funded status of the company’s pension and other postretirement benefit (OPEB) plans reflected on the Consolidated Balance Sheet;

the components of pension and OPEB expense reflected on the Consolidated Statement of Income;

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The determination of pension plan expense and obligations is based on a number of actuarial assumptions.

Two critical assumptions are the expected long-term rate of return on plan assets and the discount rate applied to pension plan obligations.

Two critical assumptions are the expected long-term rate of return on plan assets and the discount rate applied to pension plan

Management's Discussion and Analysis of Financial Condition and Results of Operations

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.

Information related to the company’s processes to develop these assumptions is included in Note 23 Employee Benefit Plans under the relevant headings.

Actual rates may vary significantly from estimates because of unanticipated changes beyond the company’s control.

Management's Discussion and Analysis of Financial Condition and Results of Operations

For 2021, the company used an expected long-term rate of return of 6.5 percent and a discount rate for service costs of 3.0 percent and a discount rate for interest cost of 1.9 percent for the primary U.S.

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For the 10 years ended December 31, 2021, actual asset returns averaged 9.8 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.

Additionally, with the exception of two 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 2021 was $1.2 billion.

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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.

pension plan, which accounted for about 60 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $425 million, and would have decreased the plan’s underfunded status from approximately $1.2 billion to $800 million.

For the company’s OPEB plans, expense for 2021 was $85 million, and the total liability, all unfunded at the end of 2021, was $2.5 billion.

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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 N ote 29 beginning on page 96 .

Refer to page 88 in Note 23 Employee Benefit Plans for more information on the $5.1 billion of before-tax actuarial losses recorded by the company as of December 31, 2021.

In addition, information related to company contributions is included on page 91 in Note 23 Employee Benefit Plans under the heading “Cash Contributions and Benefit Payments.”

Contingent Losses Management also makes judgments and estimates in recording liabilities for claims, litigation, tax matters and environmental remediation.

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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.

For additional discussion of income tax uncertainties, refer to Note 24 Other Contingencies and Commitments under the heading Income Taxes .

Refer also to the business segment discussions elsewhere in this section for the effect on earnings from losses associated with certain litigation, environmental remediation and tax matters for the three years ended December 31, 2021.

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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.

impact on the company’s consolidated financial statements and financial or operational performance in any given period” in “Risk Factors” in Part I, Item 1A, on pages 24 and 25.

New Accounting Standards

Refer to Note 4 beginning on page 69 for information regarding new accounting standards.

Refer to Note 4 New Accounting Standards for information regarding new accounting standards.

Quarterly Results

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Based on the results of this evaluation, the company’s management concluded that internal control over financial reporting was effective as of December 31, 2021.

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.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Chevron Corporation:

To the Board of Directors and Stockholders of Chevron Corporation

Opinions on the Financial Statements and Internal Control over Financial Reporting

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We believe that our audits provide a reasonable basis for our opinions.

As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded Noble Energy, Inc.

from its assessment of internal control over financial reporting as of December 31, 2020 because it was acquired by the Company in a purchase business combination during 2020.

We have also excluded Noble Energy, Inc.

from our audit of internal control over financial reporting.

Noble Energy, Inc.

is a wholly-owned subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent eight percent and one percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2020.

Definition and Limitations of Internal Control over Financial Reporting

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(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company;

and (iii) provide reasonable assurance regarding prevention or timely

detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

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Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments.

The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments.

The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The Impact of Proved Crude Oil and Natural Gas Reserves on Upstream Property, Plant, and Equipment, Net

As described in Notes 1 and 16 to the consolidated financial statements, the Company’s upstream property, plant and equipment, net balance was $140.2 billion as of December 31, 2020, and depreciation, depletion and amortization expense was $18.0 billion, including impairments of $2.8 billion for the year ended December 31, 2020.

As described in Notes 1 and 18 to the consolidated financial statements, the Company’s upstream property, plant and equipment, net balance was $130.8 billion as of December 31, 2021, and depreciation, depletion and amortization expense was $16.5 billion for the year ended December 31, 2021.

The Company follows the successful efforts method of accounting for crude oil and natural gas exploration and production activities.

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Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of-production method by individual field as the related proved reserves are produced.

As disclosed by management, variables impacting the Company’s estimated volumes of crude oil and natural gas reserves include field performance, available technology, commodity prices, and development and production costs.

Reserves are estimated by Company asset teams composed of earth scientists and engineers.

As part of the internal control process related to reserves estimation, the Company maintains a Reserves Advisory Committee (RAC) (the Company’s earth scientists, engineers and RAC are collectively referred to as “management’s specialists”).

The principal considerations for our determination that performing procedures relating to the impact of proved crude oil and natural gas reserves on upstream property, plant, and equipment, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved crude oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained related to the data, methods and assumptions used by management and its specialists in developing the estimates of crude oil and natural gas reserve volumes.

The principal considerations for our determination that performing procedures relating to the impact of proved crude oil and natural gas reserves on upstream property, plant, and equipment, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved crude oil and natural gas reserve volumes, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained related to the data, methods and assumptions used by management and its specialists in developing the estimates of proved crude oil and natural gas reserve volumes.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements.

These procedures included testing the effectiveness of controls relating to management’s estimates of proved crude oil and natural gas reserves.

These procedures included testing the effectiveness of controls relating to management’s estimates of proved crude oil and natural gas reserve volumes.

The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved crude oil and natural gas reserve volumes.

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The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ findings.

Acquisition of Noble Energy, Inc.

- Valuation of Crude Oil and Natural Gas Properties

As described in Note 29 to the consolidated financial statements, the Company acquired Noble Energy, Inc.

(“Noble”) in an acquisition accounted for as a business combination, which required assets acquired and liabilities assumed to be measured at their acquisition date fair values, including approximately $15 billion related to the fair values of acquired oil and gas properties.

Management applied significant judgment in estimating the fair value of properties acquired, which involved use of a discounted cash flow approach that incorporated internally generated price assumptions and production profiles, and operating cost and development cost assumptions.

The principal considerations for our determination that performing procedures relating to the valuation of crude oil and natural gas properties from the acquisition of Noble is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists as defined in the previous Critical Audit Matter, when developing the fair value measurement of acquired crude oil and natural gas properties;

(ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating significant assumptions used in the discounted cash flow approach related to price, production profiles and discount rates;

and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements.

These procedures included testing the effectiveness of controls relating to the valuation of acquired crude oil and natural gas properties.

These procedures also included, among others, (i) testing management’s process for developing the fair value measurement of the acquired crude oil and natural gas properties;

(ii) evaluating the appropriateness of the discounted cash flow approach;

(iii) testing the completeness and accuracy of underlying data used in the discounted cash flow approach;

and (iv) evaluating the reasonableness of significant assumptions used by management related to price, production profiles and discount rates.

Evaluating production profile assumptions involved evaluating the reasonableness of the assumptions as compared to historical results of Noble, as well as third party data.

Evaluating price assumptions involved comparing the prices to third party data and underlying contracts.

Professionals with specialized skill and knowledge were used to assist in the evaluation of the discounted cash flow approach and discount rates used.

The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved crude oil and natural gas reserve volumes included in production profile assumptions as stated in the Critical Audit Matter titled “The Impact of Proved Crude Oil and Natural Gas Reserves on Upstream Property, Plant, and Equipment, Net”.

As a basis for using this work, the specialists’ qualifications were understood, and the Company’s relationship with the specialists was assessed.

The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of the specialists’ findings.

PricewaterhouseCoopers LLP

San Francisco, California

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Net derivatives loss on hedge transactions ( 6 ) — ( 1 )

Reclassification to net income 6 — —

Income taxes on derivatives transactions — — 3

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Total Current Assets 33,738 26,078

Long-term receivables, net 589 1,511

Long-term receivables, net (less allowances:

2021 - $ 442 ;

2020 - $ 387 )

Investments and advances 40,696 39,052

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Total Chevron Corporation Stockholders’ Equity 139,067 131,688

Noncontrolling interests (2020 includes $ 120 redeemable noncontrolling interest)

Noncontrolling interests (includes redeemable noncontrolling interest of $ 135 and $ 120 at December 31, 2021 and 2020)

Total Equity 139,940 132,726

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1 Includes finance lease liabilities of $ 449 and $ 447 at December 31, 2021 and 2020, respectively.

2 Refer to Note 22 , “Other Contingencies and Commitments” beginning on page 92.

2 Refer to Note 24 Other Contingencies and Commitments .

See accompanying Notes to the Consolidated Financial Statements.

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Cash dividends - common stock ( 10,179 ) ( 9,651 ) ( 8,959 )

Distributions to noncontrolling interests ( 24 ) ( 18 ) ( 91 )

Net contributions from (distributions to) noncontrolling interests ( 36 ) ( 24 ) ( 18 )

Net sales (purchases) of treasury shares 38 ( 1,531 ) ( 2,935 )

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Net income (loss) — 2,924 — — 2,924 ( 79 ) 2,845

Cash dividends — ( 8,502 ) — — ( 8,502 ) ( 91 ) ( 8,593 )

Cash dividends ($ 4.76 per share)

— ( 8,959 ) — — ( 8,959 ) ( 18 ) ( 8,977 )

Stock dividends — ( 3 ) — — ( 3 ) — ( 3 )

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Treasury stock transactions 84 — — — 84 — 84

Noble Acquisition 2

( 520 ) — — 4,629 4,109 779 4,888

Net income (loss) — ( 5,543 ) — — ( 5,543 ) ( 18 ) ( 5,561 )

Cash dividends — ( 8,959 ) — — ( 8,959 ) ( 18 ) ( 8,977 )

Cash dividends ($ 5.16 per share)

— ( 9,651 ) — — ( 9,651 ) ( 24 ) ( 9,675 )

Stock dividends — ( 5 ) — — ( 5 ) — ( 5 )

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Treasury stock transactions 315 — — — 315 — 315

Noble Acquisition 3

( 520 ) — — 4,629 4,109 779 4,888

NBLX Acquisition 138 ( 148 ) — 377 367 ( 321 ) 46

Net income (loss) — 15,625 — — 15,625 64 15,689

Cash dividends — ( 9,651 ) — — ( 9,651 ) ( 24 ) ( 9,675 )

Cash dividends ($ 5.31 per share)

— ( 10,179 ) — — ( 10,179 ) ( 53 ) ( 10,232 )

Stock dividends — ( 3 ) — — ( 3 ) — ( 3 )

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Changes reflect capital in excess of par.

2 Beginning and ending total issued share balances include 14,168,000 shares associated with Chevron’s Benefit Plan Trust.

2 Includes $ 120 redeemable noncontrolling interest.

3 Beginning and ending total issued share balances include 14,168,000 shares associated with Chevron’s Benefit Plan Trust.

See accompanying Notes to the Consolidated Financial Statements.

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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 some of this derivative activity, the company may elect to apply fair value or cash flow hedge accounting with changes in fair value recorded as components of accumulated other comprehensive income (loss).

For other similar derivative instruments, generally because of the short-term nature of the contracts or their limited use, the company does not apply hedge accounting, and changes in the fair value of those contracts are reflected in current income.

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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.

Refer to Note 21 Accounting for Suspended Exploratory Wells for additional discussion of accounting for suspended exploratory well costs.

Long-lived assets to be held and used, including proved crude oil and natural gas properties, are assessed for possible impairment by comparing their carrying values with their associated undiscounted, future net cash flows.

Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset (including changes to the commodity price forecast), 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.

Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset (including changes to the commodity price forecast or carbon costs), significant change in the extent or manner of use of or a physical change in an asset, and a more-likely-than-not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life.

Impaired assets are written down to their estimated fair values, generally their discounted, future net cash flows.

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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.

Refer to Note 9 Fair Value Measurements relating to fair value measurements.

The fair value of a liability for an ARO is recorded as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated.

Refer also to Note 23 , on page 94, relating to AROs.

Refer also to Note 25 Asset Retirement Obligations relating to AROs.

Depreciation and depletion of all capitalized costs of proved crude oil and natural gas producing properties, except mineral interests, are expensed using the unit-of-production method, generally by individual field, as the proved developed reserves are produced.

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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.

Refer to Note 25 Asset Retirement Obligations for a discussion of the company’s AROs.

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.

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( 18 ) 2 2 ( 1,432 ) ( 1,446 )

Stranded Tax Reclassification to Retained Earnings 3

— — — ( 562 ) ( 562 )

Balance at December 31, 2019 $ ( 142 ) $ ( 8 ) $ — $ ( 4,840 ) $ ( 4,990 )

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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.

2 Refer to Note 10 Financial and Derivative Instruments for cash flow hedging.

3 Refer to Note 23 Employee Benefit Plans , for reclassified components, including amortization of actuarial gains or losses, amortization of prior service costs and settlement losses, totaling $ 1,055 that are included in employee benefit costs for the year ended December 31, 2021.

Related income taxes for the same period, totaling $ 225 , 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

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Net sales (purchases) of treasury shares $ 38 $ ( 1,531 ) $ ( 2,935 )

Net contributions from (distributions to) noncontrolling interests consisted of the following gross and net amounts:

Distributions to noncontrolling interests $ ( 53 ) $ ( 26 ) $ ( 18 )

Contributions from noncontrolling interests 17 2 —

Net contributions from (distributions to) noncontrolling interests $ ( 36 ) $ ( 24 ) $ ( 18 )

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.

“Distributions more (less) than income from equity affiliates,” “Depreciation, depletion and amortization,” “Deferred income tax provision,” and “Dry hole expense,” collectively include approximately $ 4.8 billion in non-cash reductions to properties, plant and equipment in 2020 relating to impairments and other non-cash charges.

The company did not have any material impairments in 2021.

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.

Refer also to Note 25 Asset Retirement Obligations for a discussion of revisions to the company’s AROs that also did not involve cash receipts or payments for the three years ending December 31, 2021.

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.

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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.

There are not currently any new or pending accounting standards that have a significant impact on Chevron.

Lease Commitments

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Right-of-use assets* $ 3,668 $ 429 $ 3,949 $ 455

$ 3,949 $ 455 $ 4,074 $ 329

Accrued Liabilities $ 995 $ — $ 1,291 $ —

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Year-ended December 31

Operating lease costs 1, 2

2021 2020 2019

Operating lease costs* $ 2,199 $ 2,551 $ 2,621

Finance lease costs 66 45 66

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$ 2,265 $ 2,596 $ 2,687

1 Net rental expense of $ 816 for 2018.

* Includes variable and short-term lease costs.

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Year-ended December 31

2021 2020 2019

Operating cash flows from operating leases $ 1,670 $ 1,744 $ 1,574

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Total debt $ 11,693 $ 7,133

Summarized Financial Data – Tengizchevroil LLP

Chevron has a 50 percent equity ownership interest in Tengizchevroil LLP (TCO).

Refer to Note 15 Investments and Advances for a discussion of TCO operations.

Summarized financial information for 100 percent of TCO is presented in the table below:

Year ended December 31

2021 2020 2019

Sales and other operating revenues $ 15,927 $ 9,194 $ 16,281

Costs and other deductions 8,186 6,076 7,903

Net income attributable to TCO 5,418 2,196 5,884

At December 31

Current assets $ 3,307 $ 2,114

Other assets 51,473 48,390

Current liabilities 3,436 1,686

Other liabilities 12,060 12,553

Total TCO net equity $ 39,284 $ 36,265

Summarized Financial Data – Chevron Phillips Chemical Company LLC

Chevron has a 50 percent equity ownership interest in Chevron Phillips Chemical Company LLC (CPChem).

Refer to Note 15 Investments and Advances for a discussion of CPChem operations.

Summarized financial information for 100 percent of CPChem is presented in the table below:

Year ended December 31

2021 2020 2019

Sales and other operating revenues $ 14,104 $ 8,407 $ 9,333

Costs and other deductions 10,862 7,221 7,863

Net income attributable to CPChem 3,684 1,260 1,760

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

At December 31

Current assets $ 3,381 $ 2,816

Other assets 14,396 14,210

Current liabilities 1,854 1,394

Other liabilities 3,160 3,380

Total CPChem net equity $ 12,763 $ 12,252

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.

The tables below show the fair value hierarchy for assets and liabilities measured at fair value on a recurring and nonrecurring basis at December 31, 2021 and December 31, 2020.

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, 2021.

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 The company records most of its derivative instruments – other than any commodity derivative contracts that are accounted for as normal purchase and normal sale – on the Consolidated Balance Sheet at fair value, with the offsetting amount to the Consolidated Statement of Income.

The company designates certain derivative instruments as cash flow hedges that, if applicable, are reflected in the table below.

Derivatives classified as Level 1 include futures, swaps and options contracts traded in active markets such as the New York Mercantile Exchange.

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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.

Properties, Plant and Equipment The company did not have any individually material impairments in 2021.

The company reported impairments for certain upstream properties in 2020 primarily due to downward revisions to its oil and gas price outlook.

Investments and Advances In 2021, the company did not have any material impairments of investments and advances measured at fair value on a nonrecurring basis.

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

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Marketable securities $ 35 $ 35 $ — $ — $ 31 $ 31 $ — $ —

Derivatives 74 37 37 — 11 1 10 —

Derivatives - not designated 313 285 28 — 74 37 37 —

Total assets at fair value $ 348 $ 320 $ 28 $ — $ 105 $ 68 $ 37 $ —

Derivatives 173 58 115 — 74 26 48 —

Derivatives - not designated 72 24 48 — 173 58 115 —

Total liabilities at fair value $ 72 $ 24 $ 48 $ — $ 173 $ 58 $ 115 $ —

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Total nonrecurring assets at fair value $ 140 $ — $ — $ 140 $ 446 $ 3,889 $ — $ 1,438 $ 2,451 $ 5,347

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

At year-end 2021, the company had assets measured at fair value Level 3 using unobservable inputs of $ 140 .

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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.

Assets and Liabilities Not Required to Be Measured at Fair Value The company holds cash equivalents in U.S.

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 $ 5,640 and $ 5,596 at December 31, 2021, and December 31, 2020, 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.

The fair values of cash and cash equivalents are classified as Level 1 and reflect the cash that would have been received if the instruments were settled at December 31, 2021.

“Cash and cash equivalents” do not include investments with a carrying/fair value of $ 1,155 and $ 1,141 at December 31, 2021, and December 31, 2020, 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.

At December 31, 2021, these investments are classified as Level 1 and include restricted funds related to certain upstream decommissioning activities, tax payments and a financing program.

Long-term debt, excluding finance lease liabilities, of $ 22,164 and $ 30,805 at December 31, 2021, and December 31, 2020, respectively, had estimated fair values of $ 23,670 and $ 34,390 , respectively.

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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.

Derivative Commodity Instruments The company’s derivative commodity instruments principally include crude oil, natural gas, liquefied natural gas and refined product futures, swaps, options, and forward contracts.

The company applies cash flow hedge accounting to certain commodity transactions, where appropriate, to manage the market price risk associated with forecasted sales of crude oil.

The company’s derivatives are not material to the company’s financial position, results of operations or liquidity.

The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodity derivative activities.

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.

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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:

Derivative instruments measured at fair value at December 31, 2021, 2020 and 2019, and their classification on the Consolidated Balance Sheet below and Consolidated Statement of Income on the following page:

Consolidated Balance Sheet:

Fair Value of Derivatives Not Designated as Hedging Instruments

Fair Value of Derivatives

At December 31

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Total liabilities at fair value $ 72 $ 173

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Consolidated Statement of Income:

The Effect of Derivatives Not Designated as Hedging Instruments

The Effect of Derivatives

Type of Derivative Statement of Year ended December 31

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Commodity Sales and other operating revenues $ ( 685 ) $ 69 $ ( 291 )

$ 69 $ ( 291 ) $ 135

Commodity Purchased crude oil and products

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$ ( 795 ) $ 40 $ ( 310 )

All designated cash flow hedges during the year were settled by December 31, 2021.

The impact on sales and other operating revenues from designated hedges in 2021 was immaterial.

The table below represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated Balance Sheet at December 31, 2021 and December 31, 2020.

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At December 31, 2021

Derivative Assets $ 818 $ 744 $ 74 $ — $ 74

Derivative Liabilities $ 917 $ 744 $ 173 $ — $ 173

Derivative Assets - not designated $ 1,684 $ 1,371 $ 313 $ — $ 313

Derivative Liabilities - not designated $ 1,443 $ 1,371 $ 72 $ — $ 72

At December 31, 2020

Derivative Assets $ 656 $ 645 $ 11 $ — $ 11

Derivative Liabilities $ 719 $ 645 $ 74 $ — $ 74

Derivative Assets - not designated $ 818 $ 744 $ 74 $ — $ 74

Derivative Liabilities - not designated $ 917 $ 744 $ 173 $ — $ 173

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.

Concentrations of Credit Risk The company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, marketable securities, derivative financial instruments and trade receivables.

The company’s short-term investments are placed with a wide array of financial institutions with high credit ratings.

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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

For a discussion of credit risk on trade receivables, see Note 28 Financial Instruments - Credit Losses .

Assets Held for Sale

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In addition, 614,768 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.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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).

Diluted EPS includes the effects of these items as well as the dilutive effects of outstanding stock options awarded under the company’s stock option programs (refer to Note 22 Stock Options and Other Share-Based Compensation ).

The table below sets forth the computation of basic and diluted EPS:

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marketing of crude oil, refined products, and lubricants;

manufacturing and marketing of renewable fuels;

transporting of crude oil and refined products by pipeline, marine vessel, motor equipment and rail car;

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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).

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Non-billable costs remain at the corporate level in “All Other.” Earnings by major operating area are presented in the following table:

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Year ended December 31

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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.

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“All Other” activities include revenues from insurance operations, real estate activities and technology companies.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Year ended December 31 1

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Total Income Tax Expense (Benefit) $ 5,950 $ ( 1,892 ) $ 2,691

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.

Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 15 Investments and Advances .

Information related to properties, plant and equipment by segment is contained in Note 18 Properties, Plant and Equipment .

Notes to the Consolidated Financial Statements

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Angola LNG Limited 2,180 2,258 336 ( 166 ) ( 26 )

Noble Midstream equity affiliates 895 — ( 9 ) — —

Other* 1,859 1,875 187 137 ( 478 )

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Total International $ 32,156 $ 31,074 $ 3,768 $ ( 1,181 ) $ 3,327

* Upstream Other line includes amounts previously reported as Noble Midstream equity affiliates.

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:

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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 .

Included in the investment is a loan to TCO to fund the development of the FGP/WPMP with a balance of $ 4,500 .

Petropiar Chevron has a 30 percent interest in Petropiar, a joint stock company which operates the heavy oil Huyapari Field and upgrading project in Venezuela’s Orinoco Belt.

In 2020, the company fully impaired its investments in the Petropiar affiliate and, effective July 1, 2020, began accounting for this venture as a non-equity method investment.

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.

The company also has an outstanding long-term loan to Petroboscan of $ 560 , which has been fully provisioned for at year-end 2021.

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.

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The joint venture imports, refines and markets petroleum products, petrochemicals and lubricants.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $ 10,796 , $ 6,038 and $ 8,006 with affiliated companies for 2021, 2020 and 2019, respectively.

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Total affiliates’ net equity $ 80,612 $ 76,805 $ 80,343 $ 40,153 $ 39,639 $ 38,851

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.

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.

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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.

The Lago Agrio plaintiffs sought to 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.

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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.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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 continues to believe that the Ecuadorian judgment is illegitimate and unenforceable and will vigorously defend against any further attempts to have it recognized or enforced.

Climate Change

Governmental and other entities in various jurisdictions across the United States have filed legal proceedings against fossil fuel producing companies, including Chevron entities, purporting to seek legal and equitable relief to address alleged impacts of climate change.

Chevron entities are or were among the codefendants in 21 separate lawsuits brought by 17 U.S.

cities and counties, two U.S.

states, the District of Columbia and a trade group.

One of the city lawsuits was dismissed on the merits, and one of the county lawsuits was voluntarily dismissed by the plaintiff.

The lawsuits assert various causes of action, including public nuisance, private nuisance, failure to warn, design defect, product defect, trespass, negligence, impairment of public trust, and violations of consumer protection statutes, based upon the company’s production of oil and gas products and alleged misrepresentations or omissions relating to climate change risks associated with those products.

The unprecedented legal theories set forth in these proceedings entail the possibility of damages liability (both compensatory and punitive), injunctive and other forms of equitable relief, including without limitation abatement and disgorgement of profits, civil penalties and liability for fees and costs of suits, that, while we believe remote, could have a material adverse effect on the company’s results of operations and financial condition.

Further such proceedings are likely to be filed by other parties.

Management believes that these proceedings are legally and factually meritless and detract from constructive efforts to address the important policy issues presented by climate change, and will vigorously defend against such proceedings.

Seven coastal parishes and the State of Louisiana have filed lawsuits in Louisiana against numerous oil and gas companies seeking damages for coastal erosion in or near oil fields located within Louisiana’s coastal zone under Louisiana’s State and Local Coastal Resources Management Act (SLCRMA).

Chevron entities are defendants in 39 of these cases.

The lawsuits allege that the defendants’ historical operations were conducted without necessary permits or failed to comply with permits obtained and seek damages and other relief, including the costs of restoring coastal wetlands allegedly impacted by oil field operations.

Plaintiffs’ SLCRMA theories are unprecedented;

thus, there remains significant uncertainty about the scope of the claims and alleged damages and any potential effects on the company’s results of operations and financial condition.

Management believes that the claims lack legal and factual merit and will continue to vigorously defend against such proceedings.

Year ended December 31

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statutory federal income tax rate and the company’s effective income tax rate is detailed in the following table:

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

2021 2020 2019

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Effect of income taxes from international operations 2,692 ( 39 ) 2,196

( 39 ) 2,196 3,132

State and local taxes on income, net of U.S.

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Prior year tax adjustments, claims and settlements 1

362 ( 236 ) 192

Tax credits ( 173 ) ( 33 ) ( 18 )

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Effective income tax rate 27.5 % 25.4 % 48.6 %

* 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

1 Includes one-time tax costs (benefits) associated with changes in uncertain tax positions.

2 Includes one-time tax costs (benefits) associated with changes in valuation allowances (2021 - $( 624 );

2019 - $ 0 ).

The 2021 increase in income tax expense of $ 7,842 is a result of the year-over-year increase in total income before income tax expense, which is primarily due to higher upstream realizations, the absence of 2020 impairment and write-offs and higher downstream margins.

The company’s effective tax rate changed from 25.4 percent in 2020 to 27.5 percent in 2021.

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 change in effective tax rate is mainly due to mix effects resulting from the absolute level of earnings or losses and whether they arose in higher or lower tax rate jurisdictions.

The company records its deferred taxes on a tax-jurisdiction basis.

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Deferred tax liabilities decreased by $ 946 from year-end 2020.

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 decrease to Investments and other was driven by a consolidated subsidiary restructuring, partially offset with an increase to Properties, plant and equipment.

Deferred tax assets decreased by $ 2,780 from year-end 2020.

This decrease was primarily related to decreases in tax loss carryforwards for various locations, and employee benefits, partially offset by the increase in foreign tax credits.

The overall valuation allowance relates to deferred tax assets for U.S.

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foreign tax credit carryforwards of $ 11,718 will expire between 2022 and 2032.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

At December 31, 2021 and 2020, deferred taxes were classified on the Consolidated Balance Sheet as follows:

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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.

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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.

United States – 2013, Nigeria – 2007, Australia – 2009, Kazakhstan – 2012 and Saudi Arabia – 2015.

The company engages in ongoing discussions with tax authorities regarding the resolution of tax matters in the various jurisdictions.

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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

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, 2021, accrual benefit of $( 76 ) for anticipated interest and penalty was included on the Consolidated Balance Sheet, compared with accrual benefit of $( 95 ) as of year-end 2020.

Income tax expense (benefit) associated with interest and penalties was $ 19 , $( 124 ) and $( 3 ) in 2021, 2020 and 2019, respectively.

Taxes Other Than on Income

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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 7 2

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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 49 39 35

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Commercial paper 1

$ 5,612 $ 4,654

Notes payable to banks and others with originating terms of one year or less

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Redeemable long-term obligations 2,959 2,960

Long-term debt 2,960 3,078

11,373 13,032

Reclassified to long-term debt ( 7,759 ) ( 9,825 )

Total short-term debt $ 256 $ 1,548

1 Weighted-average interest rates at December 31, 2020 and 2019, were 0.15 % and 1.69 %, respectively.

1 Weighted-average interest rate at December 31, 2020 was 0.15 %.

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.

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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.

Any borrowings under the facility would be unsecured indebtedness at interest rates based on the London Interbank Offered Rate (LIBOR), or Secured Overnight Financing Rate (SOFR) when LIBOR has permanently or indefinitely ceased or is no longer representative, 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, 2021.

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Notes due 2022 2.179 0.333 - 2.498

Floating rate notes due 2021 0.913 0.751 - 1.171

Debentures due 2021 8.875 40 40

Notes due 2022 2.179 0.333 - 2.498

$ 3,800 $ 3,800

Floating rate notes due 2022 0.536 0.264 - 0.705

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Debt due within one year ( 4,946 ) ( 2,600 )

Fair market valuation adjustment of Noble long-term debt 1,690 —

Fair market value adjustment for debt acquired in the Noble Energy acquisition 741 1,690

Reclassified from short-term debt 7,759 9,825

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2 Range of interest rates at December 31, 2021.

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

3 Principal amount to be repaid in installments between 2022 and 2025.

4 For details on finance lease liabilities, see Note 5 Lease Commitments .

Chevron has an automatic shelf registration statement that expires in August 2023.

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and after 2026 – $ 8,381 .

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

In addition to the $ 2.6 billion in long-term debt that matured in 2021, the company also completed a tender offer in October 2021, with the objective of lowering future interest expenses, and redeemed bonds with a face value of $ 2.6 billion and a book value of $ 3.4 billion (including the fair market valuation adjustment for debt acquired in the Noble Energy acquisition), which resulted in an after-tax loss on the extinguishment of debt of $ 260 million.

The company also repaid $ 1.1 billion of bank loans associated with the NBLX acquisition during 2021.

In February 2022, the company early-redeemed $ 1.4 billion in notes at face value that were scheduled to mature in March 2022.

See Note 9 Fair Value Measurements for information concerning the fair value of the company’s long-term debt.

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.

Accounting for Suspended Exploratory Wells

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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

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* 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.

Of the $ 2,044 of exploratory well costs capitalized for more than one year at December 31, 2021, $ 1,119 is related to nine projects that had drilling activities underway or firmly planned for the near future.

The $ 925 balance is related to six projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not underway or firmly planned for the near future.

Additional drilling was not deemed necessary because the presence of hydrocarbons had already been established, and other activities were in process to enable a future decision on project development.

The projects for the $ 925 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.

(a) $ 486 ( four projects) – undergoing front-end engineering and design with final investment decision expected within four years ;

(b) $ 439 ( two projects) – development alternatives under review.

While progress was being made on all 15 projects, the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations associated with the projects.

More than half of these decisions are expected to occur in the next five years .

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

The $ 2,044 of suspended well costs capitalized for a period greater than one year as of December 31, 2021, represents 83 exploratory wells in 15 projects.

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Total $ 2,044 15

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Stock Options and Other Share-Based Compensation

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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.

Noble Share-Based Plans (Noble Plans) When Chevron acquired Noble in October 2020, outstanding stock options granted under various Noble Plans were exchanged for Chevron options.

These awards retained the same 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.

Awards issued may be exercised for up to five years after termination of employment, depending upon the termination type, or the original expiration date, whichever is earlier.

Other awards issued under the Noble Plans included restricted stock awards, restricted stock units, and performance shares, which retained the same provisions as the original Noble Plans.

Upon termination of employment due to change-in-control, all unvested awards issued under the Noble Plans, including stock options, restricted stock awards, restricted stock units and performance shares become vested on the termination date.

If not exercised, awards will expire between 2022 and 2029.

Fair Value and Assumptions The fair market values of stock options and stock appreciation rights granted in 2021, 2020 and 2019 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

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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:

A summary of option activity during 2021 is presented below:

Shares (Thousands) Weighted-Average

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Exercisable at December 31, 2021 66,499 $ 109.80 3.45 $ 806

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2021, 2020 and 2019 was $ 152 , $ 92 and $ 516 , respectively.

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During 2021, 2,219,379 performance shares were granted, 1,378,766 shares vested with cash proceeds distributed to recipients and 252,345 shares were forfeited.

At December 31, 2020, performance shares outstanding were 4,434,797 .

At December 31, 2021, there were 5,023,065 performance shares outstanding that are payable in cash.

The fair value of the liability recorded for these instruments was $ 683 and was measured using the Monte Carlo simulation method.

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During 2021, 1,381,433 restricted stock units were granted, 111,831 units vested with cash proceeds distributed to recipients and 186,898 units were forfeited.

At December 31, 2020, restricted stock units outstanding were 3,303,933 .

At December 31, 2021, there were 4,386,637 restricted stock units outstanding that are payable in cash.

The fair value of the liability recorded for the vested portion of these instruments was $ 381 , valued at the stock price as of December 31, 2021.

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Plan participants’ contributions — 3 — 3 43 59

Plan amendments — — — 29 — —

Actuarial (gain) loss ( 325 ) ( 364 ) 1,782 550 ( 108 ) 191

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Benefits paid ( 2,560 ) ( 746 ) ( 2,045 ) ( 368 ) ( 189 ) ( 214 )

Divestitures/Acquisitions — — 36 — — —

Fair value of plan assets at December 31 9,919 4,950 9,930 5,363 — —

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Net amount recognized at December 31 $ ( 3,047 ) $ ( 401 ) $ ( 5,236 ) $ ( 944 ) $ ( 2,489 ) $ ( 2,650 )

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.

For the year ended December 31, 2021, the decrease in benefit obligations was primarily due to actuarial gains caused by higher discount rates used to value the obligations and large benefit payments paid to retirees in 2021.

For the year ended December 31, 2020, 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 $ 4,979 and $ 7,278 at the end of 2021 and 2020, respectively.

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pension plan assets, which account for 67 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.

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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.

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.

The effective discount rates derived from this analysis were 2.8 percent, 2.4 percent, and 3.1 percent for 2021, 2020, and 2019, respectively, for both the main U.S.

pension and OPEB plans.

Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2021, for the main U.S.

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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.

Awards under the LTIP consist of stock options and other share-based compensation that are described in Note 22 Stock Options and Other Share-Based Compensation .

Other Contingencies and Commitments

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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.

Refer to Note 17 Taxes for a discussion of the periods for which tax returns have been audited for the company’s major tax jurisdictions and a discussion for all tax jurisdictions of the differences between the amount of tax benefits recognized in the financial statements and the amount taken or expected to be taken in a tax return.

Settlement of open tax years, as well as other tax issues in countries where the company conducts its businesses, are not expected to have a material effect on the consolidated financial position or liquidity of the company and, in the opinion of management, adequate provisions have been made for all years under examination or subject to future examination.

Guarantees The company has 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.

Guarantees The company has one guarantee to an equity affiliate totaling $ 215 .

This guarantee is associated with certain payments under a terminal use agreement entered into by an equity affiliate.

Over the approximate 6 -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.

Chevron has recorded no liability for this 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.

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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:

The aggregate amounts of required payments under throughput and take-or-pay agreements are:

2022 – $ 1,049 ;

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2026 – $ 1,223 ;

2026 and after – $ 8,400 .

A portion of these commitments may

after 2026 – $ 7,626 .

The aggregate amount of required payments for other unconditional purchase obligations are:

2022 – $ 57 ;

2023 – $ 257 ;

2024 – $ 242 ;

2025 – $ 252 ;

2026 – $ 200 ;

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.

A portion of these commitments may ultimately be shared with project partners.

Total payments under the agreements were $ 861 in 2021, $ 514 in 2020 and $ 836 in 2019.

Such contingencies may exist for various operating, closed and divested sites, including, but not limited to, U.S.

federal Superfund sites and analogous sites under state laws, refineries, chemical plants, marketing facilities, crude oil fields, and mining sites.

Although the company has provided for known environmental obligations that are probable and reasonably estimable, it is likely that the company will continue to incur additional liabilities.

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Chevron’s environmental reserve as of December 31, 2021, was $ 960 .

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.

Included in this balance was $ 230 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 U.S.

federal Superfund law or analogous state laws which provide for joint and several liability for all responsible parties.

Any future actions by regulatory agencies to require Chevron to assume other potentially responsible parties’ costs at designated hazardous waste sites are not expected to have a material effect on the company’s results of operations, consolidated financial position or liquidity.

Of the remaining year-end 2021 environmental reserves balance of $ 730 , $ 466 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.

downstream operations, $ 50 to its international downstream operations, and $ 214 to its upstream operations.

Liabilities at all sites were primarily associated with the company’s plans and activities to remediate soil or groundwater contamination or both.

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No single remediation site at year-end 2021 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.

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.

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;

Refer to Note 25 Asset Retirement Obligations for a discussion of the company’s asset retirement obligations.

Other Contingencies Chevron receives claims from and submits claims to customers;

trading partners;

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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 amounts of these claims, individually and in the aggregate, may be significant and take lengthy periods to resolve, and may result in gains or losses in future periods.

The company and its affiliates also continue to review and analyze their operations and may close, retire, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve competitiveness and profitability.

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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.

No significant AROs associated with any legal obligations to retire downstream long-lived assets have been recognized, as indeterminate settlement dates

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

for the asset retirements prevent estimation of the fair value of the associated ARO.

The company performs periodic reviews of its downstream long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation.

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Balance at December 31 $ 12,808 $ 13,616 $ 12,832

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.

In the table above, the amount associated with “Revisions in estimated cash flows” in 2021 primarily reflects increased cost estimates and scope changes to decommission wells, equipment and facilities.

The long-term portion of the $ 12,808 balance at the end of 2021 was $ 11,611 .

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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.

Refer to Note 14 Operating Segments and Geographic Data for additional information on the company’s segmentation of revenue.

Receivables related to revenue from contracts with customers are included in “Accounts and notes receivable, net” on the Consolidated Balance Sheet, net of the allowance for doubtful accounts.

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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

Other Financial Information

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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 2020 included after-tax charges of approximately $ 4,800 for impairments and other asset write-offs related to upstream.

Earnings in 2021 included after-tax charges of approximately $ 519 for pension settlement costs, $ 260 for early retirement of debt, $ 120 relating to upstream remediation and $ 110 relating to downstream legal reserves.

Earnings in 2020 included after-tax charges of approximately $ 4,800 for impairments and other asset write-offs related to upstream.

Earnings in 2019 included after-tax charges of approximately $ 10,400 for impairments and other asset write-offs related to upstream.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Other financial information is as follows:

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The company tested this goodwill for impairment during 2021, and no impairment was required.

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

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

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

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.

Chevron’s expected credit loss allowance balance was $ 745 million as of December 31, 2021 and $ 671 million as of December 31, 2020, with a majority of the allowance relating to non-trade receivable balances.

The majority of the company’s receivable balance is concentrated in trade receivables, with a balance of $ 16.4 billion as of December 31, 2021, which reflects the company’s diversified sources of revenues and is dispersed across the company’s broad worldwide customer base.

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The company routinely assesses the financial strength of its customers.

When the financial strength of a customer is not considered sufficient, alternative risk mitigation measures may be deployed, including requiring prepayments, letters of credit or other acceptable forms of collateral.

Once credit is extended and a receivable balance exists, the company applies a quantitative calculation to current trade receivable balances that reflects credit risk predictive analysis, including probability of default and loss given default, which takes into consideration current and forward-looking market data as well as the company’s historical loss data.

This statistical approach becomes the basis of the company’s expected credit loss allowance for current trade receivables with payment terms that are typically short-term in nature, with most due in less than 90 days.

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 $ 3.4 billion as of December 31, 2021, which includes receivables from certain governments in their capacity as joint venture partners.

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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.

Loans to equity affiliates and non-equity investees are also considered non-trade and associated allowances of $ 560 million are included within “Investments and Advances” on the Consolidated Balance Sheet at both December 31, 2021 and December 30, 2020.

Acquisition of Noble Energy, Inc.

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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 .

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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.

Oil and gas properties were valued using a discounted cash flow approach that incorporated internally generated price assumptions and production profiles together

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

with appropriate operating cost and development cost assumptions.

Debt assumed in the acquisition was valued based on observable market prices for Noble’s debt.

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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

Millions of dollars, except per-share amounts 2020 2019 2018 2017 2016

Statement of Income Data

Revenues and Other Income

Total sales and other operating revenues *

$ 94,471 $ 139,865 $ 158,902 $ 134,674 $ 110,215

Income from equity affiliates and other income 221 6,651 7,437 7,048 4,257

Total Revenues and Other Income 94,692 146,516 166,339 141,722 114,472

Total Costs and Other Deductions 102,145 140,980 145,764 132,501 116,632

Income (Loss) Before Income Tax Expense (7,453) 5,536 20,575 9,221 (2,160)

Income Tax Expense (Benefit) (1,892) 2,691 5,715 (48) (1,729)

Net Income (Loss) (5,561) 2,845 14,860 9,269 (431)

Net income (loss) attributable to noncontrolling interests (18) (79) 36 74 66

Net Income (Loss) Attributable to Chevron Corporation $ (5,543) $ 2,924 $ 14,824 $ 9,195 $ (497)

Per Share of Common Stock

Net Income (Loss) Attributable to Chevron

– Basic $ (2.96) $ 1.55 $ 7.81 $ 4.88 $ (0.27)

– Diluted $ (2.96) $ 1.54 $ 7.74 $ 4.85 $ (0.27)

Cash Dividends Per Share $ 5.16 $ 4.76 $ 4.48 $ 4.32 $ 4.29

Balance Sheet Data (at December 31)

Current assets $ 26,078 $ 28,329 $ 34,021 $ 28,560 $ 29,619

Noncurrent assets 213,712 209,099 219,842 225,246 230,459

Total Assets 239,790 237,428 253,863 253,806 260,078

Short-term debt 1,548 3,282 5,726 5,192 10,840

Other current liabilities 20,635 23,248 21,445 22,545 20,945

Long-term debt 42,767 23,691 28,733 33,571 35,286

Other noncurrent liabilities 42,114 41,999 42,317 43,179 46,285

Total Liabilities 107,064 92,220 98,221 104,487 113,356

Total Chevron Corporation Stockholders’ Equity $ 131,688 $ 144,213 $ 154,554 $ 148,124 $ 145,556

Noncontrolling interests 1,038 995 1,088 1,195 1,166

Total Equity $ 132,726 $ 145,208 $ 155,642 $ 149,319 $ 146,722

* Includes excise, value-added and similar taxes:

$ — $ — $ — $ 7,189 $ 6,905

Supplemental Information on Oil and Gas Producing Activities - Unaudited

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and results of operations.

Tables V through VII present information on the company’s

Tables V through VII present information on the company’s estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to

Table I - Costs Incurred in Exploration, Property Acquisitions and Development 1

Consolidated Companies Affiliated Companies

Other Australia/

Millions of dollars U.S.

Americas Africa Asia Oceania Europe Total TCO Other

Americas Africa Asia Australia Europe Total TCO Other

Year Ended December 31, 2021

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Property acquisitions 2

Proved - Noble 3,463 — 438 7,945 — — 11,846 — —

Proved - Other 98 — 15 53 — — 166 — —

Unproved - Noble 2,845 2 113 129 — — 3,089 — —

Unproved - Other 13 16 — — — — 29 — —

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Property acquisitions 2

Proved 81 34 — 93 — — 208 — —

Unproved 68 150 — 17 1 — 236 — —

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 — —

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Includes capitalized amounts related to asset retirement obligations.

See Note 23 , “Asset Retirement Obligations,” on page 94.

See Note 25 Asset Retirement Obligations .

2 Includes wells, equipment and facilities associated with proved reserves.

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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.

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.

Refer to Note 15 Investments and Advances for a discussion of the company’s major equity affiliates.

Table II - Capitalized Costs Related to Oil and Gas Producing Activities

Consolidated Companies Affiliated Companies

Other Australia/

Millions of dollars U.S.

Americas Africa Asia Oceania Europe Total TCO Other

Americas Africa Asia Australia Europe Total TCO Other

At December 31, 2021

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Consolidated Companies Affiliated Companies

Other Australia/

Millions of dollars U.S.

Americas Africa Asia Oceania Europe Total TCO Other

Americas Africa Asia Australia Europe Total TCO Other

Year Ended December 31, 2021

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2 Represents accretion of ARO liability.

Refer to Note 23 , “Asset Retirement Obligations,” on page 94.

Refer to Note 25 Asset Retirement Obligations .

3 Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses.

2 unchanged sentences

Consolidated Companies Affiliated Companies

Other Australia/

Millions of dollars U.S.

Americas Africa Asia Oceania Europe Total TCO Other

Americas Africa Asia Australia Europe Total TCO Other

Year Ended December 31, 2019

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2 Represents accretion of ARO liability.

Refer to Note 23 , “Asset Retirement Obligations,” on page 94.

Refer to Note 25 Asset Retirement Obligations .

3 Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses.

1 unchanged sentence

Consolidated Companies Affiliated Companies

Other Australia/

Americas Africa Asia Oceania Europe Total TCO Other

Americas Africa Asia Australia Europe Total TCO Other

Year Ended December 31, 2021

Average sales prices

Liquids, per barrel $ 30.53 $ 35.41 $ 38.06 $ 39.77 $ 38.03 $ 34.20 $ 34.12 $ 24.25 $ 24.07

Crude, per barrel $ 65.16 $ 62.84 $ 72.38 $ 63.71 $ 71.40 $ 69.20 $ 66.14 $ 58.31 $ —

Natural gas liquids, per barrel 28.54 26.33 39.40 — 30.00 — 29.10 27.13 66.00

Natural gas, per thousand cubic feet 3.02 3.39 2.66 4.10 8.22 12.50 5.08 0.47 9.71

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Average sales prices 3

Liquids, per barrel $ 48.54 $ 54.85 $ 62.27 $ 59.53 $ 60.15 $ 61.80 $ 54.47 $ 49.14 $ 45.25

Crude, per barrel $ 36.28 $ 35.80 $ 38.89 $ 39.77 $ 37.82 $ 34.20 $ 37.41 $ 25.39 $ 25.22

Natural gas liquids, per barrel 9.97 11.79 20.51 — 40.97 — 11.11 10.58 22.52

Natural gas, per thousand cubic feet 0.96 2.20 1.61 4.30 5.42 1.07 3.68 0.54 0.61

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Average sales prices 3

Liquids, per barrel $ 58.17 $ 58.27 $ 69.75 $ 63.55 $ 68.78 $ 66.31 $ 62.45 $ 56.20 $ 56.41

Crude, per barrel $ 57.58 $ 57.50 $ 63.94 $ 59.53 $ 60.15 $ 61.80 $ 59.43 $ 50.85 $ 47.58

Natural gas liquids, per barrel 11.22 7.50 24.00 — — — 12.60 18.57 31.94

Natural gas, per thousand cubic feet 1.07 2.24 1.84 4.73 7.54 4.43 4.86 0.79 0.99

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2 Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel.

3 2020 and 2019 unit prices have been conformed to current presentation.

Crude and NGL realizations were previously combined and disclosed as liquids.

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Table V Reserve Quantity Information

Table V Proved Reserve Quantity Information*

Summary of Net Oil and Gas Reserves

13 unchanged sentences

Asia 270 — — 7,007 358 — — 7,864 406 — — 3,382

Australia/Oceania 115 — 4 8,951 136 — 4 10,697 127 — 5 10,084

Australia 102 — 3 8,057 115 — 4 8,951 136 — 4 10,697

Europe 24 — — 8 23 — — 8 21 — — 8

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Asia 52 — — 466 45 — — 319 107 — — 299

Australia/Oceania 26 — — 2,434 30 — — 3,961 29 — — 3,647

Australia 32 — — 3,627 26 — — 2,434 30 — — 3,961

Europe 38 — — 13 38 — — 14 48 — — 18

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Total Proved Reserves 4,604 471 1,038 30,908 4,722 597 828 29,922 5,241 540 740 29,457

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.

*Throughout Table V, some totals and percentages may not exactly agree with the sum of their component parts because of rounding.

Reserves Governance The company has adopted a comprehensive reserves and resources classification system modeled after a system developed and approved by a number of organizations, including the Society of Petroleum Engineers, the World Petroleum Congress and the American Association of Petroleum Geologists.

The company classifies discovered recoverable hydrocarbons into six categories based on their status at the time of reporting – three deemed commercial and three potentially recoverable.

Within the commercial classification are proved reserves and two categories of unproved reserves:

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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 developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

Proved undeveloped reserves are the quantities expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

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

Supplemental Information on Oil and Gas Producing Activities - Unaudited

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.

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.

The Manager of Global Reserves has more than 30 years of experience working in the oil and gas industry and holds both undergraduate and graduate degrees in geoscience.

His experience includes various technical and management roles in providing reserve and resource estimates in support of major capital and exploration projects, and more than 10 years of overseeing oil and gas reserves processes.

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The RAC has the following primary responsibilities:

establish the policies and processes used within the operating units to estimate reserves;

establish the policies and processes used within the business units to estimate reserves;

provide independent reviews and oversight of the business units’ recommended reserves estimates and changes;

confirm that proved reserves are recognized in accordance with SEC guidelines;

determine that reserve volumes are calculated using consistent and appropriate standards, procedures and technology;

determine that reserve quantities are calculated using consistent and appropriate standards, procedures and technology;

and maintain the Chevron Corporation Reserves Manual , which provides standardized procedures used corporatewide for classifying and reporting hydrocarbon reserves.

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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 2021, additions to Chevron’s proved reserves were based on a wide range of geologic and engineering technologies.

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Improved recovery 9

Extension & Discoveries 123

Purchases 329

Extension and discoveries 658

Transfers to proved developed (371)

Quantity at December 31 3,860

In 2021, revisions include an increase of 202 million BOE in Australia, primarily from the approval of the Jansz Io Compression project (Gorgon and Jansz Io make up the Gorgon Project).

In the United States, there was a net increase of 192 million BOE primarily from the Midland and Delaware basins, where 105 million BOE was attributed to improved commodity price environment, and performance revisions, and 91 million BOE associated with the Anchor Project in the Gulf of Mexico due to improved commodity price.

In Bangladesh, there was an increase of 30 million BOE, primarily from

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.

the approval of the Bibiyana Optimization Project and entitlement effects.

These increases were partially offset by a decrease of 339 million BOE in Kazakhstan, primarily at TCO, which includes entitlement effects, changes in field operating assumptions, reservoir model changes and changes to the FGP/WPMP schedule.

In 2021, extensions and discoveries of 630 million BOE in the United States were primarily due to the increase of activity and planned development of new locations in shale and tight assets in the Midland and Delaware basins.

The difference in 2021 extensions and discoveries of 149 million BOE, between the net quantities of proved reserves of 807 million BOE as reflected on pages 105 to 107 and net quantities of proved undeveloped reserves of 658 million BOE, is primarily due to proved Extensions and Discoveries that were not recognized as proved undeveloped reserves in the prior year and were recognized directly as proved developed reserves in 2021.

Purchases of 36 million BOE in 2021 are from the acquisition of various properties in the Midland and Delaware basins in the United States.

Transfers to proved developed reserves in 2021 include 245 million BOE in the United States, primarily from the Midland, Delaware and DJ basin developments and 125 million BOE in Equatorial Guinea, Canada, and other international locations.

These transfers are the consequence of development expenditures on completing wells and facilities.

During 2021, investments totaling approximately $6.6 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 $2.8 billion related primarily to various development activities in the Midland and Delaware basins and the Gulf of Mexico.

In Asia, expenditures during the year totaled approximately $2.5 billion, primarily related to development projects of TCO in Kazakhstan.

An additional $0.4 billion were spent on development activities in Australia.

In Africa, about $0.4 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.

Reserves that remain proved undeveloped for five or more years are a result of several factors that affect optimal project development and execution.

These factors may include the complex nature of the development project in adverse and remote locations, physical limitations of infrastructure or plant capacities that dictate project timing, compression projects that are pending reservoir pressure declines, and contractual limitations that dictate production levels.

At year-end 2021, 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.

The majority of these reserves are in 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.

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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.

Affiliates account for about 950 million BOE of proved undeveloped reserves with about 900 million BOE that have remained undeveloped for five years or more.

Approximately 800 million BOE are related to TCO in Kazakhstan and about 100 million BOE are related to Angola LNG.

At TCO and Angola LNG, further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with reservoir depletion and facility constraints.

Annually, the company assesses whether any changes have occurred in facts or circumstances, such as changes to development plans, regulations, or government policies, that would warrant a revision to reserve estimates.

In 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

In 2021, improvements in commodity prices positively impacted the economic limits of oil and gas properties, resulting in proved reserve increases, and negatively impacted proved reserves due to entitlement effects.

The year-end reserves quantities have been updated for these circumstances and significant changes have been discussed in the appropriate reserves sections.

Over the past three years, the ratio of proved undeveloped reserves to total proved reserves has ranged between 31 percent and 35 percent.

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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.

Supplemental Information on Oil and Gas Producing Activities - Unaudited

At December 31, 2021, proved reserves for the company were 11.3 billion BOE.

2 unchanged sentences

Noteworthy changes in crude oil, condensate and synthetic oil proved reserves for 2019 through 2021 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.

Revisions 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 barrels 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.

Reservoir management and entitlement effects were mainly responsible for the 75 million barrels increase at TCO in Kazakhstan.

Improved field performance at various fields, including Moho-Bilondo in the Republic of Congo, Mafumeira in Angola, and Sonam in Nigeria, were responsible for the 42 million barrels 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 and performance revisions in TCO were primarily responsible for the 180 million barrels increase.

Entitlement effects primarily contributed to an increase of 77 million barrels 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 2021, the 206 million barrels increase in United States was primarily in the Gulf of Mexico and the Midland and Delaware basins.

The higher commodity price environment led to the increase of 126 million barrels in the Gulf of Mexico primarily from Anchor and a 68 million barrels increase in Midland and Delaware basins due to higher planned development activity.

In TCO, entitlement effects and technical changes in field operating assumptions, reservoir model, and project schedule were primarily responsible for the 208 million barrels decrease in Kazakhstan.

Entitlement effects primarily contributed to a decrease of 106 million barrels of synthetic oil at the Athabasca Oil Sands project in Canada.

In the Other Americas, performance revisions and price effects, mainly in Canada and Argentina, were primarily responsible for the 41 million barrels increase.

Extensions and Discoveries 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 barrels increase in the United States.

Extensions and discoveries in Loma Campana in Argentina were primarily responsible for the 39 million barrels 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.

In 2021, extensions and discoveries in the Midland and Delaware basins, and at the Whale Project in the Gulf of Mexico, were primarily responsible for the 349 million barrels increase in the United States.

Purchases 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.

In 2020, sales of 99 million barrels in Asia were in Azerbaijan.

In 2021, sales of 32 million barrels in the United States were in the Midland and Delaware basins.

Supplemental Information on Oil and Gas Producing Activities - Unaudited

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Consolidated Companies Affiliated Companies Total

Other Australia/ Synthetic Synthetic and Affiliated

Other Synthetic Synthetic and Affiliated

Millions of barrels U.S.

Africa Asia Oceania Europe Oil 2

Africa Asia Australia Europe Oil 2

Total TCO Oil Other 3

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Noteworthy changes in natural gas liquids proved reserves for 2019 through 2021 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.

Revisions 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 barrels 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 2021, higher commodity prices resulting in the increase of planned development activity in the Midland and Delaware basins were primarily responsible for the 107 million barrels increase in the United States.

Extensions and Discoveries In 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 barrels 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.

In 2021, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 190 million barrels increase in the United States.

Purchases In 2020, the acquisition of Noble assets contributed 198 million barrels primarily in the DJ basin, Midland and Delaware basins and Eagle Ford Shale in the United States.

Supplemental Information on Oil and Gas Producing Activities - Unaudited

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Consolidated Companies Affiliated Companies Total

Other Australia/ and Affiliated

Other and Affiliated

Millions of barrels U.S.

Africa Asia Oceania Europe Total TCO Other 2

Africa Asia Australia Europe Total TCO Other 2

Reserves at January 1, 2019 528 22 98 — 5 3 656 101 16 773

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Noteworthy changes in natural gas proved reserves for 2019 through 2021 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.

Revisions In 2019, strong performances at Wheatstone and the greater Gorgon areas were mainly responsible for 1.7 TCF increase in Australia.

At TCO 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.

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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 2021, the approval of the Jansz Io Compression project was mainly responsible for the 1.2 TCF increase in Australia.

Higher commodity prices, resulting in the increase of planned development activity in the Midland and Delaware basins, were mainly responsible for the 829 BCF increase in the United States.

In TCO, entitlement effects and technical changes in field operating assumptions, reservoir model, and project schedule were primarily responsible for the 179 BCF decrease.

Extensions and Discoveries 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.

In 2021, extensions and discoveries of 1.4 TCF 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.

Purchases In 2020, the acquisition of Noble assets contributed 5.4 TCF in Israel in Asia, 1.5 TCF in the DJ basin, Midland and Delaware basins and Eagle Ford Shale in the United States and 441 BCF in Equatorial Guinea in Africa.

Sales In 2019, sales of 240 BCF in Europe were in the United Kingdom and Denmark.

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Consolidated Companies Affiliated Companies Total

Other Australia/ and Affiliated

Other and Affiliated

Billions of cubic feet (BCF) U.S.

Africa Asia Oceania Europe Total TCO Other 2

Africa Asia Australia Europe Total TCO Other 2

Reserves at January 1, 2019 6,709 863 2,815 4,310 13,731 305 28,733 1,934 909 31,576

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5,885 455 2,796 7,473 11,684 21 28,314 1,701 893 30,908

1 Ending reserve balances in North America and South America were 234, 462, 582 and 95, 274, 281 in 2020, 2019 and 2018, respectively.

2 Ending reserve balances in Africa and South America were 898, 802, 799 and 0, 64, 110 in 2020, 2019 and 2018, respectively.

1 Ending reserve balances in North America and South America were 347, 234 and 462 and 108, 95 and 274 in 2021, 2020 and 2019, respectively.

2 Ending reserve balances in Africa and South America were 893, 898 and 802 and 0, 0 and 64 in 2021, 2020 and 2019, respectively.

3 Total “as sold” volumes are 2,599, 2,447 and 2,379 for 2021, 2020 and 2019, respectively.

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Consolidated Companies Affiliated Companies Total

Other Australia/ and Affiliated

Other and Affiliated

Millions of dollars U.S.

Americas Africa Asia Oceania Europe Total TCO Other Companies

Americas Africa Asia Australia Europe Total TCO Other Companies

At December 31, 2021

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Present Value at December 31, 2021 $ 103,884 $ 24,991 $ 128,875

Exhibits and Financial Statement Schedules

Exhibit and Financial Statement Schedules

(a) The following documents are filed as part of this report:

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Write-offs charged against the allowance, if any — ( 751 ) ( 3 )

Recoveries of amounts previously written-off, if any — — —

Balance at December 31 $ 745 $ 671 $ 849

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Balance at December 31 $ 17,651 $ 17,762 $ 15,965

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.

1 See also Note 17 Taxes .

2 Includes $ 974 of additions associated with the purchase of Noble in 2020.

Form 10-K Summary

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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 , 20 20 filed as Exhibit 3.

1 to Chevron Corporation's Quar terly Re port on Form 10-Q for the quarter ended September 30, 2020 , 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 In denture dated as of May 11, 2020, between Chevron Corporation and Deutsche Bank Trus t 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 In denture dated as of August 12 , 2020, among Chevron U.S.

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 R eport on Form 10-K for the year ended December 31, 2019, 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.

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.

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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.

10.5+ Chevron Incentive Plan, amended and restated effective January 1, 2021, filed as Exhibit 10.5 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31 , 202 0 , and incorporated herein by reference.

10.6+* Summary of Chevron Incentive Plan Award Criteria

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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.

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.

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 fo r the year ended December 31, 2019 and inco rporated herein by reference.

Form of Non-Qualified Stock Option Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.2 to Chevron Corporation’s Current Report on Form 8-K filed February 3, 2020, and incorporated herein by reference.

10.13+ Form of Stock Appreciation Rights Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.13 to Chevron Corporation ’ s Annual Report on Form 10-K for the year ended December 31, 2019 and incorporated herein by reference.

10.14+ Chevron Corporation Deferred Compensation Plan for Management Employees, filed as Exhibit 10.5 to Chevron Corporation’s Current Report on Form 8-K filed December 13, 2005, and incorporated herein by reference.

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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.

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 March 31 , 202 1 , and incorporated herein by reference.

Consent of PricewaterhouseCoopers LLP (page E-2).

Consent of PricewaterhouseCoopers LLP for Tengizchevroil.

23.3* Consent of Independent Petroleum Engineers and Geologists - Netherland, Sewell & Associates, Inc.

Power of Attorney for certain directors of Chevron Corporation, authorizing the signing of the Annual Report on Form 10-K on their behalf.

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Definitions of Selected Energy and Financial Terms (pages E-7 through E-8).

Tengizchevroil LLP Consolidated Financial Statements for the fiscal year ended December 31, 2020 .

99.2 Report of Netherland, Sewell & Associates, Inc.

, filed as Exhibit 99.3 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2020, and incorporated herein by reference.

iXBRL Schema Document.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 9A. Controls and Procedures