CHEVRON CORP

Note 1

Summary of Significant Accounting Policies

General The company’s Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America. These require the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Although the company uses its best estimates and judgments, actual results could differ from these estimates as circumstances change and additional information becomes known. Prior years’ data have been reclassified in certain cases to conform to the 2023 presentation basis.

Subsidiary and Affiliated Companies The Consolidated Financial Statements include the accounts of controlled subsidiary companies more than 50 percent-owned and any variable interest entities in which the company is the primary beneficiary. Undivided interests in oil and gas joint ventures and certain other assets are consolidated on a proportionate basis. Investments in and advances to affiliates in which the company has a substantial ownership interest of approximately 20 percent to 50 percent, or for which the company exercises significant influence but not control over policy decisions, are accounted for by the equity method.

Investments in affiliates are assessed for possible impairment when events indicate that the fair value of the investment may be below the company’s carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in net income. In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee’s financial performance, and the company’s ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. The new cost basis of investments in these equity investees is not changed for subsequent recoveries in fair value.

Differences between the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned to the extent practicable to specific assets and liabilities based on the company’s analysis of the various factors giving rise to the difference. When appropriate, the company’s share of the affiliate’s reported earnings is adjusted quarterly to reflect the difference between these allocated values and the affiliate’s historical book values.

Noncontrolling Interests Ownership interests in the company’s subsidiaries held by parties other than the parent are presented separately from the parent’s equity on the Consolidated Balance Sheet. The amount of consolidated net income attributable to the parent and the noncontrolling interests are both presented on the face of the Consolidated Statement of Income and Consolidated Statement of Equity. Included within noncontrolling interest is redeemable noncontrolling interest.

Fair Value Measurements The three levels of the fair value hierarchy of inputs the company uses to measure the fair value of an asset or a liability are as follows. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Level 3 inputs are inputs that are not observable in the market.

Derivatives The majority of the company’s activity in derivative commodity instruments is intended to manage the financial risk posed by physical transactions. For some of this derivative activity, the company may elect to apply fair value or cash flow hedge accounting with changes in fair value recorded as components of accumulated other comprehensive income (loss). For other similar derivative instruments, generally because of the short-term nature of the contracts or their limited use, the company does not apply hedge accounting, and changes in the fair value of those contracts are reflected in current income. For the company’s commodity trading activity, gains and losses from derivative instruments are reported in current income. The company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Interest rate swaps related to a portion of the company’s fixed-rate debt, if any, may be accounted for as fair value hedges. Interest rate swaps related to floating-rate debt, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. Where Chevron is a party to master netting arrangements, fair value receivable and payable amounts recognized for derivative instruments executed with the same counterparty are generally offset on the balance sheet.

Inventories Crude oil, products and chemicals inventories are generally stated at cost, using a last-in, first-out method. In the aggregate, these costs are below market. “Materials, supplies and other” inventories are primarily stated at cost or net realizable value.

Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. All other exploratory wells and costs are expensed. Refer to Note 21 Accounting for Suspended Exploratory Wells for additional discussion of accounting for suspended exploratory well costs.

Long-lived assets to be held and used, including proved crude oil and natural gas properties, are assessed for possible impairment by comparing their carrying values with their associated undiscounted, future net cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset (including changes to the commodity price forecast or carbon costs), significant change in the extent or manner of use of or a physical change in an asset, and a more likely than not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted, future net cash flows. For proved crude oil and natural gas properties, the company performs impairment reviews on a country, concession, PSC, development area or field basis, as appropriate. In downstream, impairment reviews are performed on the basis of a refinery, a plant, a marketing/lubricants area or distribution area, as appropriate. Impairment amounts are recorded as incremental “Depreciation, depletion and amortization” expense.

Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value. Refer to Note 9 Fair Value Measurements relating to fair value measurements. The fair value of a liability for an ARO is recorded as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. Refer also to Note 25 Asset Retirement Obligations relating to AROs.

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

The capitalized costs of all other plant and equipment are depreciated or amortized over their estimated useful lives. In general, the declining-balance method is used to depreciate plant and equipment in the United States; the straight-line method is generally used to depreciate international plant and equipment and to amortize finance lease right-of-use assets.

Gains or losses are not recognized for normal retirements of properties, plant and equipment subject to composite group amortization or depreciation. Gains or losses from abnormal retirements are recorded as expenses, and from sales as “Other income.”

Expenditures for maintenance (including those for planned major maintenance projects), repairs and minor renewals to maintain facilities in operating condition are generally expensed as incurred. Major replacements and renewals are capitalized.

Leases Leases are classified as operating or finance leases. Both operating and finance leases recognize lease liabilities and associated right-of-use assets. The company has elected the short-term lease exception and therefore only recognizes right-of-use assets and lease liabilities for leases with a term greater than one year. The company has elected the practical expedient to not separate non-lease components from lease components for most asset classes except for certain asset classes that have significant non-lease (i.e., service) components.

Where leases are used in joint ventures, the company recognizes 100 percent of the right-of-use assets and lease liabilities when the company is the sole signatory for the lease (in most cases, where the company is the operator of a joint venture). Lease costs reflect only the costs associated with the operator’s working interest share. The lease term includes the committed lease term identified in the contract, taking into account renewal and termination options that management is

reasonably certain to exercise. The company uses its incremental borrowing rate as a proxy for the discount rate based on the term of the lease unless the implicit rate is available.

Goodwill Goodwill resulting from a business combination is not subject to amortization. The company tests such goodwill at the reporting unit level for impairment annually at December 31, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount.

Environmental Expenditures Environmental expenditures that relate to ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized.

Liabilities related to future remediation costs are recorded when environmental assessments or cleanups or both are probable and the costs can be reasonably estimated. For crude oil, natural gas and mineral-producing properties, a liability for an ARO is made in accordance with accounting standards for asset retirement and environmental obligations. Refer to Note 25 Asset Retirement Obligations for a discussion of the company’s AROs. For abandonment and decommissioning obligations related to previously sold assets, refer to Note 24 Other Contingencies and Commitments.

For U.S. federal Superfund sites and analogous sites under state laws, the company records a liability for its designated share of the probable and estimable costs, and probable amounts for other potentially responsible parties when mandated by the regulatory agencies because the other parties are not able to pay their respective shares. The gross amount of environmental liabilities is based on the company’s best estimate of future costs using currently available technology and applying current regulations and the company’s own internal environmental policies. Future amounts are not discounted. Recoveries or reimbursements are recorded as assets when receipt is reasonably assured.

Currency Translation The U.S. dollar is the functional currency for substantially all of the company’s consolidated operations and those of its equity affiliates. For those operations, all gains and losses from currency remeasurement are included in current period income. The cumulative translation effects for those few entities, both consolidated and affiliated, using functional currencies other than the U.S. dollar are included in “Currency translation adjustment” on the Consolidated Statement of Equity.

Revenue Recognition The company accounts for each delivery order of crude oil, NGLs, natural gas, petroleum and chemical products as a separate performance obligation. Revenue is recognized when the performance obligation is satisfied, which typically occurs at the point in time when control of the product transfers to the customer. Payment is generally due within 30 days of delivery. The company accounts for delivery transportation as a fulfillment cost, not a separate performance obligation, and recognizes these costs as an operating expense in the period when revenue for the related commodity is recognized.

Revenue is measured as the amount the company expects to receive in exchange for transferring commodities to the customer. The company’s commodity sales are typically based on prevailing market-based prices and may include discounts and allowances. Until market prices become known under terms of the company’s contracts, the transaction price included in revenue is based on the company’s estimate of the most likely outcome.

Discounts and allowances are estimated using a combination of historical and recent data trends. When deliveries contain multiple products, an observable standalone selling price is generally used to measure revenue for each product. The company includes estimates in the transaction price only to the extent that a significant reversal of revenue is not probable in subsequent periods.

Stock Options and Other Share-Based Compensation The company issues stock options and other share-based compensation to certain employees. For equity awards, such as stock options and certain restricted stock units, total compensation cost is based on the grant date fair value, and for liability awards, such as stock appreciation rights, total compensation cost is based on the settlement value. The company recognizes stock-based compensation expense for all awards over the service period required to earn the award, which is the shorter of the vesting period or the time period in which an employee becomes eligible to retain the award at retirement. The company’s Long-Term Incentive Plan (LTIP) awards include stock options and stock appreciation rights, which have graded vesting provisions by which one-third of each award vests on each of the first, second and third anniversaries of the date of grant. In addition, performance shares granted under the company’s LTIP will vest at the end of thethree-year performance period. For awards granted under the company’s LTIP beginning in 2017, stock options and stock appreciation rights have graded vesting by which one-third of each award vests annually on each January 31 on or after the first anniversary of the grant date. Special restricted stock unit awards have cliff vesting by which the total award will vest on January 31 on or after the third anniversary of the grant date. Standard restricted stock unit awards have cliff vesting by which the total award will vest on January 31 on or after

the fifth anniversary of the grant date, subject to adjustment upon termination pursuant to the satisfaction of certain criteria. Commencing for grants issued in January 2023 and after, standard restricted stock units vest ratably on an annual basis over athree-year period. The company amortizes these awards on a straight-line basis.

Note 2

Changes in Accumulated Other Comprehensive Losses

The change in Accumulated Other Comprehensive Losses (AOCL) presented on the Consolidated Balance Sheet and the impact of significant amounts reclassified from AOCL on information presented in the Consolidated Statement of Income for the year ended December 31, 2023, are reflected in the table below.

1 All amounts are net of tax.

2 Refer to Note 23 Employee Benefit Plans, for reclassified components, including amortization of actuarial gains or losses, amortization of prior service costs and settlement losses, totaling $231 that are included in employee benefit costs for the year ended December 31, 2023. Related income taxes for the same period, totaling $25, are reflected in Income Tax Expense on the Consolidated Statement of Income. All other reclassified amounts were insignificant.

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

Note 3

Information Relating to the Consolidated Statement of Cash Flows

The “Other” line in the Operating Activities section includes changes in postretirement benefits obligations and other long-term liabilities.

The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash. “Depreciation, depletion and amortization” and “Deferred income tax provision” collectively include approximately $1,765 in non-cash reductions to “Properties, plant and equipment” and “Investments and advances” in 2023 relating to impairments, mainly of upstream assets in California. “Other income (loss)” and “Deferred income tax provision” collectively include a $1,950 charge related to non-cash increases to “Deferred credits and other noncurrent obligations” related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S. Gulf of Mexico. The cash outlays for these abandonment and decommissioning obligations are expected to take place over the next decade.

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, 2023.

The components of “Capital expenditures” are presented in the following table:

*Excludes non-cash movements of $1,559 in 2023, $334 in 2022 and $316 in 2021.

The table below quantifies the beginning and ending balances of restricted cash and restricted cash equivalents in the Consolidated Balance Sheet:

Note 4

New Accounting Standards

Segment Reporting (Topic 280) Improvements to Reportable Segment Disclosures In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) 2023-07, which becomes effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The standard requires companies to disclose significant segment expenses. The company does not expect the standard to have a material effect on its consolidated financial statements and has begun evaluating disclosure presentation alternatives.

Income Taxes (Topic 740) Improvements to Income Tax Disclosures In December 2023, the FASB issued ASU 2023-09, which becomes effective for fiscal years beginning after December 15, 2024. The standard requires companies to disclose specific categories in the income tax rate reconciliation table and the amount of income taxes paid per major jurisdiction. The company does not expect the standard to have a material effect on its consolidated financial statements and has begun evaluating disclosure presentation alternatives.

Note 5

Lease Commitments

The company enters into leasing arrangements as a lessee; any lessor arrangements are not significant. Operating lease arrangements mainly involve land, bareboat charters, terminals, drill ships, drilling rigs, time chartered vessels, office buildings and warehouses, and exploration and production equipment. Finance leases primarily include facilities, vessels and office buildings.

Details of the right-of-use assets and lease liabilities for operating and finance leases, including the balance sheet presentation, are as follows:

• Includes non-cash additions of $2,556 and $233 in 2023, and $1,807 and $3 in 2022 for right-of-use assets obtained in exchange for new and modified lease liabilities for operating and finance leases, respectively.

Total lease costs consist of both amounts recognized in the Consolidated Statement of Income during the period and amounts capitalized as part of the cost of another asset. Total lease costs incurred for operating and finance leases were as follows:

*Includes variable and short-term lease costs.

Cash paid for amounts included in the measurement of lease liabilities was as follows:

At December 31, 2023, the estimated future undiscounted cash flows for operating and finance leases were as follows:

Additionally, the company has $232 in future undiscounted cash flows for operating leases not yet commenced. These leases are primarily for drill ships, drilling rigs and storage tanks. For those leasing arrangements where the underlying asset is not yet constructed, the lessor is primarily involved in the design and construction of the asset.

Note 6

Summarized Financial Data – Chevron U.S.A. Inc.

Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron Corporation. CUSA and its subsidiaries manage and operate most of Chevron’s U.S. businesses. Assets include those related to the exploration and production of crude oil, natural gas liquids and natural gas and those associated with the refining, marketing, supply and distribution of products derived from petroleum, excluding most of the regulated pipeline operations of Chevron. CUSA also holds the company’s investment in the Chevron Phillips Chemical Company LLC joint venture, which is accounted for using the equity method. The summarized financial information for CUSA and its consolidated subsidiaries is as follows:

Note 7

Summarized Financial Data – Tengizchevroil LLP

Chevron has a 50 percent equity ownership interest in Tengizchevroil LLP (TCO). Refer to Note 15 Investments and Advances for a discussion of TCO operations. Summarized financial information for 100 percent of TCO is presented in the table below:

Note 8

Summarized Financial Data – Chevron Phillips Chemical Company LLC

Chevron has a 50 percent equity ownership interest in Chevron Phillips Chemical Company LLC (CPChem). Refer to Note 15 Investments and Advances for a discussion of CPChem operations. Summarized financial information for 100 percent of CPChem is presented in the table below:

Note 9

Fair Value Measurements

The tables below show the fair value hierarchy for assets and liabilities measured at fair value on a recurring and nonrecurring basis at December 31, 2023 and 2022.

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, 2023.

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 valued using quoted prices from active markets such as the New York Mercantile Exchange. Derivatives classified as Level 2 include swaps, options and forward contracts, the fair values of which are obtained from third-party broker quotes, industry pricing services and exchanges. The company obtains multiple sources of pricing information for the Level 2 instruments. Since this pricing information is generated from observable market data, it has historically been very consistent. The company does not materially adjust this information.

Properties, Plant and Equipment In 2023, the company impaired a portion of its U.S. upstream assets, primarily in California, due to continuing regulatory challenges in the state that have resulted in lower anticipated future investment levels in its business plans. The company did not have any individually material impairments of long-lived assets measured at fair value on a nonrecurring basis to report in 2022.

Investments and Advances The company did not have any material impairments of investments and advances measured at fair value on a nonrecurring basis to report in 2023 or 2022.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

At year-end 2023, the company had assets measured at fair value Level 3 using unobservable inputs of $521. The carrying value of these assets were written down to fair value based on estimates derived from discounted cash flow models. Cash

flows were determined using estimates of future production, an outlook of future price based on published prices and a discount rate believed to be consistent with those used by principal market participants.

Assets and Liabilities Not Required to Be Measured at Fair Value The company holds cash equivalents in U.S. and non-U.S. portfolios. The instruments classified as cash equivalents are primarily bank time deposits with maturities of 90 days or less and money market funds. “Cash and cash equivalents” had carrying/fair values of $8,178 and $17,678 at December 31, 2023, and December 31, 2022, respectively. The fair values of cash and cash equivalents are classified as Level 1 and reflect the cash that would have been received if the instruments were settled at December 31, 2023.

“Cash and cash equivalents” do not include investments with a carrying/fair value of $1,097 and $1,443 at December 31, 2023, and December 31, 2022, respectively. At December 31, 2023, these investments are classified as Level 1 and include restricted funds related to certain upstream decommissioning activities, a financing program and tax payments.

Long-term debt, excluding finance lease liabilities, of $14,612 and $16,258 at December 31, 2023, and December 31, 2022, respectively, had estimated fair values of $13,709 and $14,959, respectively. Long-term debt primarily includes corporate issued bonds. The fair value of corporate bonds is $13,321 and classified as Level 1. The fair value of other long-term debt classified as Level 2 is $388.

The carrying values of other short-term financial assets and liabilities on the Consolidated Balance Sheet approximate their fair values. Fair value remeasurements of other financial instruments at December 31, 2023 and 2022, were not material.

Note 10

Financial and Derivative Instruments

Derivative Commodity Instruments The company’s derivative commodity instruments principally include crude oil, natural gas, liquefied natural gas and refined product futures, swaps, options, and forward contracts. The company applies cash flow hedge accounting to certain commodity transactions, where appropriate, to manage the market price risk associated with forecasted sales of crude oil. The company’s derivatives are not material to the company’s financial position, results of operations or liquidity. The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodity derivative activities.

The company uses derivative commodity instruments traded on the New York Mercantile Exchange and on electronic platforms of the Inter-Continental Exchange and Chicago Mercantile Exchange. In addition, the company enters into swap contracts and option contracts principally with major financial institutions and other oil and gas companies in the “over-the-counter” markets, which are governed by International Swaps and Derivatives Association agreements and other master netting arrangements. Depending on the nature of the derivative transactions, bilateral collateral arrangements may also be required.

Derivative instruments measured at fair value at December 31, 2023, 2022 and 2021, and their classification on the Consolidated Balance Sheet and Consolidated Statement of Income are as follows:

Consolidated Balance Sheet: Fair Value of Derivatives

Consolidated Statement of Income: The Effect of Derivatives

The amount reclassified from AOCL to “Sales and other operating revenues” from designated hedges was a decrease of $33 in 2023, compared with an increase of $80 in the prior year. At December 31, 2023, before-tax deferred gains in AOCL related to outstanding crude oil price hedging contracts were $7, all of which is expected to be reclassified into earnings during the next 12 months as the hedged crude oil sales are recognized in earnings.

The table below represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated Balance Sheet at December 31, 2023 and 2022.

Consolidated Balance Sheet: The Effect of Netting Derivative Assets and Liabilities

Derivative assets and liabilities are classified on the Consolidated Balance Sheet as “Accounts and notes receivable,” “Long-term receivables,” “Accounts payable,” and “Deferred credits and other noncurrent obligations.” Amounts not offset on the Consolidated Balance Sheet represent positions that do not meet all the conditions for “a right of offset.”

Concentrations of Credit Risk The company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, marketable securities, derivative financial instruments and trade receivables. The company’s short-term investments are placed with a wide array of financial institutions with high credit ratings. Company investment policies limit the company’s exposure both to credit risk and to concentrations of credit risk. Similar policies on diversification and creditworthiness are applied to the company’s counterparties in derivative instruments. For a discussion of credit risk on trade receivables, see Note 28 Financial Instruments - Credit Losses.

Note 11

Assets Held for Sale

At December 31, 2023, the company classified $675 of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. These assets are associated with upstream operations that are anticipated to be sold in the next 12 months. The revenues and earnings contributions of these assets in 2023 were not material.

Note 12

Equity

Retained earnings at December 31, 2023 and 2022, included $34,359 and $33,570, respectively, for the company’s share of undistributed earnings of equity affiliates.

At December 31, 2023, about 101 million shares of Chevron’s common stock remained available for issuance from the 104 million shares that were reserved for issuance under the 2022 Chevron Long-Term Incentive Plan. In addition,578,044 shares remain available for issuance from the 1,600,000 shares of the company’s common stock that were reserved for awards under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan.

Note 13

Earnings Per Share

Basic earnings per share (EPS) is based upon “Net Income (Loss) Attributable to Chevron Corporation” (“earnings”) and includes the effects of deferrals of salary and other compensation awards that are invested in Chevron stock units by certain officers and employees of the company. Diluted EPS includes the effects of these items as well as the dilutive effects of outstanding stock options awarded under the company’s stock option programs (refer to Note 22 Stock Options and Other Share-Based Compensation). The table below sets forth the computation of basic and diluted EPS:

Note 14

Operating Segments and Geographic Data

Although each subsidiary of Chevron is responsible for its own affairs, Chevron Corporation manages its investments in these subsidiaries and their affiliates. The investments are grouped intotwo business segments, Upstream and Downstream, representing the company’s “reportable segments” and “operating segments.” Upstream operations consist primarily of exploring for, developing, producing and transporting crude oil and natural gas; liquefaction, transportation and regasification associated with liquefied natural gas (LNG); transporting crude oil by major international oil export pipelines; processing, transporting, storage and marketing of natural gas; carbon capture and storage; and a gas-to-liquids plant. Downstream operations consist primarily of refining of crude oil into petroleum products; marketing of crude oil, refined products, and lubricants; manufacturing and marketing of renewable fuels; transporting of crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant additives. All Other activities of the company include worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology activities.

The company’s segments are managed by “segment managers” who report to the “chief operating decision maker” (CODM). The segments represent components of the company that engage in activities (a) from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the segments and assesses their performance; and (c) for which discrete financial information is available.

The company’s primary country of operation is the United States of America, its country of domicile. Other components of the company’s operations are reported as “International” (outside the United States).

Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Non-billable costs remain at the corporate level in “All Other.” Earnings by major operating area are presented in the following table:

Segment Assets Segment assets do not include intercompany investments or receivables. Assets at year-end 2023 and 2022 are as follows:

Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2023, 2022 and 2021, are presented in the table on the next page. Products are transferred between operating segments at internal product values that approximate market prices.

Revenues for the upstream segment are derived primarily from the production and sale of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the manufacture and sale of fuel and lubricant additives and the transportation and trading of refined products and crude oil. “All Other” activities include revenues from insurance operations, real estate activities and technology companies.

*Other than the United States, no other country accounted for 10 percent or more of the company’s Sales and Other Operating Revenues.

Segment Income Taxes Segment income tax expense for the years 2023, 2022 and 2021 is as follows:

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.

Note 15

Investments and Advances

Equity in earnings, together with investments in and advances to companies accounted for using the equity method and other investments accounted for at or below cost, is shown in the following table. For certain equity affiliates, Chevron pays its share of some income taxes directly. For such affiliates, the equity in earnings does not include these taxes, which are reported on the Consolidated Statement of Income as “Income tax expense.”

Descriptions of major equity affiliates and non-equity investments, including significant differences between the company’s carrying value of its investments and its underlying equity in the net assets of the affiliates, are as follows:

Tengizchevroil Chevron has a 50 percent equity ownership interest in Tengizchevroil (TCO), which operates the Tengiz and Korolev crude oil fields in Kazakhstan. At December 31, 2023, the company’s carrying value of its investment in TCO was about$80 higher than the amount of underlying equity in TCO’s net assets. This difference results from Chevron acquiringa portion of its interest in TCO at a value greater than the underlying book value for that portion of TCO’s net assets. Included in the investment is a loan to TCO to fund the development of the FGP/WPMP with a principal balance of $4,500.

Caspian Pipeline Consortium Chevron has a 15 percent interest in the Caspian Pipeline Consortium, which provides the critical export route for crude oil from both TCO and Karachaganak.

Angola LNG Limited Chevron has a 36.4 percent interest in Angola LNG Limited, which processes and liquefies natural gas produced in Angola for delivery to international markets.

Chevron Phillips Chemical Company LLC Chevron owns 50 percent of Chevron Phillips Chemical Company LLC. Included in the investment balance is a loan with a principal balance of$387 to fund a portion of the Golden Triangle Polymers Project in Orange, Texas, in which Chevron Phillips Chemical Company LLC owns 51 percent.

GS Caltex Corporation Chevron owns 50 percent of GS Caltex Corporation, a joint venture with GS Energy in South Korea. The joint venture imports, produces and markets petroleum products, petrochemicals and lubricants.

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $13,623, $16,286 and $10,796 with affiliated companies for 2023, 2022 and 2021, respectively. “Purchased crude oil and products” includes $7,404, $10,171 and $5,778 with affiliated companies for 2023, 2022 and 2021, respectively.

“Accounts and notes receivable” on the Consolidated Balance Sheet includes $1,480 and $907 due from affiliated companies at December 31, 2023 and 2022, respectively. “Accounts payable” includes $591 and $709 due toaffiliated companies at December 31, 2023 and 2022, respectively.

The following table provides summarized financial information on a 100 percent basis for all equity affiliates as well as Chevron’s total share, which includes Chevron’s net loans to affiliates of $4,494, $4,278 and $4,704 at December 31, 2023, 2022 and 2021, respectively.

• Chevron’s net income attributable to affiliates is recorded in the company’s before-tax consolidated earnings in accordance with U.S. Generally Accepted Accounting Principles. The total income tax expense recorded by the company’s equity affiliates in 2023 was $3,686, with Chevron’s share being $1,724.

Note 16

Litigation

Ecuador

In 2003, Chevron was sued in Ecuador for environmental harm allegedly caused by an oil consortium formerly operated by a Texaco subsidiary. The Ecuadorian trial court entered judgment against Chevron, and Ecuador’s highest Constitutional Court affirmed the judgment for approximately $9.5 billion. In 2017, Chevron obtained a final court ruling in the United States determining that the Ecuadorian judgment had been procured through fraud, bribery, and corruption, and prohibiting the Ecuadorian plaintiffs and their cohorts from seeking to enforce the Ecuadorian judgment in the United States or profiting from their illegal acts. The Ecuadorian plaintiffs sought to have the Ecuadorian judgment recognized and enforced in Canada, Brazil, and Argentina, but all of those actions were dismissed in Chevron’s favor.

In 2009, Chevron filed an arbitration claim against Ecuador before an arbitral tribunal administered by the Permanent Court of Arbitration in The Hague, under the United States-Ecuador Bilateral Investment Treaty. In 2018, the tribunal ruled in Chevron’s favor, finding that the Ecuadorian judgment was procured through fraud, bribery, and corruption and was based on environmental claims that Ecuador had already settled and released. The tribunal ruled that the Ecuadorian judgment “violates international public policy” and “should not be recognized or enforced by the courts of other States,” and ordered Ecuador to remove the judgment’s status of enforceability and to compensate Chevron for its injuries in an amount to be established separately by the tribunal. Ecuador’s requests to have a Dutch court set aside the tribunal’s award were denied, and the Dutch Supreme Court affirmed such denial in a final ruling in favor of Chevron in November 2023.

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 brought 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 29 separate lawsuits filed by various U.S. cities and counties, four U.S. states, the District of Columbia, two Native American tribes, and a trade group in both federal and state courts.1 One of the city lawsuits was dismissed on the merits andtwo suits, includingone of the county lawsuits and the case brought by the trade association, were voluntarily dismissed by the plaintiffs. The lawsuits have asserted various causes of action, including public nuisance, private nuisance, failure to warn, fraud, conspiracy to commit fraud, design defect, product defect, trespass, negligence, impairment of public trust, equitable relief for pollution, impairment and destruction of natural resources, unjust enrichment, violations of consumer protection statutes, violations of unfair competition statutes, violations of a federal antitrust statute, and violations of federal and state RICO statutes, based upon, among other things, the company’s production of oil and gas products and alleged misrepresentations or omissions relating to climate change risks associated with those products. Further such proceedings are likely to be brought by other parties. While defendants have sought to remove cases filed in state court to federal court, most of those cases have been remanded to state court and the U.S. Supreme Court has denied petitions for writ of certiorari on jurisdictional questions to date. The unprecedented legal theories set forth in these proceedings include claims for damages (both compensatory and punitive), injunctive and other forms of equitable relief, including without limitation abatement, contribution to abatement funds, disgorgement of profits and equitable relief for pollution, impairment and destruction of natural resources, civil penalties and liability for fees and costs of suits. Due to the unprecedented nature of the suits, the company is unable to estimate any range of possible liability, but given the uncertainty of litigation there can be no assurance that the cases will not have a material adverse effect on the company’s results of operations and financial condition. Management believes that these proceedings are legally and factually meritless and detract from constructive efforts to address the important policy issues presented by climate change and will vigorously defend against such proceedings.

1 The cases are: Bayamon v. Exxon Mobil Corp., et al., No. 22-cv-1550 (D.P.R.); City of Annapolis v. BP P.L.C., et al., No. C-02-CV-21-000250 (Md. Cir. Ct.); County of Anne Arundel v. BP P.L.C., et al., No. C-02-CV-21-000565 (Md. Cir. Ct.); Mayor and City Council of Baltimore v. BP P.L.C., et al., No. 24-C-18-004219 (Md. Cir. Ct.); People ex rel. Bonta v. Exxon Mobil Corp., et al., No. CGC-23-609134 (Cal. Super. Ct.); City of Charleston v. Brabham Oil Co., et al., No. 20-CP-10-3975 (S.C. Ct. of Common Pleas); District of Columbia v. Exxon Mobil Corp., et al., No. 2020-CA-002892-B (D.C. Super. Ct.); Delaware ex rel. Jennings v. BP America Inc., et al., No. N20C-09-097 (Del.Super. Ct.); City of Hoboken v. Exxon Mobil Corp., et al., No. HUD-L-003179-20 (N.J. Super. Ct.); City and County of Honolulu, et al. v. Sunoco LP, et al., No. 1CCV-20-0000380 (Haw. Cir. Ct.); City of Imperial Beach v. Chevron Corp., et al., No. C17-01227 (Cal. Super. Ct.); King County v. BP P.L.C., et al., No. 18-2-11859-0 (Wash. Super. Ct.) (voluntarily dismissed); Makah Indian Tribe v. Exxon Mobil Corp., et al., No. 23-25216-1-SEA (Wash. Super. Ct.); County of Marin v. Chevron Corp., et al., No. 17-cv-02586 (Cal. Super. Ct.); County of Maui v. Sunoco LP, et al., No. 2CCV-20-0000283 (Haw. Cir. Ct.); County of Multnomah v. Exxon Mobil Corp., et al., No. 23-cv-25164 (Or. Cir. Ct.); Municipality of San Juan, Puerto Rico v. Exxon Mobil Corp., et al., No. 23-cv-01608 (D.P.R.); City of Oakland v. BP p.l.c., et al., No. RG17875889 (Cal. Super. Ct.); Platkin, et al. v. Exxon Mobil Corp., et al., No. MER-L-001797-22 (N.J. Super. Ct.); City of New York v. Chevron Corp., et al., No. 18-cv-00182 (S.D.N.Y.) (dismissed on the merits); Pacific Coast Federation of Fishermen’s Associations v. Chevron Corp., et al., No. CGC-18-571285 (Cal. Super. Ct.) (voluntarily dismissed); State of Rhode Island v. Chevron Corp., et al., No. PC-2018-4716 (R.I. Super. Ct.); City of Richmond v. Chevron Corp., et al., No. C18-00055 (Cal. Super. Ct.); City of San Francisco v. BP P.L.C., et al., No. CGC-17-561370 (Cal. Super. Ct.); County of San Mateo v. Chevron Corp., et al., No. 17-CIV-03222 (Cal. Super. Ct.); City of Santa Cruz v. Chevron Corp., et al., No. 17-cv-03243 (Cal. Super. Ct.); County of Santa Cruz v. Chevron Corp., et al., No. 17-cv-03242 (Cal. Super. Ct.); Shoalwater Bay Indian Tribe v. Exxon Mobil Corp., et al., No. 23-2-25215-2-SEA (Wash. Super. Ct.); City of Chicago v. BP p.l.c., et al., No. 2024-CH-01024 (Ill. Cir. Ct.).

Louisiana

Seven coastal parishes and the State of Louisiana have filed lawsuits in Louisiana against numerous oil and gas companies seeking damages for coastal erosion in or near oil fields located within Louisiana’s coastal zone under Louisiana’s State and Local Coastal Resources Management Act (SLCRMA). Chevron entities are defendants in 39 of these cases.2 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. Further such proceedings may be filed by other parties. The Supreme Court denied a petition for writ of certiorari on jurisdictional questions impacting certain of these cases, and those cases have been or will be remanded to Louisiana state court. Federal jurisdictional questions are still being decided for the remaining cases in the United States Court of Appeals for the Fifth Circuit. A case has been set for trial in the United States District Court for the Eastern District of Louisiana and is scheduled to begin in October 2024. Due to the unprecedented nature of the suits, the company is unable to estimate any range of possible liability, but given the uncertainty of litigation there can be no assurance that the cases will not have a material adverse effect 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.

2 The cases are: Jefferson Parish v. Atlantic Richfield Company, et al., No. 732-768 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Chevron U.S.A. Holdings, Inc., et al., No. 732-769 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Destin Operating Company, Inc., et al., No. 732-770 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Canlan Oil Company, et al., No. 732-771 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Anadarko E&P Onshore LLC, et al., No. 732-772 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. ExxonMobil Corporation, et al., No. 732-774 (24th Jud. Dist. Ct., Jefferson Par.); Jefferson Parish v. Equitable Petroleum Corporation, et al., No. 732-775 (24th Jud. Dist. Ct., Jefferson Par.); Plaquemines Parish v. ConocoPhillips Co., et al., No. 60-982 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. HHE Energy Co., et al., No. 60-983 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Exchange Oil & Gas Corp., et al., No. 60-984 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. LLOG Exploration & Production Co., et al., No. 60-985 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Equitable Petroleum Corporation, et al., No. 60-986 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. June Energy, et al., No. 60-987 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Linder Oil Company, et al., No. 60-988 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Riverwood Production Company, et al., No. 60-989 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Helis Oil & Gas Company, et al., No. 60-990 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Northcoast Oil Company, et al., No. 60-992 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Goodrich Petroleum Company, L.L.C., et al., No. 60-994 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Devon Energy Production Company, L.P., et al., No. 60-995 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Rozel Operating Co., et al., No. 60-996 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Palm Energy Offshore, L.L.C., et al., No. 60-997 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Great Southern Oil & Gas Company, Inc., et al., No. 60-998 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Hilcorp Energy Company, et al., No. 60-999 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Apache Oil Corporation, et al., No. 61-000 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. Campbell Energy Corporation, et al., No. 61-001 (25th Jud. Dist. Ct., Plaquemines Par.); Plaquemines Parish v. TotalPetrochemicals & Refining USA, Inc., et al., No. 61-002 (25th Jud. Dist. Ct., Plaquemines Par.); Cameron Parish v. Alpine Exploration Companies, Inc., et al., No. 10-19580 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Anadarko E&P Onshore, LLC, et al., No. 10-19578 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Apache Corporation (of Delaware), et al., No. 10-19579 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Auster Oil & Gas, Inc., et al., No. 10-19582 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Ballard Exploration Company, Inc., et al., No. 10-19574 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Bay Coquille, Inc., et al., No. 10-19581 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. BEPCO, LP, et al., No. 10-19572 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. BP America Production Company, et al., No. 10-19576 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Brammer Engineering, Inc., et al., No. 10-19573 (38th Jud. Dist. Ct., Cameron Par.); Cameron Parish v. Burlington Resources, et al., No. 10-19575 (38th Jud. Dist. Ct., Cameron Par.); Stutes v. Gulfport Energy Corporation, et al., No. 102,146 (15th Jud. Dist. Ct., Vermilion Par.); St. Bernard Parish v. Atlantic Richfield, et al., No. 16-1228 (34th Jud. Dist. Ct. St., Bernard Par.); City of New Orleans v. Apache Louisiana Mins, LLC, et al., No. 19-cv-08290, (E.D. La.).

Note 17

Taxes

The reconciliation between the U.S. statutory federal income tax rate and the company’s effective income tax rate is detailed in the following table:

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 (2023 - $(84); 2022 - $(36); 2021 - $(624)).

3 The company’s effective tax rate is reflective of equity income reported on an after-tax basis as part of the “Total Income (Loss) Before Income Tax Expense,” in accordance with U.S. Generally Accepted Accounting Principles. Chevron’s share of its equity affiliates’ total income tax expense in 2023 was $1,724.

The 2023 decrease in income tax expense of $5,893 is a result of the year-over-year decrease in total income before income tax expense, which is primarily due to lower upstream realizations and downstream margins. The company’s effective tax rate changed from 28.3 percent in 2022 to 27.6 percent in 2023. The change in effective tax rate is mainly due to mix effects resulting from the absolute level of earnings or losses and whether they arose in higher or lower tax rate jurisdictions.

The company records its deferred taxes on a tax-jurisdiction basis. The reported deferred tax balances are composed of the following:

Deferred tax liabilities increased by $1,779 from year-end 2022, driven by an increase to properties, plant and equipment. Deferred tax assets increased by $628 from year-end 2022. This increase was primarily related to increases in foreign tax credits and other accrued liabilities, partially offset by decreases in tax loss carryforwards and employee benefits.

The overall valuation allowance relates to deferred tax assets for U.S. foreign tax credit carryforwards, tax loss carryforwards and temporary differences. The valuation allowance reduces the deferred tax assets to amounts that are, in management’s assessment, more likely than not to be realized. At the end of 2023, the company had gross tax loss carryforwards of approximately $9,600 and tax credit carryforwards of approximately $260, primarily related to various international tax jurisdictions. Whereas some of these tax loss carryforwards do not have an expiration date, others expire at various times from 2024 through 2042. U.S. foreign tax credit carryforwards of $13,560 will expire between 2024 and 2033.

At December 31, 2023 and 2022, deferred taxes were classified on the Consolidated Balance Sheet as follows:

Income taxes, including U.S. state and foreign withholding taxes, are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely, or where no taxable temporary differences exist that are attributable to unremitted earnings from an investment in a foreign entity. The indefinite reinvestment assertion continues to apply for the purpose of determining deferred tax liabilities for U.S. state and foreign withholding tax purposes. It is not practicable to estimate the amount of state and foreign withholding taxes that might be payable on the possible remittance of earnings that are intended to be reinvested indefinitely. The company does not anticipate incurring significant additional taxes on remittances of earnings that are not indefinitely reinvested.

Uncertain Income Tax Positions The company recognizes a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that the position is more likely than not (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in the accounting standards for income taxes refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods.

The following table indicates the changes to the company’s unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021. The term “unrecognized tax benefits” in the accounting standards for income taxes refers to the

differences between a tax position taken or expected to be taken in a tax return and the benefit measured and recognized in the financial statements. Interest and penalties are not included.

Approximately 79 percent of the $5,452 of unrecognized tax benefits at December 31, 2023, would have an impact on the effective tax rate if subsequently recognized. Certain of these unrecognized tax benefits relate to tax carryforwards that may require a full valuation allowance at the time of any such recognition.

The company and its subsidiaries are subject to income taxation and audits throughout the world. With certain exceptions, income tax examinations are completed through 2016 for the United States and 2007 for other major jurisdictions.

The company engages in ongoing discussions with tax authorities regarding the resolution of tax matters in the various jurisdictions. Both the outcome of these tax matters and the timing of resolution and/or closure of the tax audits are highly uncertain. 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 (Benefit).” As of December 31, 2023, accrued expense of $229 for anticipated interest and penalties was included on the Consolidated Balance Sheet, compared with accrued benefit of $112 as of year-end 2022. Income tax expense (benefit) associated with interest and penalties was $124, $152 and $19 in 2023, 2022 and 2021, respectively.

Note 18

Properties, Plant and Equipment 1

1 Other than the United States and Australia, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2023. Australia had PP&E of $41,409, $44,012 and $46,687 in 2023, 2022 and 2021, respectively. Gross Investment at Cost and Additions at Cost for 2023 each include $10,487 associated with the PDC acquisition.

2 Net of dry hole expense related to prior years’ expenditures of $110, $177 and $35 in 2023, 2022 and 2021, respectively.

3 Depreciation expense includes accretion expense of $593, $560 and $616 in 2023, 2022 and 2021, respectively, and impairments and write-offs of$2,180,$950 and $414 in 2023, 2022 and 2021, respectively.

Note 19

Short-Term Debt

Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date.

The company may periodically enter into interest rate swaps on a portion of its short-term debt. At December 31, 2023, the company had no interest rate swaps on short-term debt.

At December 31, 2023, the company had $8,050 in 364-day committed credit facilities with various major banks that enable the refinancing of short-term obligations on a long-term basis. The credit facilities allow the company to convert any amounts outstanding into a term loan for a period of up to one year. This supports commercial paper borrowing and can also be used for general corporate purposes. The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facility would be unsecured indebtedness at interest rates based on the Secured Overnight Financing Rate (SOFR), or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under this facility at December 31, 2023.

The company classified $4,543 and $4,050 of short-term debt as long-term at December 31, 2023 and 2022, respectively. Settlement of these obligations is not expected to require the use of working capital within one year, and the company has both the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

Note 20

Long-Term Debt

Total long-term debt including finance lease liabilities at December 31, 2023, was $20,307. The company’s long-term debt outstanding at year-end 2023 and 2022 was as follows:

Long-term debt excluding finance lease liabilities with a principal balance of $16,281 matures as follows: 2024 – $1,650; 2025 – $4,000; 2026 – $2,250; 2027 – $2,000; 2028 – $600; and after 2028 – $5,781.

During the third quarter of 2023, the company assumed $1.5 billion of debt in conjunction with the PDC acquisition, including balances outstanding under the revolving credit facility, PDC’s 6.125% notes due 2024 (2024 notes) and PDC’s 5.75% notes due 2026 (2026 notes). The outstanding balances under the revolving credit facility and the 2024 notes were repaid during third quarter 2023. The company also irrevocably deposited sufficient U.S. Treasury securities with U.S. Bank Trust Company, N.A., as trustee, to fund the redemption of the 2026 notes, resulting in the indenture being satisfied and discharged.

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

Note 21

Accounting for Suspended Exploratory Wells

The company continues to capitalize exploratory well costs after the completion of drilling when the well has found a sufficient quantity of reserves to justify completion as a producing well, and the business unit is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met or if the company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense.

The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended December 31, 2023:

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:

*Certain projects have multiple wells or fields or both.

Of the $1,570 of exploratory well costs capitalized for more than one year at December 31, 2023, $844 is related toseven projects that had drilling activities underway or firmly planned for the near future. The $726 balance is related tosix 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 $726 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability: (a) $311 (four projects) – undergoing front-end engineering and design with final investment decision expected within four years; (b) $415 (two projects) – development alternatives under review. While progress was being made on all 13 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. Approximately three-quarters of these decisions are expected to occur in the next five years.

The $1,570 of suspended well costs capitalized for a period greater than one year as of December 31, 2023, represents 71 exploratory wells in 13 projects. The tables below contain the aging of these costs on a well and project basis:

Note 22

Stock Options and Other Share-Based Compensation

Compensation expense for stock options for 2023, 2022 and 2021 was $85 ($65 after tax), $60 ($46 after tax) and $60 ($47 after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance shares and restricted stock units resulted in a net benefit of $(100) ($(76) after tax) for 2023, primarily as a result of reductions in the fair value of outstanding liability-classified performance shares that are remeasured each reporting period. Compensation expense for stock appreciation rights, restricted stock, performance shares and restricted stock units was $1,013 ($770 after tax) and $701 ($554 after tax) for 2022 and 2021, respectively. No significant stock-based compensation cost was capitalized at December 31, 2023, or December 31, 2022.

Cash received in payment for option exercises under all share-based payment arrangements for 2023, 2022 and 2021 was $263, $5,835 and $1,274, respectively. Actual tax benefits realized for the tax deductions from option exercises were $20, $216 and $(15) for 2023, 2022 and 2021, respectively.

Cash paid to settle performance shares, restricted stock units and stock appreciation rights was $566, $556 and $163 for 2023, 2022 and 2021, respectively.

On May 25, 2022, stockholders approved the Chevron 2022 Long-Term Incentive Plan (2022 LTIP). Awards under the 2022 LTIP may take the form of, but are not limited to, stock options, restricted stock, restricted stock units, stock appreciation rights, performance shares and non-stock grants. From May 2022 through May 2032, no more than 104 million shares may be issued under the 2022 LTIP. For awards issued on or after May 25, 2022, no more than 48 million of those shares may be issued in the form of full value awards such as share-settled restricted stock, share-settled restricted stock units and other share-settled awards that do not require full payment in cash or property for shares underlying such awards by the award recipient. For the major types of awards issued before January 1, 2017, the contractual terms vary between three years for the performance shares and restricted stock units, and 10 years for the stock options and stock appreciation rights. For awards issued after January 1, 2017, contractual terms vary between three years for the performance shares and special restricted stock units, five years for standard restricted stock units and 10 years for the stock options and stock appreciation rights. Commencing for grants issued in January 2023 and after, standard restricted stock units vest ratably on an annual basis over athree-year period. Forfeitures of performance shares, restricted stock units, and stock appreciation rights are recognized as they occur. Forfeitures of stock options are estimated using historical forfeiture data dating back to 1990.

Fair Value and Assumptions The fair market values of stock options and stock appreciation rights granted in 2023, 2022 and 2021 were measured on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions:

1 Expected term is based on historical exercise and post-vesting cancellation data.

2 Volatility rate is based on historical stock prices over an appropriate period, generally equal to the expected term.

A summary of option activity during 2023 is presented below:

The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2023, 2022 and 2021 was $167, $2,369 and $152, respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.

As of December 31, 2023, there was $181 of total unrecognized before-tax compensation cost related to nonvested share-based compensation arrangements granted under the plan. That cost is expected to be recognized over a weighted-average period of 1.9 years.

At January 1, 2023, the number of LTIP performance shares outstanding was equivalent to 4,753,266 shares. During 2023,1,291,262 performance shares were granted,1,521,636 shares vested with cash proceeds distributed to recipients and 103,582 shares were forfeited. At December 31, 2023, there were 4,419,310 performance shares outstanding that are payable in cash. The fair value of the liability recorded for these instruments was $360 and was measured largely using the Monte Carlo simulation method.

At January 1, 2023, the number of restricted stock units outstanding was equivalent to 4,287,826 shares. During 2023,1,739,120 restricted stock units were granted,866,494 units vested with cash proceeds distributed to recipients and 100,210 units were forfeited. At December 31, 2023, there were 5,060,242 restricted stock units outstanding, of which 3,905,243 are payable in cash and 1,154,999 are payable in shares. The fair value of the liability recorded for the vested portion of these instruments payable in cash was $457, valued at the stock price as of December 31, 2023. In addition, outstanding stock appreciation rights that were granted under the LTIP totaled 652,493 equivalent shares as of December 31, 2023. The fair value of the liability recorded for the vested portion of these instruments was $32.

Note 23

Employee Benefit Plans

The company has defined benefit pension plans for many employees. The company typically prefunds defined benefit plans as required by local regulations or in certain situations where prefunding provides economic advantages. In the United States, all qualified plans are subject to the Employee Retirement Income Security Act (ERISA) minimum funding standard. The company does not typically fund U.S. nonqualified pension plans that are not subject to funding requirements under laws and regulations because contributions to these pension plans may be less economic and investment returns may be less attractive than the company’s other investment alternatives.

The company also sponsors other postretirement benefit (OPEB) plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees. The plans are unfunded, and the company and retirees share the costs. For the company’s main U.S. medical plan, the increase to the pre-Medicare company contribution for retiree medical coverage is limited to no more than 4 percent each year. Certain life insurance benefits are paid by the company.

The company recognizes the overfunded or underfunded status of each of its defined benefit pension and OPEB plans as an asset or liability on the Consolidated Balance Sheet.

The funded status of the company’s pension and OPEB plans for 2023 and 2022 follows:

Amounts recognized on the Consolidated Balance Sheet for the company’s pension and OPEB plans at December 31, 2023 and 2022, include:

For the year ended December 31, 2023, 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, 2022, the decrease in benefit obligations was primarily due to actuarial gains caused by higher discount rates used to value the obligations and benefit payments paid to retirees in 2022.

Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $3,792 and $3,446 at the end of 2023 and 2022, respectively. These amounts consisted of:

The accumulated benefit obligations for all U.S. and international pension plans were $9,284 and $3,378, respectively, at December 31, 2023, and $8,595 and $3,084, respectively, at December 31, 2022.

Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2023 and 2022, was:

The components of net periodic benefit cost and amounts recognized in the Consolidated Statement of Comprehensive Income for 2023, 2022 and 2021 are shown in the table below:

Assumptions The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31:

Expected Return on Plan Assets The company’s estimated long-term rates of return on pension assets are driven primarily by actual historical asset-class returns, an assessment of expected future performance, advice from external actuarial firms and the incorporation of specific asset-class risk factors. Asset allocations are periodically updated using pension plan asset/liability studies, and the company’s estimated long-term rates of return are consistent with these studies. For 2023, the company used an expected long-term rate of return of 7.0 percent for U.S. pension plan assets, which account for 71 percent of the company’s pension plan assets at the beginning of the year.

The market-related value of assets of the main U.S. pension plan used in the determination of pension expense was based on the market values in thethree months preceding the year-end measurement date. Management considers thethree-month time period long enough to minimize the effects of distortions from day-to-day market volatility and still be contemporaneous to the end of the year. For other plans, market value of assets as of year-end is used in calculating the pension expense.

Discount Rate The discount rate assumptions used to determine the U.S. and international pension and OPEB plan obligations and expense reflect the rate at which benefits could be effectively settled, and are equal to the equivalent single rate resulting from yield curve analysis. This analysis considered the projected benefit payments specific to the company’s plans and the yields on high-quality bonds. The projected cash flows were discounted to the valuation date using the yield curve for the main U.S. pension and OPEB plans. The effective discount rates derived from this analysis were 5.0 percent,5.2 percent, and 2.8 percent for 2023, 2022, and 2021, 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, 2023, for the main U.S. OPEB plan, the assumed health care cost-trend rates start with 8.4 percent in 2024 and gradually decline to 4.5 percent for 2033 and beyond. For this measurement at December 31, 2022, the assumed health care cost-trend rates started with 6.6 percent in 2023 and gradually declined to 4.5 percent for 2032 and beyond.

Plan Assets and Investment Strategy

The fair value measurements of the company’s pension plans for 2023 and 2022 are as follows:

1 There wereno investments in the company’s common stock at December 31, 2023 or December 31, 2022.

2 Collective Trusts/Mutual Funds for U.S. plans are entirely index funds; for International plans, they are mostly unit trust and index funds.

3 Mixed funds are composed of funds that invest in both equity and fixed-income instruments in order to diversify and lower risk.

4 The year-end valuations of the U.S. real estate assets are based on third-party appraisals that occur at least once a year for each property in the portfolio.

5 The “Other” asset class includes net payables for securities purchased but not yet settled (Level 1); dividends and interest- and tax-related receivables (Level 2); insurance contracts (Level 3); and investments in private-equity limited partnerships (NAV).

The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below:

The primary investment objectives of the pension plans are to achieve the highest rate of total return within prudent levels of risk and liquidity, to diversify and mitigate potential downside risk associated with the investments, and to provide adequate liquidity for benefit payments and portfolio management.

The company’s U.S. and U.K. pension plans comprise 95 percent of the total pension assets. Both the U.S. and U.K. plans have an Investment Committee that regularly meets during the year to review the asset holdings and their returns. To assess the plans’ investment performance, long-term asset allocation policy benchmarks have been established.

For the primary U.S. pension plan, the company’s Investment Committee has established the following approved asset allocation ranges: Equities 35–65 percent, Fixed Income 25–45 percent, Real Estate 5–25 percent, Alternative Investments 0–5 percent and Cash 0–15 percent. For the U.K. pension plan, the U.K. Board of Trustees has established the following asset allocation guidelines: Equities 5–15 percent, Fixed Income 63–93 percent, Real Estate 5–15 percent, and Cash 0–7 percent. The other significant international pension plans also have established maximum and minimum asset allocation ranges that vary by plan. Actual asset allocation within approved ranges is based on a variety of factors, including market conditions and liquidity constraints. To mitigate concentration and other risks, assets are invested across multiple asset classes with active investment managers and passive index funds.

The company does not prefund its OPEB obligations.

Cash Contributions and Benefit Payments In 2023, the company contributed $1,020 and $100 to its U.S. and international pension plans, respectively. In 2024, the company expects contributions to be approximately $750 to its U.S. plans and $100 to its international pension plans. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments, tax law changes and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.

The company anticipates paying OPEB benefits of approximately $150 in 2024; $159 was paid in 2023.

The following benefit payments, which include estimated future service, are expected to be paid by the company in the next 10 years:

Employee Savings Investment Plan Eligible employees of Chevron and certain of its subsidiaries participate in the Chevron Employee Savings Investment Plan (ESIP). Compensation expense for the ESIP totaled $320, $283 and $252 in 2023, 2022 and 2021, respectively.

Benefit Plan Trusts Prior to its acquisition by Chevron, Texaco established a benefit plan trust for funding obligations under some of its benefit plans. At year-end 2023, the trust contained 14.2 million shares of Chevron treasury stock. The trust will sell the shares or use the dividends from the shares to pay benefits only to the extent that the company does not pay such benefits. The company intends to continue to pay its obligations under the benefit plans. The trustee will vote the shares held in the trust as instructed by the trust’s beneficiaries. The shares held in the trust are not considered outstanding for earnings-per-share purposes until distributed or sold by the trust in payment of benefit obligations.

Employee Incentive Plans The Chevron Incentive Plan is an annual cash bonus plan for eligible employees that links awards to corporate and individual performance in the prior year. Charges to expense for cash bonuses were $809, $1,169 and $1,165 in 2023, 2022 and 2021, respectively. Chevron also has the LTIP for officers and other regular salaried employees of the company and its subsidiaries who hold positions of significant responsibility. Awards under the LTIP consist of stock options and other share-based compensation that are described in Note 22 Stock Options and Other Share-Based Compensation.

Note 24

Other Contingencies and Commitments

Income Taxes The company calculates its income tax expense and liabilities quarterly. These liabilities generally are subject to audit and are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been calculated. Refer to Note 17 Taxes for a discussion of the periods for which tax returns have been audited for the company’s major tax jurisdictions and a discussion for all tax jurisdictions of the differences between the amount of tax benefits recognized in the financial statements and the amount taken or expected to be taken in a tax return.

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

Guarantees The company hasone guarantee to an equity affiliate totaling $135. This guarantee is associated with certain payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 4-year remaining term of this guarantee, the maximum guarantee amount will be reduced as certain fees are paid by the affiliate. There are numerous cross-indemnity agreements with the affiliate and the other partners to permit recovery of amounts paid under the guarantee. Chevron has recorded no liability for this guarantee.

Indemnifications The company often includes standard indemnification provisions in its arrangements with its partners, suppliers and vendors in the ordinary course of business, the terms of which range in duration and sometimes are not limited. The company may be obligated to indemnify such parties for losses or claims suffered or incurred in connection with its service or other claims made against such parties.

Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain contingent liabilities with respect to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which may relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate amounts of required payments under throughput and take-or-pay agreements are: 2024 – $909; 2025 – $1,086; 2026 – $1,141; 2027 – $1,193; 2028 – $1,183; after 2028 – $7,553. The aggregate amount of required payments for other unconditional purchase obligations are: 2024 – $589; 2025 – $451; 2026 – $484; 2027 – $604; 2028 – $273; after 2028 – $1,078. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were $1,420 in 2023, $1,866 in 2022 and $861 in 2021.

Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances by the company or other parties. Such contingencies may exist for various operating, closed and divested sites, including, but not limited to, U.S. federal Superfund sites and analogous sites under state laws, refineries, chemical plants, marketing facilities, crude oil fields, and mining sites.

Although the company has provided for known environmental obligations that are probable and reasonably estimable, it is likely that the company will continue to incur additional liabilities. The amount of additional future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. These future costs may be material to results of operations in the period in which they are recognized, but the company does not expect these costs will have a material effect on its consolidated financial position or liquidity.

Chevron’senvironmental reserve as of December 31, 2023, was $936. Included in this balance was $232 related to remediation activities at sites for which the company had been identified as a potentially responsible party under the provisions of the U.S. federal Superfund law 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 2023 environmental reserves balance of $704, $389 is related to the company’s U.S. downstream operations, $55 to its international downstream operations, and $260 to its upstream operations. Liabilities at all sites were primarily associated with the company’s plans and activities to remediate soil or groundwater contamination or both.

The company manages environmental liabilities under specific sets of regulatory requirements, which in the United States include the Resource Conservation and Recovery Act and various state and local regulations. No single remediation site at year-end 2023 had a recorded liability that was material to the company’s results of operations, consolidated financial position or liquidity.

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

Other Contingencies Chevron receives claims from and submits claims to customers; trading partners; joint venture partners; U.S. federal, state and local regulatory bodies; governments; contractors; insurers; suppliers; and individuals. The amounts of these claims, individually and in the aggregate, may be significant and take lengthy periods to resolve, and may result in gains or losses in future periods.

The company and its affiliates also continue to review and analyze their operations and may close, retire, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve competitiveness and profitability. These activities, individually or together, may result in significant gains or losses in future periods.

In addition, some assets are sold along with their related liabilities and in certain instances, such transferred obligations have reverted and may in the future revert to the company and result in losses that could be significant. In fourth quarter 2023, the company recognized an after-tax loss of $1,950 related to abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S. Gulf of Mexico, as companies that purchased these assets have filed for protection under Chapter 11 of the U.S. Bankruptcy Code, and we believe it is now probable and estimable that a portion of these obligations will revert to the company.

Note 25

Asset Retirement Obligations

The company records the fair value of a liability for an asset retirement obligation (ARO) both as an asset and a liability when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. The legal obligation to perform the asset retirement activity is unconditional, even though uncertainty may exist about the timing and/or method of settlement that may be beyond the company’s control. This uncertainty about the timing and/or method of settlement is factored into the measurement of the liability when sufficient information exists to reasonably estimate fair value. Recognition of the ARO includes: (1) the present value of a liability and offsetting asset, (2) the subsequent accretion of that liability and depreciation of the asset, and (3) the periodic review of the ARO liability estimates and discount rates.

AROs are primarily recorded for the company’s crude oil and natural gas producing assets. No significant AROs associated with any legal obligations to retire downstream long-lived assets have been recognized, as indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the associated ARO. The company performs periodic

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

The following table indicates the changes to the company’s before-tax asset retirement obligations in 2023, 2022 and 2021:

In the table above, the amount associated with “Revisions in estimated cash flows” primarily reflects increased cost estimates and scope changes to decommission wells, equipment and facilities. The long-term portion of the $13,833 balance at the end of 2023 was $12,122.

Note 26

Revenue

Revenue from contracts with customers is presented in “Sales and other operating revenues” along with some activity that is accounted for outside the scope of Accounting Standard Codification (ASC) 606, which is not material to this line, on the Consolidated Statement of Income. Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another (including buy/sell arrangements) are combined and recorded on a net basis and reported in “Purchased crude oil and products” on the Consolidated Statement of Income. Refer to Note 14 Operating Segments and Geographic Data for additional information on the company’s segmentation of revenue.

Receivables related to revenue from contracts with customers are included in “Accounts and notes receivable” on the Consolidated Balance Sheet, net of the allowance for doubtful accounts. The net balance of these receivables was $13,641 and $14,219 at December 31, 2023 and 2022, respectively. Other items included in “Accounts and notes receivable” represent amounts due from partners for their share of joint venture operating and project costs and amounts due from others, primarily related to derivatives, leases, buy/sell arrangements and product exchanges, which are accounted for outside the scope of ASC 606.

Contract assets and related costs are reflected in “Prepaid expenses and other current assets” and contract liabilities are reflected in “Accrued liabilities” and “Deferred credits and other noncurrent obligations” on the Consolidated Balance Sheet. Amounts for these items are not material to the company’s financial position.

Note 27

Other Financial Information

Earnings in 2023 included after-tax gains of approximately $143 relating to the sale of certain properties. Of this amount, approximately $33 and $110 related to downstream and upstream, respectively. Earnings in 2022 included after-tax gains of approximately $390 relating to the sale of certain properties, of which approximately $90 and $300 related to downstream and upstream assets, respectively. Earnings in 2021 included after-tax gains of approximately $785 relating to the sale of certain properties, of which approximately $30 and $755 related to downstream and upstream assets, respectively.

Earnings in 2023 included after-tax charges of approximately $1,950 for abandonment and decommissioning obligations from previously sold oil and gas production assets in the U.S. Gulf of Mexico and $1,765 for upstream impairments, mainly in California, and several tax items with a net benefit of $655. Earnings in 2022 included after-tax charges of approximately $1,075 for impairments and other asset write-offs related to upstream, $600 for an early contract termination in upstream, and $271 for pension settlement costs. Earnings in 2021 included after-tax charges of approximately $519 for pension settlement costs, $260 for early retirement of debt, $120 relating to upstream remediation and $110 relating to downstream legal reserves.

*Includes $(11), $253 and $180 in 2023, 2022 and 2021, respectively, for the company’s share of equity affiliates’ foreign currency effects.

The company has $4,722 in goodwill on the Consolidated Balance Sheet, of which $4,370 is in the upstream segment primarily related to the 2005 acquisition of Unocal and $352 is in the downstream segment. The company tested this goodwill for impairment during 2023, andno impairment was required.

Note 28

Financial Instruments - Credit Losses

Chevron’s expected credit loss allowance balance was $641 and $1,009 at December 31, 2023 and December 31, 2022, respectively, 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 $17,640 at December 31, 2023, which reflects the company’s diversified sources of revenues and is dispersed across the company’s broad worldwide customer base. As a result, the company believes the concentration of credit risk is limited. The company routinely assesses the financial strength of its customers. When the financial strength of a customer is not considered sufficient, alternative risk mitigation measures may be deployed, including requiring prepayments, letters of credit or other acceptable forms of collateral. Once credit is extended and a receivable balance exists, the company applies a quantitative calculation to current trade receivable balances that reflects credit risk predictive analysis, including probability of default and loss given default, which takes into consideration current and forward-looking market data as well as the company’s historical loss data. This statistical approach becomes the basis of the company’s expected credit loss allowance for current trade receivables with payment terms that are typically short-term in nature, with most due in less than 90 days.

Chevron’s non-trade receivable balance was $3,864 at December 31, 2023, which includes receivables from certain governments in their capacity as joint venture partners. Joint venture partner balances that are paid as per contract terms or not yet due are subject to the statistical analysis described above while past due balances are subject to additional qualitative management quarterly review. This management review includes review of reasonable and supportable repayment forecasts. Non-trade receivables also include employee and tax receivables that are deemed immaterial and low risk. Loans to equity affiliates and non-equity investees are also considered non-trade and associated allowances of $219 and $560 at December 31, 2023 and December 31, 2022, respectively, are included within “Investments and advances” on the Consolidated Balance Sheet.