CHEVRON CORP (CVX) FY 2021 MD&A

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

Key Financial Results

Refer to the “Results of Operations” section beginning on page 38 for a discussion of financial results by major operating area for the three years ended December 31, 2021.

Business Environment and Outlook

Chevron Corporation is a global energy company with substantial business activities in the following countries: Angola, Argentina, Australia, Bangladesh, Brazil, Canada, China, Egypt, Equatorial Guinea, Israel, Kazakhstan, 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. Earnings of the company depend mostly on the profitability of its upstream business segment. The most significant factor affecting the results of operations for the upstream segment is the price of crude oil, which is determined in global markets outside of the company’s control. In the company’s downstream business, crude oil is the largest cost component of refined products. Periods of sustained lower commodity prices could result in the impairment or write-off of specific assets in future periods and cause the company to adjust operating expenses, including employee reductions, and capital 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.

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

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 (CO2e/boe),

•26 percent reduction in gas production GHG intensity to 24 kg CO2e/boe,

•53 percent reduction in methane intensity to 2 kg CO2e/boe, and

•66 percent reduction in flaring GHG intensity to 3 kg CO2e/boe.

The company also targets no routine flaring by 2030. We have set 2016 as our baseline to align with the year the Paris Agreement entered into force, and the company plans to update the metrics every five years in line with the Paris Agreement stocktakes. We believe these updates will provide additional transparency on the company’s progress toward its net zero aspiration.

2028 Portfolio Carbon Intensity Target The company also introduced a portfolio carbon intensity (PCI) metric, which is a measure of the carbon intensity across the full value chain of Chevron’s entire business. This metric encompasses the company’s Upstream and Downstream business and includes Scope 1 (direct emissions), Scope 2 (indirect emissions from imported electricity and steam), and certain Scope 3 (primarily emissions from use of sold products) emissions. The company’s PCI target is 71 grams (g) carbon dioxide equivalent (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

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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 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 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 and to acquire assets or operations complementary to its asset base to help augment the company’s financial performance and value growth. Asset dispositions and restructurings may result in significant gains or losses in future periods.

The company closely monitors developments in the financial and credit markets, the level of worldwide economic activity, and the implications for the company of movements in prices for crude oil and natural gas. Management takes these developments into account in the conduct of daily operations and for business planning.

Comments related to earnings trends for the company’s major business areas are as follows:

Upstream Earnings for the upstream segment are closely aligned with industry prices for crude oil and natural gas. Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry production and inventory levels, technology advancements, production quotas or other actions imposed by OPEC+ countries, actions of regulators, weather-related damage and disruptions, competing fuel prices, natural and human causes beyond the company’s control such as the COVID-19 pandemic, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. Any of these factors could also inhibit the company’s production capacity in an affected region. The company closely monitors developments in the countries in which it operates and holds investments and seeks to manage risks in operating its facilities and businesses.

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

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: 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.

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

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.

As U.S. 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. Henry Hub natural gas. The Brent price averaged $71 per barrel for the full-year 2021, compared to $42 in 2020. As of mid-February 2022, the Brent price was $100 per barrel. The WTI price averaged $68 per barrel for the full-year 2021, compared to $39 in 2020. As of mid-February 2022, the WTI price was $95 per barrel. The majority of the company’s equity crude production is priced based on the Brent benchmark.

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 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 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 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. (See page 42 for the company’s average natural gas realizations for the U.S. and international regions.)

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+; price effects on entitlement volumes; changes in fiscal terms or restrictions on the scope of company operations; delays in construction; reservoir performance; greater-than-expected declines in production from mature fields; start-up or ramp-up of projects; fluctuations in demand for crude oil and natural gas in various markets; weather conditions that may shut in

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

production; civil unrest; changing geopolitics; delays in completion of maintenance turnarounds; storage constraints or economic conditions that could lead to shut-in production; or other disruptions to operations. The outlook for future production levels is also affected by the size and number of economic investment opportunities and the time lag between initial exploration and the beginning of production. The company has increased its investment emphasis on short-cycle projects.

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 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, petrochemicals and renewable fuels. Industry margins are sometimes volatile and can be affected by the global and regional supply-and-demand balance for refined products and petrochemicals, and by changes in the price of crude oil, other refinery and petrochemical feedstocks, and natural gas. Industry margins can also be influenced by inventory levels, geopolitical events, costs of materials and services, refinery or chemical plant capacity utilization, maintenance programs, and disruptions at refineries or chemical plants resulting from unplanned outages due to severe weather, fires or other operational events.

Other factors affecting profitability for downstream operations include the reliability and efficiency of the company’s refining, marketing and petrochemical assets, the effectiveness of its crude oil and product supply functions, and the volatility of tanker-charter rates for the company’s shipping operations, which are driven by the industry’s demand for crude oil and product tankers. Other factors beyond the company’s control include the general level of inflation and energy costs to operate the company’s refining, marketing and petrochemical assets, and changes in tax, environmental, and other applicable laws and regulations.

The company’s most significant marketing areas are the West Coast and Gulf Coast of the United States and Asia Pacific. Chevron operates or has significant ownership interests in refineries in each of these areas. Additionally, the company has a small but growing presence in renewable fuels.

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

Refer to the “Results of Operations” section on page 40 for additional discussion of the company’s downstream operations.

All Other consists of worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities and technology companies.

Operating Developments

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

Upstream

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.

Downstream

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

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.

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

Other

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

The following section presents the results of operations and variances on an after-tax basis for the company’s business segments – Upstream and Downstream – as well as for “All Other.” Earnings are also presented for the U.S. and international geographic areas of the Upstream and Downstream business segments. Refer to Note 14 Operating Segments and Geographic Data for a discussion of the company’s “reportable segments.” This section should also be read in conjunction with the discussion in “Business Environment and Outlook” 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.

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

U.S. Upstream

U.S. 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. crude oil and natural gas liquids in 2021 was $56.06 per barrel compared with $30.53 in 2020. The average natural gas realization was $3.11 per thousand cubic feet in 2021, compared with $0.98 in 2020.

Net oil-equivalent production in 2021 averaged 1.14 million barrels per day, up 8 percent from 2020. 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 1.69 billion cubic feet per day in 2021, an increase of 5 percent from 2020.

International Upstream

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.

The company’s average realization for international crude oil and natural gas liquids in 2021 was $64.53 per barrel compared with $36.07 in 2020. The average natural gas realization was $5.93 per thousand cubic feet in 2021 compared with $4.59 in 2020.

International net oil-equivalent production was 1.96 million barrels per day in 2021, down 3 percent from 2020. The decrease was primarily due to the absence of 69,000 barrels per day following expiration of the Rokan concession in

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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.

U.S. Downstream

U.S. 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

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 $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.

All Other

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 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 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.

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

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

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.

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.

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.

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.

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

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

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.

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

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

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.

U.S. 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.

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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 Data1,2

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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 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. Cash provided by investing activities included proceeds and deposits related to asset sales of $1.4 billion in 2021 and $2.9 billion in 2020.

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 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 $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.

At year-end 2021, settlement of these obligations was not expected to require the use of working capital in 2022, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

The company has an automatic shelf registration statement that expires in August 2023 for an unspecified amount of nonconvertible debt securities issued by Chevron Corporation or CUSA.

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,

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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. The company’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and P-1 by Moody’s. All of these ratings denote high-quality, investment-grade securities.

The company’s future debt level is dependent primarily on results of operations, cash that may be generated from asset dispositions, the capital program, lending commitments to affiliates and shareholder distributions. Based on its high-quality debt ratings, the company believes that it has substantial borrowing capacity to meet unanticipated cash requirements. During extended periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, the company has the ability to modify its capital spending plans and discontinue or curtail the stock repurchase program. This provides the flexibility to continue paying the common stock dividend and remain committed to retaining the company’s high-quality debt ratings.

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

Summarized Financial Information for Guarantee of Securities of Subsidiaries CUSA issued bonds that are fully and unconditionally guaranteed on an unsecured basis by Chevron Corporation (together, the “Obligor Group”). The tables below contain summary financial information for Chevron Corporation, as Guarantor, excluding its consolidated subsidiaries, and CUSA, as the issuer, excluding its consolidated subsidiaries. The summary financial information of the Obligor Group is presented on a combined basis, and transactions between the combined entities have been eliminated. Financial information for non-guarantor entities has been excluded.

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 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.

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

Capital and Exploratory Expenditures

Capital and exploratory expenditures by business segment for 2021, 2020 and 2019 are as follows:

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. 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. Approximately 81 percent was expended for upstream operations in 2020. International upstream accounted for 51 percent of the worldwide upstream investment in 2021 and 53 percent in 2020.

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.

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: 2022 – $683; 2023 – $533; 2024 – $447; 2025 – $388; 2026 – $305; 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.”

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

Financial Ratios and Metrics

The following represent several metrics the company believes are useful measures to monitor the financial health of the company and its performance over time:

Current Ratio Current assets divided by current liabilities, which indicates the company’s ability to repay its short-term liabilities with short-term assets. The current ratio in all periods was adversely affected by the fact that Chevron’s inventories are valued on a last-in, first-out basis. At year-end 2021, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $5.6 billion.

Interest Coverage Ratio Income before income tax expense, plus interest and debt expense and amortization of capitalized interest, less net income attributable to noncontrolling interests, divided by before-tax interest costs. This ratio indicates the company’s ability to pay interest on outstanding debt. The company’s interest coverage ratio in 2021 was higher than 2020 due to higher income.

Free Cash Flow The cash provided by operating activities less cash capital expenditures, which represents the cash available to creditors and investors after investing in the business.

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

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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 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.

Capital Employed The sum of Chevron Corporation Stockholders’ Equity, total debt and noncontrolling interests, which represents the net investment in the business.

Return on Average Capital Employed (ROCE) Net income attributable to Chevron (adjusted for after-tax interest expense and noncontrolling interest) divided by average capital employed. Average capital employed is computed by averaging the sum of capital employed at the beginning and end of the year. ROCE is a ratio intended to measure annual earnings as a percentage of historical investments in the business.

Return on Stockholders’ Equity (ROSE) Net income attributable to Chevron divided by average Chevron Corporation Stockholders’ Equity. Average stockholders’ equity is computed by averaging the sum of stockholders’ equity at the beginning and end of the year. ROSE is a ratio intended to measure earnings as a percentage of shareholder investments.

Financial and Derivative Instrument Market Risk

The market risk associated with the company’s portfolio of financial and derivative instruments is discussed below. The estimates of financial exposure to market risk do not represent the company’s projection of future market changes. The actual impact of future market changes could differ materially due to factors discussed elsewhere in this report, including those set forth under the heading “Risk Factors” in Part I, Item 1A.

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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. The company uses derivative commodity instruments to manage these exposures on a portion of its activity, including firm commitments and anticipated transactions for the purchase, sale and storage of crude oil, refined products, natural gas, natural gas liquids, liquefied natural gas and feedstock for company refineries. The company also uses derivative commodity instruments for limited trading purposes. The results of these activities were not material to the company’s financial position, results of operations or cash flows in 2021.

The company’s market exposure positions are monitored on a daily basis by an internal Risk Control group in accordance with the company’s risk management policies. The company’s risk management practices and its compliance with policies are reviewed by the Audit Committee of the company’s Board of Directors.

Derivatives beyond those designated as normal purchase and normal sale contracts are recorded at fair value on the Consolidated Balance Sheet with resulting gains and losses reflected in income. Fair values are derived principally from published market quotes and other independent third-party quotes. The change in fair value of Chevron’s derivative commodity instruments in 2021 was not material to the company’s results of operations.

The company uses the Monte Carlo simulation method as its Value-at-Risk (VaR) model to estimate the maximum potential loss in fair value, at the 95 percent confidence level with a one-day holding period, from the effect of adverse changes in market conditions on derivative commodity instruments held or issued. Based on these inputs, the VaR for the company’s primary risk exposures in the area of derivative commodity instruments at December 31, 2021 and 2020 was not material to the company’s cash flows or results of operations.

Foreign Currency The company may enter into foreign currency derivative contracts to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments. The foreign currency derivative contracts, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. There were no material open foreign currency derivative contracts at December 31, 2021.

Interest Rates The company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Interest rate swaps, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. At year-end 2021, the company had no interest rate swaps.

Transactions With Related Parties

Chevron enters into a number of business arrangements with related parties, principally its equity affiliates. These arrangements include long-term supply or offtake agreements and long-term purchase agreements. Refer to “Other Information” in Note 15 Investments and Advances for further discussion. Management believes these agreements have been negotiated on terms consistent with those that would have been negotiated with an unrelated party.

Litigation and Other Contingencies

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

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

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

Environmental The following table displays the annual changes to the company’s before-tax environmental remediation reserves, including those for U.S. federal Superfund sites and analogous sites under state laws.

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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 $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 24 Other Contingencies and Commitments under the heading “Environmental” for additional discussion of environmental remediation provisions and year-end reserves. Refer also to Note 25 Asset Retirement Obligations for additional discussion of the company’s asset retirement obligations.

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

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

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

Environmental Matters

The company is subject to various international, federal, state and local environmental, health and safety laws, regulations and market-based programs. These laws, regulations and programs continue to evolve and are expected to increase in both number and complexity over time and govern not only the manner in which the company conducts its operations, but also the products it sells. For example, international agreements and national, regional, and state legislation and regulatory measures that aim to limit or reduce greenhouse gas (GHG) emissions are currently in various stages of implementation. Consideration of GHG issues and the responses to those issues through international agreements and national, regional or state legislation or regulations are integrated into the company’s strategy and planning, capital investment reviews and risk management tools and processes, where applicable. They are also factored into the company’s long-range supply, demand and energy price forecasts. These forecasts reflect long-range effects from renewable fuel penetration, energy efficiency standards, climate-related policy actions, and demand response to oil and natural gas prices. In addition, legislation and regulations intended to address hydraulic fracturing also continue to evolve 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.

Most of the costs of complying with existing laws and regulations pertaining to company operations and products are embedded in the normal costs of doing business. However, it is not possible to predict with certainty the amount of additional investments in new or existing technology or facilities or the amounts of increased operating costs to be incurred in the future to: prevent, control, reduce or eliminate releases of hazardous materials or other pollutants into the environment; remediate and restore areas damaged by prior releases of hazardous materials; or comply with new environmental laws or regulations. Although these costs may be significant to the results of operations in any single period, the company does not presently expect them to have a material adverse effect on the company’s liquidity or financial position.

Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. The company may incur expenses for corrective actions at various owned and previously owned facilities and at third-party-owned waste disposal sites used by the company. An obligation may arise when operations are closed or sold or at non-Chevron sites where company products have been handled or disposed of. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered acceptable at the time but now require investigative or remedial work or both to meet current standards.

Using definitions and guidelines established by the American Petroleum Institute, Chevron estimated its worldwide environmental spending in 2021 at approximately $1.9 billion for its consolidated companies. Included in these expenditures were approximately $0.3 billion of environmental capital expenditures and $1.6 billion of costs associated

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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. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites.

Critical Accounting Estimates and Assumptions

Management makes many estimates and assumptions in the application of accounting principles generally accepted in the United States of America (GAAP) that may have a material impact on the company’s consolidated financial statements and related disclosures and on the comparability of such information over different reporting periods. Such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on management’s experience and other information available prior to the issuance of the financial statements. Materially different results can occur as circumstances change and additional information becomes known.

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

1.the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters, or the susceptibility of such matters to change; and

2.the impact of the estimates and assumptions on the company’s financial condition or operating performance is material.

The development and selection of accounting estimates and assumptions, including those deemed “critical,” and the associated disclosures in this discussion have been discussed by management with the Audit Committee of the Board of Directors. The areas of accounting and the associated “critical” estimates and assumptions made by the company are as follows:

Oil and Gas Reserves Crude oil and natural gas reserves are estimates of future production that impact certain asset and expense accounts included in the Consolidated Financial Statements. Proved reserves are the estimated quantities of oil and gas that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in the future under existing economic conditions, operating methods and government regulations. Proved reserves include both developed and undeveloped volumes. Proved developed reserves represent volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for recompletion. Variables impacting Chevron’s estimated volumes of crude oil and natural gas reserves include field performance, available technology, commodity prices, and development, 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. Impacts of oil and gas reserves on Chevron’s Consolidated Financial Statements, using the successful efforts method of accounting, include the following:

1.Amortization - Capitalized exploratory drilling and development costs are depreciated on a unit-of-production (UOP) basis using proved developed reserves. Acquisition costs of proved properties are amortized on a UOP basis using total proved reserves. During 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 five percent across all oil and gas properties, UOP DD&A in 2021 would have increased by approximately $700 million.

2.Impairment - Oil and gas reserves are used in assessing oil and gas producing properties for impairment. A significant reduction in the estimated reserves of a property would trigger an impairment review. Proved reserves (and, in some cases, a portion of unproved resources) are used to estimate future production volumes in the cash flow model. For a further discussion of estimates and assumptions used in impairment assessments, see Impairment of Properties, Plant and Equipment and Investments in Affiliates below.

Refer to Table V, “Reserve Quantity Information,”, 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.

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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 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 18 Properties, Plant and Equipment and to the section on Properties, Plant and Equipment in Note 1 Summary of Significant Accounting Policies.

The company performs impairment assessments when triggering events arise to determine whether any write-down in the carrying value of an asset or asset group is required. For example, when significant downward revisions to crude oil and natural gas reserves are made for any single field or concession, an impairment review is performed to determine if the carrying value of the asset remains recoverable. Similarly, a significant downward revision in the company’s crude oil or natural gas price outlook would trigger impairment reviews for impacted upstream assets. In addition, impairments could occur due to changes in national, state or local environmental regulations or laws, including those designed to stop or impede the development or production of oil and gas. Also, if the expectation of sale of a particular asset or asset group in any period has been deemed more likely than not, an impairment review is performed, and if the estimated net proceeds exceed the carrying value of the asset or asset group, no impairment charge is required. Such calculations are reviewed each period until the asset or asset group is disposed. Assets that are not impaired on a held-and-used basis could possibly become impaired if a decision is made to sell such assets. That is, the assets would be impaired if they are classified as held-for-sale and the estimated proceeds from the sale, less costs to sell, are less than the assets’ associated carrying values.

Investments in common stock of affiliates that are accounted for under the equity method, as well as investments in other securities of these equity investees, are reviewed for impairment when the fair value of the investment falls below the company’s carrying value. When this occurs, a determination must be made as to whether this loss is other-than-temporary, in which case the investment is impaired. Because of the number of differing assumptions potentially affecting whether an investment is impaired in any period or the amount of the impairment, a sensitivity analysis is not practicable.

A sensitivity analysis of the impact on earnings for these periods if other assumptions had been used in impairment reviews and impairment calculations is not practicable, given the broad range of the company’s PP&E and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired, or resulted in larger impacts on impaired assets.

Asset Retirement Obligations In the determination of fair value for an asset retirement obligation (ARO), the company uses various assumptions and judgments, including such factors as the existence of a legal obligation, estimated amounts and timing of settlements, discount and inflation rates, and the expected impact of advances in technology and process improvements. A sensitivity analysis of the ARO impact on earnings for 2021 is not practicable, given the broad range of the company’s long-lived assets and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions would have reduced estimated future obligations, thereby lowering accretion expense and amortization costs, whereas unfavorable changes would have the opposite effect. Refer to Note 25 Asset Retirement Obligations for additional discussions on asset retirement obligations.

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

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

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

obligations. Critical assumptions in determining expense and obligations for OPEB plans, which provide for certain health care and life insurance benefits for qualifying retired employees and which are not funded, are the discount rate and the assumed health care cost-trend rates. Information related to the company’s processes to develop these assumptions is included in Note 23 Employee Benefit Plans under the relevant headings. Actual rates may vary significantly from estimates because of unanticipated changes beyond the company’s control.

For 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. pension plan. The actual return for 2021 was 11.2 percent. For the 10 years ended December 31, 2021, actual asset returns averaged 9.8 percent for this plan. 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. An increase in the expected long-term return on plan assets or the discount rate would reduce pension plan expense, and vice versa. As an indication of the sensitivity of pension expense to the long-term rate of return assumption, a 1 percent increase in this assumption for the company’s primary U.S. pension plan, which accounted for about 67 percent of companywide pension expense, would have reduced total pension plan expense for 2021 by approximately $81 million. A 1 percent increase in the discount rates for this same plan would have reduced pension expense for 2021 by approximately $357 million.

The aggregate funded status recognized at December 31, 2021, was a net liability of approximately $3.4 billion. An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan. At December 31, 2021, the company used a discount rate of 2.8 percent to measure the obligations for the primary U.S. pension plan. As an indication of the sensitivity of pension liabilities to the discount rate assumption, a 0.25 percent increase in the discount rate applied to the company’s primary U.S. pension plan, which accounted for about 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. For the primary U.S. OPEB plan, the company used a discount rate for service cost of 2.9 percent and a discount rate for interest cost of 1.6 percent to measure expense in 2021, and a 2.8 percent discount rate to measure the benefit obligations at December 31, 2021. Discount rate changes, similar to those used in the pension sensitivity analysis, resulted in an immaterial impact on 2021 OPEB expense and OPEB liabilities at the end of 2021.

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 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. Actual costs can frequently vary from estimates for a variety of reasons. For example, the costs for settlement of claims and litigation can vary from estimates based on differing interpretations of laws, opinions on culpability and assessments on the amount of damages. Similarly, liabilities for environmental remediation are subject to change because of changes in laws, regulations and their interpretation, the determination of additional information on the extent and nature of site contamination, and improvements in technology.

Under the accounting rules, a liability is generally recorded for these types of contingencies if management determines the loss to be both probable and estimable. The company generally reports these losses as “Operating expenses” or “Selling, general and administrative expenses” on the Consolidated Statement of Income. An exception to this handling is for income tax matters, for which benefits are recognized only if management determines the tax position is “more likely than not” (i.e., likelihood greater than 50 percent) to be allowed by the tax jurisdiction. For additional discussion of income tax uncertainties, refer to Note 24 Other Contingencies and Commitments under the heading Income Taxes. Refer also to the business segment discussions elsewhere in this section for the effect on earnings from losses associated with certain litigation, environmental remediation and tax matters for the three years ended December 31, 2021.

An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in recording these liabilities is not practicable because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss. For further information, refer to “Changes in management’s estimates and assumptions may have a material

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

New Accounting Standards

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

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Quarterly Results

Unaudited

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[table omitted - see filing]