Item 8. Financial Statements and Supplementary Data

ConocoPhillips

Index to Financial Statements
			Page
Reports of Management			71
Reports of Independent Registered Public Accounting Firm (PCAOB ID #42)			72
Consolidated Income Statement for the years ended December 31, 2023, 2022 and 2021			75
Consolidated Statement of Comprehensive Income for the years ended December 31, 2023, 2022 and 2021			76
Consolidated Balance Sheet at December 31, 2023 and 2022			77
Consolidated Statement of Cash Flows for the years ended December 31, 2023, 2022 and 2021			78
Consolidated Statement of Changes in Equity for the years ended December 31, 2023, 2022 and 2021			79
Notes to Consolidated Financial Statements			80
Supplementary Information
Oil and Gas Operations			135

ConocoPhillips 2023 10-K			70

			Table of Contents

Reports of Management

Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the company’s financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the company includes amounts that are based on estimates and judgments management believes are reasonable under the circumstances. The company’s financial statements have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed by the Audit and Finance Committee of the Board of Directors and ratified by stockholders. Management has made available to Ernst & Young LLP all of the company’s financial records and related data, as well as the minutes of stockholders’ and directors’ meetings.

Assessment of Internal Control Over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. ConocoPhillips’ internal control system was designed to provide reasonable assurance to the company’s management and directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2023. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework (2013). Based on our assessment, we believe the company’s internal control over financial reporting was effective as of December 31, 2023.

Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2023, and their report is included herein.

/s/ Ryan M. Lance			/s/ William L. Bullock, Jr.
Ryan M. Lance			William L. Bullock, Jr.
Chairman and Chief Executive Officer			Executive Vice President and Chief Financial Officer

71			ConocoPhillips 2023 10-K

			Table of Contents

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of ConocoPhillips

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of ConocoPhillips (the Company) as of December 31, 2023 and 2022, the related consolidated income statement, statements of comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 15, 2024 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the Audit and Finance Committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosure to which it relates.

ConocoPhillips 2023 10-K			72

			Table of Contents

			Depreciation, depletion and amortization of proved oil and gas properties, plants and equipment
Description of the Matter			At December 31, 2023, the net book value of the Company’s proved oil and gas properties, plants and equipment (PP&E) was $62 billion, and depreciation, depletion and amortization (DD&A) expense was $8.1 billion for the year then ended. As described in Note 1, under the successful efforts method of accounting, DD&A of PP&E on producing hydrocarbon properties and steam-assisted gravity drainage facilities and certain pipeline and liquified natural gas assets (those which are expected to have a declining utilization pattern) are determined by the unit-of-production method. The unit-of-production method uses proved oil and gas reserves, as estimated by the Company’s internal reservoir engineers. Proved oil and gas reserves estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan, historical extraction recovery and processing yield factors, installed plant operating capacity and approved operating limits. Significant judgment is required by the Company’s internal reservoir engineers in evaluating the data used to estimate proved oil and gas reserves. Estimating proved oil and gas reserves also requires the selection of inputs, including historical production, oil and gas price assumptions and future operating and capital costs assumptions, among others. Auditing the Company’s DD&A calculation is complex because of the use of the work of the internal reservoir engineers and the evaluation of management’s determination of the inputs described above used by the internal reservoir engineers in estimating proved oil and gas reserves.
How We Addressed the Matter in Our Audit			We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s internal controls over its processes to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the internal reservoir engineers for use in estimating proved oil and gas reserves. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company’s internal reservoir engineers primarily responsible for overseeing the preparation of the proved oil and gas reserves estimates. In addition, in assessing whether we can use the work of the internal reservoir engineers, we evaluated the completeness and accuracy of the financial data and inputs described above used by the internal reservoir engineers in estimating proved oil and gas reserves by agreeing them to source documentation and we identified and evaluated corroborative and contrary evidence. We also tested the accuracy of the DD&A calculation, including comparing the proved oil and gas reserves amounts used in the calculation to the Company’s reserve report.

We have served as the Company's auditor since 1949.

/s/ Ernst & Young LLP

Houston, Texas

February 15, 2024

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			Table of Contents

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of ConocoPhillips

Opinion on Internal Control over Financial Reporting

We have audited ConocoPhillips’ internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, ConocoPhillips (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2023 and 2022, the related consolidated income statement, statements of comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2023, and the related notes and our report dated February 15, 2024 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included under the heading “Assessment of Internal Control Over Financial Reporting” in the accompanying “Reports of Management.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Houston, Texas

February 15, 2024

ConocoPhillips 2023 10-K			74

Financial Statements			Table of Contents

Consolidated Income Statement			ConocoPhillips

Years Ended December 31			Millions of Dollars
			2023			2022			2021
Revenues and Other Income
Sales and other operating revenues			$	56,141		78,494			45,828
Equity in earnings of affiliates			1,720			2,081			832
Gain (loss) on dispositions			228			1,077			486
Other income			485			504			1,203
Total Revenues and Other Income			58,574			82,156			48,349
Costs and Expenses
Purchased commodities			21,975			33,971			18,158
Production and operating expenses			7,693			7,006			5,694
Selling, general and administrative expenses			705			623			719
Exploration expenses			398			564			344
Depreciation, depletion and amortization			8,270			7,504			7,208
Impairments			14			(12)			674
Taxes other than income taxes			2,074			3,364			1,634
Accretion on discounted liabilities			283			250			242
Interest and debt expense			780			805			884
Foreign currency transaction (gain) loss			92			(100)			(22)
Other expenses			2			(47)			102
Total Costs and Expenses			42,286			53,928			35,637
Income (loss) before income taxes			16,288			28,228			12,712
Income tax provision (benefit)			5,331			9,548			4,633
Net Income (Loss)			$	10,957		18,680			8,079
Net Income (Loss) Per Share of Common Stock (dollars)
Basic			$	9.08		14.62			6.09
Diluted			9.06			14.57			6.07
Average Common Shares Outstanding (in thousands)
Basic			1,202,757			1,274,028			1,324,194
Diluted			1,205,675			1,278,163			1,328,151

See Notes to Consolidated Financial Statements.

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Financial Statements			Table of Contents

Consolidated Statement of Comprehensive Income			ConocoPhillips

Years Ended December 31			Millions of Dollars
			2023			2022			2021
Net Income (Loss)			$	10,957		18,680			8,079
Other comprehensive income (loss)
Defined benefit plans
Prior service credit (cost) arising during the period			—			(10)			—
Reclassification adjustment for amortization of prior service cost (credit) included in net income (loss)			(38)			(39)			(38)
Net change			(38)			(49)			(38)
Net actuarial gain (loss) arising during the period			37			(623)			357
Reclassification adjustment for amortization of net actuarial losses (gains) included in net income (loss)			82			72			178
Net change			119			(551)			535
Nonsponsored plans*			(3)			5			5
Income taxes on defined benefit plans			(23)			178			(108)
Defined benefit plans, net of tax			55			(417)			394
Unrealized holding gain (loss) on securities			20			(13)			(2)
Reclassification adjustment for (gain) loss included in net income			(4)			(1)			(1)
Income taxes on unrealized holding gain (loss) on securities			(3)			3			1
Unrealized holding gain (loss) on securities, net of tax			13			(11)			(2)
Foreign currency translation adjustments			195			(623)			(124)
Income taxes on foreign currency translation adjustments			2			1			—
Foreign currency translation adjustments, net of tax			197			(622)			(124)
Unrealized gain (loss) on hedging activities			78			—			—
Income taxes on unrealized gain (loss) on hedging activities			(16)			—			—
Unrealized gain (loss) on hedging activities, net of tax			62			—			—
Other Comprehensive Income (Loss), Net of Tax			327			(1,050)			268
Comprehensive Income (Loss)			$	11,284		17,630			8,347

***Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates.

See Notes to Consolidated Financial Statements.

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Financial Statements			Table of Contents

Consolidated Balance Sheet			ConocoPhillips

At December 31			Millions of Dollars
			2023			2022
Assets
Cash and cash equivalents			$	5,635		6,458
Short-term investments			971			2,785
Accounts and notes receivable (net of allowance of $3 and $2, respectively)			5,461			7,075
Accounts and notes receivable—related parties			13			13
Inventories			1,398			1,219
Prepaid expenses and other current assets			852			1,199
Total Current Assets			14,330			18,749
Investments and long-term receivables			9,130			8,225
Net properties, plants and equipment (net of accumulated DD&A of $74,361 and $66,630, respectively)			70,044			64,866
Other assets			2,420			1,989
Total Assets			$	95,924		93,829
Liabilities
Accounts payable			$	5,083		6,113
Accounts payable—related parties			34			50
Short-term debt			1,074			417
Accrued income and other taxes			1,811			3,193
Employee benefit obligations			774			728
Other accruals			1,229			2,346
Total Current Liabilities			10,005			12,847
Long-term debt			17,863			16,226
Asset retirement obligations and accrued environmental costs			7,220			6,401
Deferred income taxes			8,813			7,726
Employee benefit obligations			1,009			1,074
Other liabilities and deferred credits			1,735			1,552
Total Liabilities			46,645			45,826
Equity
Common stock (2,500,000,000 shares authorized at $0.01 par value) Issued (2023—2,103,772,516 shares; 2022—2,100,885,134 shares)
Par value			21			21
Capital in excess of par			61,303			61,142
Treasury stock (at cost: 2023—925,670,961 shares; 2022—877,029,062 shares)			(65,640)			(60,189)
Accumulated other comprehensive income (loss)			(5,673)			(6,000)
Retained earnings			59,268			53,029
Total Equity			49,279			48,003
Total Liabilities and Equity			$	95,924		93,829

See Notes to Consolidated Financial Statements.

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Financial Statements			Table of Contents

Consolidated Statement of Cash Flows			ConocoPhillips

Years Ended December 31			Millions of Dollars
			2023			2022			2021
Cash Flows From Operating Activities
Net income (loss)			$	10,957		18,680			8,079
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization			8,270			7,504			7,208
Impairments			14			(12)			674
Dry hole costs and leasehold impairments			162			340			44
Accretion on discounted liabilities			283			250			242
Deferred taxes			1,145			2,086			1,346
Distributions more (less) than income from equity affiliates			964			942			446
(Gain) loss on dispositions			(228)			(1,077)			(486)
(Gain) loss on investment in Cenovus Energy			—			(251)			(1,040)
Other			(220)			86			(788)
Working capital adjustments
Decrease (increase) in accounts and notes receivable			1,333			(963)			(2,500)
Decrease (increase) in inventories			(103)			(38)			(160)
Decrease (increase) in prepaid expenses and other current assets			337			(173)			(649)
Increase (decrease) in accounts payable			(1,118)			901			1,399
Increase (decrease) in taxes and other accruals			(1,831)			39			3,181
Net Cash Provided by Operating Activities			19,965			28,314			16,996
Cash Flows From Investing Activities
Capital expenditures and investments			(11,248)			(10,159)			(5,324)
Working capital changes associated with investing activities			30			520			134
Acquisition of businesses, net of cash acquired			(2,724)			(60)			(8,290)
Proceeds from asset dispositions			632			3,471			1,653
Net sales (purchases) of investments			1,373			(2,629)			3,091
Collection of advances/loans—related parties			—			114			105
Other			(63)			2			87
Net Cash Used in Investing Activities			(12,000)			(8,741)			(8,544)
Cash Flows From Financing Activities
Issuance of debt			3,787			2,897			—
Repayment of debt			(1,379)			(6,267)			(505)
Issuance of company common stock			(52)			362			145
Repurchase of company common stock			(5,400)			(9,270)			(3,623)
Dividends paid			(5,583)			(5,726)			(2,359)
Other			(34)			(49)			7
Net Cash Used in Financing Activities			(8,661)			(18,053)			(6,335)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash			(99)			(224)			(34)
Net Change in Cash, Cash Equivalents and Restricted Cash			(795)			1,296			2,083
Cash, cash equivalents and restricted cash at beginning of period			6,694			5,398			3,315
Cash, Cash Equivalents and Restricted Cash at End of Period			$	5,899		6,694			5,398

Restricted cash of $264 million and $236 million is included in the “Other assets” line of our Consolidated Balance Sheet as of December 31, 2023 and December 31, 2022, respectively.

See Notes to Consolidated Financial Statements.

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Financial Statements			Table of Contents

Consolidated Statement of Changes in Equity			ConocoPhillips

			Millions of Dollars
			Common Stock
			Par Value			Capital in Excess of Par			Treasury Stock			Accum. Other Comprehensive Income (Loss)			Retained Earnings						Total
Balances at December 31, 2020			$	18		47,133			(47,297)			(5,218)			35,213						29,849
Net income (loss)															8,079						8,079
Other comprehensive income (loss)												268									268
Dividends declared
Ordinary ($1.75 per share of common stock)															(2,359)						(2,359)
Variable return of cash ($0.20 per share of common stock)															(260)						(260)
Acquisition of Concho			3			13,122															13,125
Repurchase of company common stock									(3,623)												(3,623)
Distributed under benefit plans						326															326
Other															1						1
Balances at December 31, 2021			$	21		60,581			(50,920)			(4,950)			40,674						45,406
Net income (loss)															18,680						18,680
Other comprehensive income (loss)												(1,050)									(1,050)
Dividends declared
Ordinary ($1.89 per share of common stock)															(2,419)						(2,419)
Variable return of cash ($3.10 per share of common stock)															(3,908)						(3,908)
Repurchase of company common stock									(9,270)												(9,270)
Distributed under benefit plans						561															561
Other									1						2						3
Balances at December 31, 2022			$	21		61,142			(60,189)			(6,000)			53,029						48,003
Net income (loss)															10,957						10,957
Other comprehensive income (loss)												327									327
Dividends declared
Ordinary ($2.11 per share of common stock)															(2,550)						(2,550)
Variable return of cash ($1.80 per share of common stock)															(2,170)						(2,170)
Repurchase of company common stock									(5,400)												(5,400)
Excise tax on share repurchases									(50)												(50)
Distributed under benefit plans						161															161
Other									(1)						2						1
Balances at December 31, 2023			$	21		61,303			(65,640)			(5,673)			59,268						49,279

79			ConocoPhillips 2023 10-K

Notes to Consolidated Financial Statements			Table of Contents

Notes to Consolidated Financial Statements

Note 1—Accounting Policies

• Consolidation Principles and Investments**—Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries and, if applicable, variable interest entities where we are the primary beneficiary. The equity method is used to account for investments in affiliates in which we have the ability to exert significant influence over the affiliates’ operating and financial policies. When we do not have the ability to exert significant influence, the investment is measured at fair value except when the investment does not have a readily determinable fair value. For those exceptions, it will be measured at cost minus impairment, plus or minus observable price changes in orderly transactions for an identical or similar investment of the same issuer. Undivided interests in oil and gas joint ventures, pipelines, natural gas plants and terminals are consolidated on a proportionate basis. Other securities and investments are generally carried at cost. We manage our operations through six operating segments, defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International. See Note 24.

• Foreign Currency Translation**—Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in accumulated other comprehensive income (loss) in common stockholders’ equity. Foreign currency transaction gains and losses are included in current earnings. Some of our foreign operations use their local currency as the functional currency.

• Use of Estimates**—The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.

• Revenue Recognition**—Revenues associated with the sales of crude oil, bitumen, natural gas, NGLs, LNG and other items are recognized at the point in time when the customer obtains control of the asset. In evaluating when a customer has control of the asset, we primarily consider whether the transfer of legal title and physical delivery has occurred, whether the customer has significant risks and rewards of ownership and whether the customer has accepted delivery and a right to payment exists. These products are typically sold at prevailing market prices. We allocate variable market-based consideration to deliveries (performance obligations) in the current period as that consideration relates specifically to our efforts to transfer control of current period deliveries to the customer and represents the amount we expect to be entitled to in exchange for the related products. Payment is typically due within 30 days or less.

Transactions commonly called buy/sell contracts, in which the purchase and sale of inventory with the same counterparty are entered into “in contemplation” of one another, are combined and reported net (i.e., on the same income statement line).

• Shipping and Handling Costs**—We typically incur shipping and handling costs prior to control transferring to the customer and account for these activities as fulfillment costs. Accordingly, we include shipping and handling costs in production and operating expenses for production activities. Transportation costs related to marketing activities are recorded in purchased commodities. Freight costs billed to customers are treated as a component of the transaction price and recorded as a component of revenue when the customer obtains control.

• Cash Equivalents**—Cash equivalents are highly liquid, short-term investments that are readily convertible to known amounts of cash and have original maturities of 90 days or less from their date of purchase. They are carried at cost plus accrued interest, which approximates fair value.

• Short-Term Investments**—Short-term investments include investments in bank time deposits and marketable securities (commercial paper and government obligations) which are carried at cost plus accrued interest and have original maturities of greater than 90 days but within one year or when the remaining maturities are within one year. We also invest in financial instruments classified as available for sale debt securities which are carried at fair value. Those instruments are included in short-term investments when they have remaining maturities of one year or less, as of the balance sheet date.

• Long-Term Investments in Debt Securities**—Long-term investments in debt securities includes financial instruments classified as available for sale debt securities with remaining maturities greater than one year as of the balance sheet date. They are carried at fair value and presented within the “Investments and long-term receivables” line of our consolidated balance sheet.

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Notes to Consolidated Financial Statements			Table of Contents

• Inventories**—We have several valuation methods for our various types of inventories and consistently use the following methods for each type of inventory. The majority of our commodity-related inventories are recorded at cost using the LIFO basis. We measure these inventories at the lower-of-cost-or-market in the aggregate. Any necessary lower-of-cost-or-market write-downs at year end are recorded as permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with current revenues. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location, but not unusual/nonrecurring costs or research and development costs. Materials, supplies and other miscellaneous inventories, such as tubular goods and well equipment, are valued using various methods, including the weighted-average-cost method and the FIFO method, consistent with industry practice.

• Fair Value Measurements**—Assets and liabilities measured at fair value and required to be categorized within the fair value hierarchy are categorized into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or our assumptions about pricing by market participants.

• Derivative Instruments**—Derivative instruments are recorded on the balance sheet at fair value. If the right of offset exists and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the balance sheet and the collateral payable or receivable is netted against derivative assets and derivative liabilities, respectively.

Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives not accounted for as hedges are recognized immediately in earnings. We do not apply hedge accounting to our derivative instruments.

• Oil and Gas Exploration and Development**—Oil and gas exploration and development costs are accounted for using the successful efforts method of accounting.

Property Acquisition Costs—Oil and gas leasehold acquisition costs are capitalized and included in the balance sheet caption PP&E. Leasehold impairment is recognized based on exploratory experience and management’s judgment. Upon achievement of all conditions necessary for reserves to be classified as proved, the associated leasehold costs are reclassified to proved properties.

Exploratory Costs—Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or “suspended,” on the balance sheet pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the potential oil and gas field or while we seek government or coventurer approval of development plans or seek environmental permitting. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas resources are designated as proved reserves.

Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as dry holes when it judges the potential field does not warrant further investment in the near term. See Note 6.

Development Costs—Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.

Depletion and Amortization—Leasehold costs of producing properties are depleted using the unit-of-production method based on estimated proved oil and gas reserves. Amortization of development costs is based on the unit-of-production method using estimated proved developed oil and gas reserves.

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• Capitalized Interest**—Interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets.

• Depreciation and Amortization**—Depreciation and amortization of PP&E on producing hydrocarbon properties and SAGD facilities and certain pipeline and LNG assets (those which are expected to have a declining utilization pattern), are determined by the unit-of-production method. Depreciation and amortization of all other PP&E are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units).

• Impairment of Properties, Plants and Equipment**—Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If there is an indication the carrying amount of an asset may not be recovered, a recoverability test is performed using management’s assumptions for prices, volumes and future development plans. If the sum of the undiscounted cash flows before income-taxes is less than the carrying value of the asset group, the carrying value is written down to estimated fair value and reported as an impairment in the period in which the determination is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for E&P assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates and prices believed to be consistent with those used by principal market participants, or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible.

The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, commodity prices, operating costs and capital decisions, considering all available evidence at the date of review. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. Additionally, when probable and possible reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the impairment calculation.

Long-lived assets committed by management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell, with fair value determined using a binding negotiated price, if available, or present value of expected future cash flows as previously described.

• Maintenance and Repairs**—Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.

• Property Dispositions**—When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in the “Gain (loss) on dispositions” line of our consolidated income statement. When partial units of depreciable property are sold or retired which do not significantly alter the DD&A rate, the asset cost and accumulated depreciation are eliminated such that no gain or loss is recorded.

• Asset Retirement Obligations and Environmental Costs**—The fair value of legal obligations to retire and remove long-lived assets are recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). Fair value is estimated using a present value approach, incorporating assumptions about estimated amounts and timing of settlements and impacts of the use of technologies. See Note 8.

Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures relating to an existing condition caused by past operations, and those having no future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless acquired through a business combination, which we record on a discounted basis) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is probable and estimable.

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• Impairment of Investments in Nonconsolidated Entities**—Investments in nonconsolidated entities are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred. When such a condition is judgmentally determined to be other than temporary, the carrying value of the investment is written down to fair value. The fair value of the impaired investment is based on quoted market prices, if available, or upon the present value of expected future cash flows using discount rates and prices believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate.

• Guarantees**—The fair value of a guarantee is determined and recorded as a liability at the time the guarantee is given. The initial liability is subsequently reduced as we are released from exposure under the guarantee. We amortize the guarantee liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is indefinite, we reverse the liability when we have information indicating the liability is essentially relieved or amortize it over an appropriate time period as the fair value of our guarantee exposure declines over time. We amortize the guarantee liability to the related income statement line item based on the nature of the guarantee. When it becomes probable that we will have to perform on a guarantee, we accrue a separate liability if it is reasonably estimable, based on the facts and circumstances at that time. We reverse the fair value liability only when there is no further exposure under the guarantee.

• Share-Based Compensation**—We recognize share-based compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the award) or the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement. We have elected to recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.

• Income Taxes**—Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial reporting basis and the tax basis of our assets and liabilities, except for deferred taxes on income and temporary differences related to the cumulative translation adjustment considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures. Allowable tax credits are applied currently as reductions of the provision for income taxes. Interest related to unrecognized tax benefits is reflected in interest and debt expense, and penalties related to unrecognized tax benefits are reflected in production and operating expenses.

• Taxes Collected from Customers and Remitted to Governmental Authorities**—Sales and value-added taxes are recorded net.

• Net Income (Loss) Per Share of Common Stock**—Basic net income (loss) per share (EPS) is calculated using the two-class method. Under the two-class method, all earnings (distributed and undistributed) are allocated to common stock (including fully vested stock and unit awards that have not yet been issued as common stock) and participating securities. ConocoPhillips grants RSUs under its share-based compensation programs, the majority of which entitle recipients to receive nonforfeitable dividends during the vesting period on a basis equivalent to dividends paid to holders of the Company’s common stock. See Note 16. These unvested RSUs meet the definition of participating securities based on their respective rights to receive non-forfeitable dividends and are treated as a separate class of securities in computing basic EPS. Participating securities are not included as incremental shares in computing diluted EPS. Diluted EPS includes the potential impact of contingently issuable shares, including awards which require future service as a condition of delivery of the underlying common stock.

Diluted EPS is calculated under both the two-class and treasury stock methods, and the more dilutive amount is reported. Diluted net loss per share does not assume conversion or exercise of securities that would have an antidilutive effect. Treasury stock is excluded from the daily weighted-average number of common shares outstanding in both calculations. See Note 23.

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Note 2—Inventories

Inventories at December 31 were:

			Millions of Dollars
			2023			2022
Crude oil and natural gas			$	676		641
Materials and supplies			722			578
Total inventories			$	1,398		1,219
Inventories valued on the LIFO basis			$	401		396

The estimated excess of current replacement cost over LIFO cost of inventories was approximately $91 million and $149 million at December 31, 2023 and 2022, respectively.

Note 3—Acquisitions and Dispositions

All gains or losses on asset dispositions are reported before-tax and are included net in the “Gain (loss) on dispositions” line on our consolidated income statement. All cash proceeds and payments are included in the “Cash Flows From Investing Activities” section of our consolidated statement of cash flows.

2023

Surmont Acquisition

In October 2023, we completed our acquisition of the remaining 50 percent working interest in Surmont, an asset in our Canada segment, from TotalEnergies EP Canada Ltd. Following the acquisition, we own 100 percent working interest in Surmont. The fair value of total consideration for the all-cash transaction was $3.0 billion (CAD $4.1 billion):

Fair value of consideration			Millions of Dollars
Cash paid			$	2,685
Contingent consideration			320
Total consideration			$	3,005

The contingent payment arrangement requires additional consideration to be paid to TotalEnergies EP Canada Ltd. up to $0.4 billion CAD over a five-year term. The contingent payments represent $2.0 million for every dollar that WCS pricing exceeds $52 per barrel during the month, subject to certain production targets being achieved. The range of the undiscounted amounts we could pay under this arrangement is between $0 and $0.3 billion. The fair value of the contingent consideration on the acquisition date was $320 million and estimated by applying the income approach. See Note 13.

The transaction is accounted for as a business combination under FASB Topic ASC 805 using the acquisition method, which requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. Fair value measurements were made for acquired assets and liabilities, and adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date as we identify new information about facts and circumstances that existed as of the acquisition date to consider.

Oil and gas properties were valued using a discounted cash flow approach incorporating market participants and internally generated price assumptions, production profiles and operating and development cost assumptions. The fair values of other assets acquired and liabilities assumed, which included accounts receivable, accounts payable, and most other current assets and current liabilities, were determined to be equivalent to the carrying value due to their short-term nature. The total consideration of $3.0 billion was allocated to the identifiable assets and liabilities based on their fair values as of the acquisition date, October 4, 2023.

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Recognized amounts of identifiable assets acquired and liabilities assumed			Millions of Dollars
Oil and gas properties			3,129
Asset retirement obligations			(112)
Other			(12)
Total identifiable net assets			$	3,005

With the completion of the transaction, we acquired proved and unproved properties of approximately $2.9 billion and $0.2 billion, respectively.

In anticipation of the acquisition, we entered into, and settled, various foreign exchange forward contracts to purchase CAD and recognized a loss of $112 million in the "Foreign currency transaction (gain) loss" line on our consolidated income statement associated with these forward contracts. The related cash flows are included within "cash flows from investing activities" on our consolidated statement of cash flows.

From the acquisition date through December 31, 2023, "Total Revenues and Other Income" and "Net Income (Loss)" associated with the acquired assets were $572 million and $119 million, respectively.

Supplemental Pro Forma (unaudited)

The following tables summarize the unaudited supplemental pro forma financial information for the year ended December 31, 2023, and 2022, as if we had completed the acquisition on January 1, 2022.

			Millions of Dollars
			Year Ended December 31, 2023
			As reported						Pro forma Surmont			Pro forma Combined
Total Revenues and Other Income			$	58,574					2,561			61,135
Income (loss) before income taxes			16,288						659			16,947
Net Income (Loss)			10,957						501			11,458
Earnings per share:
Basic net income (loss)			$	9.08								9.50
Diluted net income (loss)			9.06									9.47
			Millions of Dollars
			Year Ended December 31, 2022
			As reported						Pro forma Surmont			Pro forma Combined
Total Revenues and Other Income			$	82,156					3,582			85,738
Income (loss) before income taxes			28,228						947			29,175
Net Income (Loss)			18,680						720			19,400
Earnings per share:
Basic net income (loss)			$	14.62								15.18
Diluted net income (loss)			14.57									15.13

The unaudited supplemental pro forma financial information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the transactions been completed on January 1, 2022, nor is it necessarily indicative of future operating results of the combined entity. The unaudited pro forma financial information for the years ending December 31, 2023 and 2022, respectively, is a result of combining the consolidated income statement of ConocoPhillips with the assets acquired from TotalEnergies EP Canada Ltd. The pro forma results do not include transaction-related costs, nor any cost savings anticipated as a result of the transaction. The pro forma results include adjustments which relate primarily to DD&A, which is based on the unit-of-production method, resulting from the purchase price allocated to properties, plants and equipment. We believe the estimates and assumptions are reasonable, and the relative effects of the transaction are properly reflected.

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QatarEnergy LNG NFS(3) (NFS3), formerly Qatar Liquefied Gas Company Limited (12) (QG12)

During 2022, we were awarded a 25 percent interest in NFS3, a new joint venture with QatarEnergy, to participate in the North Field South (NFS) LNG project. Formation of NFS3 closed during 2023. NFS3 has a 25 percent interest in the NFS project and is reported as an equity method investment in our Europe, Middle East and North Africa segment. See Note 4.

Port Arthur Liquefaction Holdings, LLC (PALNG)

During 2023, we acquired a 30 percent interest in PALNG, a joint venture for the development of a large-scale LNG facility for the first phase of the Port Arthur LNG project ("Phase 1"). Sempra PALNG Holdings, LLC owns the remaining 70 percent interest in the joint venture. PALNG is reported as an equity method investment in our Corporate and Other segment. See Note 4.

Contingent Payments

We recorded contingent payments related to the previous dispositions of our working interests in the Foster Creek Christina Lake Partnership and western Canada gas assets, and our San Juan assets. Contingent payments were recorded as (gain) loss on disposition on our consolidated income statement and reflected within our Canada and Lower 48 segments. In our Canada segment, the contingent payment, calculated and paid quarterly, was $6 million CAD for every $1 CAD by which the WCS quarterly average crude oil price exceeded $52 CAD per barrel. In our Lower 48 segment, the contingent payment, paid annually, was calculated monthly at $7 million per month when the U.S. Henry Hub natural gas price was at or above $3.20 per MMBTU. The term of contingent payments in our Canada segment ended in the second quarter of 2022 and the term of contingent payments in our Lower 48 segment ended at the end of 2023. Contingent payments recorded in the years 2023, 2022 and 2021 were $7 million, $451 million and $369 million, respectively.

2022

Acquisition of Additional Shareholding Interest in Australia Pacific LNG (APLNG)

In February 2022, we completed the acquisition of an additional 10 percent interest in APLNG from Origin Energy for approximately $1.4 billion, after customary adjustments, in an all-cash transaction resulting from the exercise of our preemption right. This increased our ownership in APLNG to 47.5 percent, with Origin Energy and Sinopec owning

27.5 percent and 25.0 percent, respectively. APLNG is reported as an equity investment in our Asia Pacific segment.

QatarEnergy LNG NFE(4) (NFE4), formerly Qatar Liquefied Gas Company Limited (8) (QG8)

During 2022, we were awarded a 25 percent interest in NFE4, a new joint venture with QatarEnergy to participate in the North Field East (NFE) LNG project. NFE4 has a 12.5 percent interest in the NFE project and is reported as an equity method investment in our Europe, Middle East and North Africa segment. See Note 4.

Asset Acquisition

In September 2022, we completed the acquisition of an additional working interest in certain Eagle Ford acreage in the Lower 48 segment for cash consideration of $236 million after customary adjustments. This agreement was accounted for as an asset acquisition, with the consideration allocated primarily to PP&E.

Assets Sold

During 2022, we sold our interests in certain noncore assets in our Lower 48 segment for net proceeds of $680 million, with no gain or loss recognized on sale. At the time of disposition, our interest in these assets had a net carrying value of $680 million, consisting of $825 million of assets, primarily related to $818 million of PP&E, and $145 million of liabilities, primarily related to AROs.

In March 2022, we completed the divestiture of our subsidiaries that held our Indonesia assets and operations, and based on an effective date of January 1, 2021, we received net proceeds of $731 million after customary adjustments and recognized a $534 million before-tax and $462 million after-tax gain related to this transaction. Together, the subsidiaries sold indirectly held our 54 percent interest in the Indonesia Corridor Block PSC and 35 percent shareholding in the Transasia Pipeline Company. At the time of the disposition, the net carrying value was approximately $0.2 billion, excluding $0.2 billion of cash and restricted cash. The net book value consisted primarily of $0.3 billion of PP&E and $0.1 billion of ARO. The before-tax earnings associated with the subsidiaries sold, excluding the gain on disposition noted above, were $138 million and $604 million for the years ended December 31, 2022 and 2021, respectively. Results of operations for the Indonesia interests sold were reported in our Asia Pacific segment.

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2021

During the year, we completed the acquisitions of Concho Resources Inc. (Concho) and of Shell Enterprises LLC’s (Shell) Permian assets. The acquisitions were accounted for as business combinations under FASB Topic ASC 805 using the acquisition method, which requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. We completed the final allocation of the purchase price to acquired assets and liabilities of Concho by the end of the year, and by the end of the first quarter of 2022 for the Shell assets. It was based on the fair value of the long-lived assets and the conclusion of the fair value determination of all other assets and liabilities acquired.

Acquisition of Concho Resources Inc.

In January 2021, we completed our acquisition of Concho, an independent oil and gas exploration and production company with operations across New Mexico and West Texas focused in the Permian-based Delaware and Midland Basins. Total consideration for the all-stock transaction was valued at $13.1 billion, in which 1.46 shares of ConocoPhillips common stock were exchanged for each outstanding share of Concho common stock.

We recognized approximately $157 million of transaction-related costs, all of which were expensed in the first quarter of 2021. These non-recurring costs related primarily to fees paid to advisors and the settlement of share-based awards for certain Concho employees based on the terms of the Merger Agreement.

In the first quarter of 2021, we commenced a company-wide restructuring program, the scope of which included combining the operations of the two companies as well as other global restructuring activities. We recognized non-recurring restructuring costs mainly for employee severance and related incremental pension benefit costs.

The impact from the transaction and restructuring costs to the lines of our consolidated income statement for the year ended December 31, 2021, are below:

			Millions of Dollars
			Transaction Cost			Restructuring Cost			Total Cost
Production and operating expenses						128			128
Selling, general and administration expenses			135			67			202
Exploration expenses			18			8			26
Taxes other than income taxes			4			2			6
Other expenses			—			29			29
			$	157		234			391

In February 2021, we completed a debt exchange offer related to the debt assumed from Concho. As a result of the debt exchange, we recognized an additional income tax-related restructuring charge of $75 million.

From the acquisition date through December 31, 2021, “Total Revenues and Other Income” and “Net Income (Loss)” associated with the acquired Concho business were approximately $6,571 million and $2,330 million, respectively. The results associated with the Concho business for the same period include a before- and after-tax loss of $305 million and $233 million, respectively, on the acquired derivative contracts. The before-tax loss is recorded within “Total Revenues and Other Income” on our consolidated income statement. See Note 12.

Acquisition of Shell Permian Assets

In December 2021, we completed our acquisition of Shell assets in the Permian based Delaware Basin. The accounting close date used for reporting purposes was December 31, 2021. Assets acquired include approximately 225,000 net acres and producing properties located entirely in Texas. Total consideration for the transaction was $8.6 billion. We recognized approximately $44 million of transaction-related costs which were expensed in 2021.

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Supplemental Pro Forma (unaudited)

The following table summarizes the unaudited supplemental pro forma financial information for the year ended December 31, 2021, as if we had completed the acquisition of the Shell Permian assets on January 1, 2020.

			Millions of Dollars
			Year Ended December 31, 2021
			As reported									Pro forma Shell			Pro forma Combined
Total Revenues and Other Income			$	48,349								3,220			51,569
Income (loss) before income taxes			12,712									1,201			13,913
Net Income (Loss)			8,079									920			8,999
Earnings per share:
Basic net income (loss)			$	6.09											6.78
Diluted net income (loss)			6.07												6.76

The unaudited supplemental pro forma financial information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the transaction been completed on January 1, 2020, nor is it necessarily indicative of future operating results of the combined entity. The pro forma results do not include transaction-related costs, nor any cost savings anticipated as a result of the transaction. The pro forma includes adjustments which relate primarily to DD&A, which is based on the unit-of-production method, resulting from the purchase price allocated to properties, plants and equipment. We believe the estimates and assumptions are reasonable, and the relative effects of the transaction are properly reflected.

Assets Sold

In 2020, we completed the sale of our Australia-West assets and operations. The sales agreement entitled us to a $200 million payment upon a FID of the Barossa development project. In March 2021, FID was announced and as such, we recognized a $200 million gain on disposition in the first quarter of 2021. The purchaser failed to pay the FID bonus when due. We filed an arbitration proceeding against the purchaser to enforce our contractual right to the $200 million, plus interest accruing from the due date and the matter was resolved in April 2023 to our satisfaction. Results of operations related to this transaction are reflected in our Asia Pacific segment. See Note 11.

In the second half of 2021, we sold our interests in certain noncore assets in our Lower 48 segment for approximately $250 million after customary adjustments, recognizing a before-tax gain on sale of approximately $58 million. We also completed the sale of our noncore exploration interests in Argentina, recognizing a before-tax loss on disposition of $179 million. Results of operations for Argentina were reported in our Other International segment.

Note 4—Investments, Loans and Long-Term Receivables

Components of investments and long-term receivables at December 31 were:

			Millions of Dollars
			2023			2022
Equity investments			$	7,905		7,493
Long-term receivables			143			142
Long-term investments in debt securities			989			522
Other investments			93			68
			$	9,130		8,225

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Equity Investments

Affiliated companies in which we had a significant equity investment at December 31, 2023, included:

• APLNG—47.5 percent owned joint venture with Origin Energy (27.5 percent) and Sinopec (25 percent)—to produce CBM from the Bowen and Surat basins in Queensland, Australia, as well as process and export LNG.

• Port Arthur Liquefication Holdings, LLC (PALNG)— 30 percent owned joint venture with Sempra PALNG Holdings, LLC for the development of a large-scale LNG facility for the first phase of the Port Arthur LNG project ("Phase 1"). See Note 3.

• QatarEnergy LNG N(3) (N3), formerly Qatar Liquefied Gas Company Limited (3) (QG3)—30 percent owned joint venture with affiliates of QatarEnergy (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent)—produces and liquefies natural gas from Qatar’s North Field, as well as exports LNG.

• QatarEnergy LNG NFE(4) (NFE4), formerly Qatar Liquefied Gas Company Limited (8) (QG8)—25 percent owned joint venture with an affiliate of QatarEnergy (75 percent)—participant in the North Field East (NFE) LNG project. See Note 3.

• QatarEnergy LNG NFS(3) (NFS3), formerly Qatar Liquefied Gas Company Limited (12) (QG12)— 25 percent owned joint venture with an affiliate of QatarEnergy (75 percent)—participant in the North Field South project. See Note 3.

Summarized 100 percent earnings information for equity method investments in affiliated companies, combined, was as follows:

			Millions of Dollars
			2023			2022			2021
Revenues			$	15,314		18,356			11,824
Income (loss) before income taxes			6,301			8,234			3,946
Net income (loss)			4,214			5,507			2,557

Summarized 100 percent balance sheet information for equity method investments in affiliated companies, combined, was as follows:

			Millions of Dollars
			2023			2022
Current assets			$	3,827		5,001
Noncurrent assets			39,299			37,789
Current liabilities			3,462			4,169
Noncurrent liabilities			16,665			17,244

Our share of income taxes incurred directly by an equity method investee is reported in equity in earnings of affiliates, and as such is not included in income taxes on our consolidated financial statements.

At December 31, 2023, retained earnings included $60 million related to the undistributed earnings of affiliated companies. Dividends received from affiliates were $2,684 million, $3,045 million and $1,279 million in 2023, 2022 and 2021, respectively.

APLNG

APLNG is a joint venture focused on producing CBM from the Bowen and Surat basins in Queensland, Australia. Natural gas is sold to domestic customers and LNG is processed and exported to Asia Pacific markets. Our investment in APLNG gives us access to CBM resources in Australia and enhances our LNG position. The majority of APLNG LNG is sold under two long-term sales and purchase agreements, supplemented with sales of additional LNG cargoes targeting the Asia Pacific markets. Origin Energy, an integrated Australian energy company, is the operator of APLNG’s production and pipeline system, while we operate the LNG facility.

In 2012, APLNG executed an $8.5 billion project finance facility that became non-recourse following financial completion in 2017. The facility is currently composed of a financing agreement with the Export-Import Bank of the United States, a commercial bank facility and two United States Private Placement note facilities. APLNG principal and interest payments commenced in March 2017 and are scheduled to occur bi-annually until September 2030. At December 31, 2023, a balance of $4.7 billion was outstanding on the facilities. See Note 10.

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During the fourth quarter of 2021, Origin Energy Limited agreed to the sale of 10 percent of their interest in APLNG for $1.645 billion, before customary adjustments. ConocoPhillips announced in December 2021 that we were exercising our preemption right under the APLNG Shareholders Agreement to purchase an additional 10 percent shareholding interest in APLNG, subject to government approvals. The sales price associated with this preemption right was determined to reflect a relevant observable market participant view of APLNG’s fair value which was below the carrying value of our existing investment in APLNG. Based on a review of the facts and circumstances surrounding this decline in fair value, we concluded in the fourth quarter of 2021 the impairment was other than temporary under the guidance of FASB ASC Topic 323, and the recognition of an impairment of our existing investment was necessary. Accordingly, we recorded a noncash $688 million before- and after-tax impairment in the fourth quarter of 2021. The impairment was included in the “Impairments” line on our consolidated income statement. See Note 7.

At December 31, 2023, the carrying value of our equity method investment in APLNG was approximately $5.4 billion. The historical cost basis of our 47.5 percent share of net assets of APLNG was $5.4 billion, resulting in a basis difference of $33 million on our books. The basis difference, which is substantially all associated with PP&E and subject to amortization, has been allocated on a relative fair value basis to individual production license areas owned by APLNG. Any future additional payments are expected to be allocated in a similar manner. As the joint venture produces natural gas from each license, we amortize the basis difference allocated to that license using the unit-of-production method. Included in net income (loss) for 2023, 2022 and 2021 was after-tax expense of $8 million, $10 million and $39 million, respectively, representing the amortization of this basis difference on currently producing licenses.

PALNG

PALNG is a joint venture for the development of a large-scale LNG facility. At December 31, 2023, the carrying value of our equity method investment in PALNG was approximately $1.1 billion. See Note 3.

N3

N3 is a joint venture that owns an integrated large-scale LNG project located in Qatar. We have terminal and pipeline use agreements with Golden Pass LNG Terminal and affiliated Golden Pass Pipeline near Sabine Pass, Texas, intended to provide us with terminal and pipeline capacity for the receipt, storage and regasification of LNG purchased from N3. Currently, the LNG from N3 is being sold to markets outside of the U.S.

NFE4

NFE4 is a joint venture with QatarEnergy participating in the NFE LNG project. NFE4 has a 12.5 percent interest in the NFE project. See Note 3.

NFS3

NFS3 is a joint venture with QatarEnergy to participate in the NFS LNG project. NFS3 has a 25 percent interest in the NFS project. See Note 3.

At December 31, 2023, the carrying value of our equity method investments in Qatar was approximately $1.1 billion.

Loans

As part of our normal ongoing business operations and consistent with industry practice, we enter into numerous agreements with other parties to pursue business opportunities. Included in such activity are loans to certain affiliated and non-affiliated companies.

At December 31, 2023, there were no outstanding loans to affiliated companies.

Note 5—Investment in Cenovus Energy

In 2022, we sold our remaining 91 million shares of Cenovus Energy (CVE), recognizing proceeds of $1.4 billion and a net gain of $251 million. All gains and losses were recognized within "Other income" on our consolidated income statement. Proceeds related to the sale of our CVE shares were included within "Cash Flows from Investing Activities" on our consolidated statement of cash flows.

			Millions of Dollars
			2023			2022			2021
Total Net gain on equity securities						251			1,040
Less: Net gain on equity securities sold during the period						251			473
Unrealized gain on equity securities still held at the reporting date			$						567

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Note 6—Suspended Wells and Exploration Expenses

The following table reflects the net changes in suspended exploratory well costs during 2023, 2022 and 2021:

			Millions of Dollars
			2023			2022			2021
Beginning balance			$	527		660			682
Additions pending the determination of proved reserves			—			5			10
Reclassifications to proved properties			(285)			(7)			—
Charged to dry hole expense			(58)			(131)			(32)
Ending balance			$	184		527			660

The following table provides an aging of suspended well balances at December 31:

			Millions of Dollars
			2023			2022			2021
Exploratory well costs capitalized for a period of one year or less			$	—		15			4
Exploratory well costs capitalized for a period greater than one year			184			512			656
Ending balance			$	184		527			660
Number of projects with exploratory well costs capitalized for a period greater than one year			14			17			22

The following table provides a further aging of those exploratory well costs that have been capitalized for more than one year since the completion of drilling as of December 31, 2023:

			Millions of Dollars
						Suspended Since
			Total			2020-2022			2017-2019			2006-2016
WL4-00—Malaysia(2)			36			19			17			—
PL891—Norway(1)			30			30			—			—
West Willow—Alaska(1)			29			—			29			—
Narwhal Trend—Alaska(1)			25			—			25			—
PL782S—Norway(1)			19			—			19			—
Montney—Canada(1)			16			8			8			—
Other of $10 million or less each(1)(2)			29			—			4			25
Total			$	184		57			102			25

*(1)*Additional appraisal wells planned.

*(2)*Appraisal drilling complete; costs being incurred to assess development.

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Exploration Expenses

The charges discussed below are included in the “Exploration expenses” line on our consolidated income statement.

2023

In our Europe, Middle East and North Africa segment, after further evaluation we recognized a before-tax expense of $37 million for dry hole costs associated with the suspended Warka discovery well, drilled in 2020, on license PL1009 in the Norwegian Sea.

In our Alaska segment, we recorded a before-tax expense of approximately $31 million for dry hole costs associated with the Bear-1 exploration well.

2022

In the fourth quarter, we recorded a before-tax expense of $129 million for impairment of certain aged, suspended wells associated with Surmont in our Canada segment.

In our Europe, Middle East and North Africa segment, we recorded a before-tax expense of $102 million for dry hole costs associated with four operated exploration and appraisal wells and one partner-operated well that were drilled in Norway in 2022.

Note 7—Impairments

During 2023, 2022 and 2021, we recognized the following before-tax impairment charges:

			Millions of Dollars
			2023			2022			2021
Alaska			$	—		2			5
Lower 48			7			(11)			(8)
Canada			6			(2)			6
Europe, Middle East and North Africa			—			(1)			(24)
Asia Pacific			—			—			695
Corporate and Other			1			—			—
			$	14		(12)			674

2021

We recorded an impairment of $688 million on our APLNG investment included within the Asia Pacific segment. See Note 4 and Note 13.

In our Lower 48 segment, we recorded a credit to impairment of $89 million due to a decreased ARO estimate for a previously sold asset, in which we retained the ARO liability. This was offset by recorded impairments of $84 million during the fourth quarter of 2021, related to certain noncore assets due to changes in development plans. See Note 13.

In our Europe, Middle East and North Africa segment, we recorded a credit to impairment of $24 million due to decreased ARO estimates on fields in Norway which ceased production and were fully depreciated in prior years.

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Note 8—Asset Retirement Obligations and Accrued Environmental Costs

Asset retirement obligations and accrued environmental costs at December 31 were:

			Millions of Dollars
			2023			2022
Asset retirement obligations			$	7,227		6,380
Accrued environmental costs			184			182
Total asset retirement obligations and accrued environmental costs			7,411			6,562
Asset retirement obligations and accrued environmental costs due within one year*			(191)			(161)
Long-term asset retirement obligations and accrued environmental costs			$	7,220		6,401

*Classified as a current liability on the balance sheet under “Other accruals.”

Asset Retirement Obligations

We record the fair value of a liability for an ARO when it is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize the associated asset retirement cost by increasing the carrying amount of the related PP&E. Over time, the liability increases for the change in its present value, while the capitalized cost depreciates over the useful life of the related asset. If in subsequent periods, our estimate of this liability changes, we will record an adjustment to both the liability and PP&E. Reductions to estimated liabilities for assets that are no longer producing are recorded as a credit to impairment.

We have numerous AROs we are required to perform under law or contract once an asset is permanently taken out of service. Most of these obligations are not expected to be paid until several years, or decades, in the future and will be funded from general company resources at the time of removal. Our largest individual obligations involve plugging and abandonment of wells and removal and disposal of offshore oil and gas platforms around the world, as well as oil and gas production facilities and pipelines in Alaska.

During 2023 and 2022, our overall ARO changed as follows:

			Millions of Dollars
			2023			2022
Balance at January 1			$	6,380		5,926
Accretion of discount			278			245
New obligations			257			144
Changes in estimates of existing obligations			484			681
Spending on existing obligations			(119)			(231)
Property dispositions			(27)			(203)
Foreign currency translation			(26)			(182)
Balance at December 31			$	7,227		6,380

Accrued Environmental Costs

Total accrued environmental costs at December 31, 2023 and 2022, were $184 million and $182 million, respectively.

We had accrued environmental costs of $112 million and $107 million at December 31, 2023 and 2022, respectively, related to remediation activities in the U.S. and Canada. We had also accrued in Corporate and Other $55 million and $59 million of environmental costs associated with sites no longer in operation at December 31, 2023 and 2022, respectively. In addition, December 31, 2023 and 2022, included a $17 million and $16 million accrual, respectively, where the company has been named a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act, or similar state laws. Accrued environmental liabilities are expected to be paid over periods extending up to 30 years.

Expected expenditures for environmental obligations acquired in various business combinations are discounted using a weighted-average 5 percent discount factor, resulting in an accrued balance for acquired environmental liabilities of $116 million at December 31, 2023. The total expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are $151 million.

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Note 9—Debt

Long-term debt at December 31 was:

			Millions of Dollars
			2023			2022
7.65% Debentures due 2023			—			78
2.125% Notes due 2024			461			900
3.35% Notes due 2024			265			426
2.4% Notes due 2025			366			900
8.2% Notes due 2025			134			134
3.35% Debentures due 2025			199			199
6.875% Debentures due 2026			67			67
7.8% Debentures due 2027			203			203
3.75% Notes due 2027			196			196
4.3% Notes due 2028			223			223
7.375% Debentures due 2029			92			92
7.0% Debentures due 2029			112			112
6.95% Notes due 2029			1,195			1,195
8.125% Notes due 2030			390			390
2.4% Notes due 2031			227			227
7.2% Notes due 2031			447			447
7.25% Notes due 2031			400			400
7.4% Notes due 2031			382			382
5.9% Notes due 2032			505			505
5.05% Notes due 2033			1,000			—
4.15% Notes due 2034			246			246
5.95% Notes due 2036			326			326
5.951% Notes serially maturing 2022 through 2037			603			631
5.9% Notes due 2038			350			350
6.5% Notes due 2039			1,588			1,588
3.758% Notes due 2042			785			785
4.3% Notes due 2044			750			750
5.95% Notes due 2046			329			329
7.9% Debentures due 2047			60			60
4.875% Notes due 2047			319			319
4.85% Notes due 2048			219			219
3.8% Notes due 2052			1,100			1,100
5.3% Notes due 2053			1,100			—
5.55% Notes due 2054			1,000			—
4.025% Notes due 2062			1,770			1,770
5.70% Notes due 2063			700			—
Marine Terminal Revenue Refunding Bonds due 2031 at 1.65% – 4.70% during 2023 and 0.07% – 4.10% during 2022			265			265
Industrial Development Bonds due 2035 at 1.85% – 4.70% during 2023 and 0.07% – 4.10% during 2022			18			18
Other			21			23
Debt at face value			18,413			15,855
Finance leases			1,129			1,320
Net unamortized premiums, discounts and debt issuance costs			(605)			(532)
Total debt			18,937			16,643
Short-term debt			(1,074)			(417)
Long-term debt			$	17,863		16,226

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The principal amounts of long-term debt, excluding finance lease obligations, maturing in 2024 through 2028 are: $759 million, $735 million, $104 million, $438 million, and $265 million, respectively.

2023

In December 2023, the company retired $78 million principal amount of our 7.65 percent Notes at maturity. In the third quarter of 2023, we issued $2.7 billion in new Notes through our universal shelf registration statement and prospectus supplement. The net proceeds were used to fund the acquisition of the remaining 50 percent working interest in Surmont which closed in October 2023. See Note 3. The following Notes were issued:

• 5.05% Notes due 2033 with principal of $1.0 billion

• 5.55% Notes due 2054 with principal of $1.0 billion

• 5.70% Notes due 2063 with principal of $0.7 billion

In the second quarter of 2023, as described further below, we initiated and completed two concurrent transactions as part of our debt refinancing strategy. We issued $1.1 billion in new Notes through our universal shelf registration statement and prospectus supplement and used the proceeds to repurchase $1.1 billion of existing debt.

Debt Issuance

On May 23, 2023, we issued 5.3% Notes due 2053 with principal of $1.1 billion.

Tender Offers

On May 25, 2023, we repurchased a total of $1,133 million aggregate principal amount of debt as listed below. We paid $33 million below face value to repurchase these debt instruments and recognized a gain on debt extinguishment of $27 million, which is included in the "Other expenses" line on our consolidated income statement.

• 2.125% Notes due 2024 with principal of $900 million (partial repurchase of $439 million)

• 3.350% Notes due 2024 with principal of $426 million (partial repurchase of $160 million)

• 2.400% Notes due 2025 with principal of $900 million (partial repurchase of $534 million)

2022

In December 2022, the company retired $329 million principal amount of our 2.40 percent Notes at maturity. In May 2022, we redeemed $1,250 million principal amount of our 4.95 percent Notes due 2026. We paid premiums above face value of $79 million to redeem the debt and recognized a loss on debt extinguishment of $83 million which is included in the "Other expenses" line on our consolidated income statement. We also paid $500 million to retire the outstanding principal amount of the floating rate notes due 2022 at maturity.

In the first quarter of 2022, we completed a debt refinancing consisting of three concurrent transactions: a tender offer to repurchase existing debt for cash; exchange offers to retire certain debt in exchange for new debt and cash; and a new debt issuance to partially fund the cash paid in the tender and exchange offers.

Tender Offer

In March 2022, we repurchased a total of $2,716 million aggregate principal amount of debt as listed below. We paid premiums above face value of $333 million to repurchase these debt instruments and recognized a gain on debt extinguishment of $155 million, which is included in the "Other expenses" line on our consolidated income statement.

• 3.75% Notes due 2027 with principal of $1,000 million (partial repurchase of $804 million)

• 4.3% Notes due 2028 with principal of $1,000 million (partial repurchase of $777 million)

• 2.4% Notes due 2031 with principal of $500 million (partial repurchase of $273 million)

• 4.875% Notes due 2047 with principal of $800 million (partial repurchase of $481 million)

• 4.85% Notes due 2048 with principal of $600 million (partial repurchase of $381 million)

Exchange Offers

Also in March 2022, we completed two concurrent debt exchange offers through which $2,544 million of aggregate principal of existing notes was tendered and accepted in exchange for a combination of new notes and cash. The debt exchange offers were treated as debt modifications for accounting purposes resulting in a portion of the unamortized debt discount, premiums and debt issuance costs of the existing notes being allocated to the new notes on the settlement dates of the exchange offers. We paid premiums above face value of $883 million, comprised of $872 million of cash as well as new notes, which were capitalized as additional debt discount. We incurred expenses of $28 million in the exchanges, which are included in the "Other expenses" line on our consolidated income statement.

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The notes tendered and accepted in the exchange offers were:

• 7.0% Debentures due 2029 with principal amount of $200 million (partial exchange of $88 million)

• 6.95% Notes due 2029 with principal amount of $1,549 million (partial exchange of $354 million)

• 7.4% Notes due 2031 with principal amount of $500 million (partial exchange of $118 million)

• 7.25% Notes due 2031 with principal amount of $500 million (partial exchange of $100 million)

• 7.2% Notes due 2031 with principal amount of $575 million (partial exchange of $128 million)

• 5.95% Notes due 2036 with principal amount of $500 million (partial exchange of $174 million)

• 5.9% Notes due 2038 with principal amount of $600 million (partial exchange of $250 million)

• 6.5% Notes due 2039 with principal amount of $2,750 million (partial exchange of $1,162 million)

• 5.95% Notes due 2046 with principal amount of $500 million (partial exchange of $171 million)

The notes tendered and accepted were exchanged for the following notes:

• 3.758% Notes due 2042 with principal amount of $785 million

• 4.025% Notes due 2062 with principal amount of $1,770 million

Debt Issuance

In March 2022, we issued the following notes:

• 2.125% Notes due 2024 with principal of $900 million

• 2.4% Notes due 2025 with principal of $900 million

• 3.8% Notes due 2052 with principal of $1,100 million

Revolving Credit Facility and Credit Rating Information

In 2022, we refinanced our revolving credit facility from a total borrowing capacity of $6.0 billion down to $5.5 billion with an expiration date of February 2027. Our revolving credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as support for our commercial paper program. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or any of its consolidated subsidiaries. The amount of the facility is not subject to redetermination prior to its expiration date.

Credit facility borrowings may bear interest at a margin above the Secured Overnight Financing Rate (SOFR). The facility agreement calls for commitment fees on available, but unused, amounts. The facility agreement also contains early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.

The revolving credit facility supports our ability to issue up to $5.5 billion of commercial paper. Commercial paper is generally limited to maturities of 90 days and is included in short-term debt on our consolidated balance sheet. With no commercial paper outstanding and no direct borrowings or letters of credit, we had access to $5.5 billion in available borrowing capacity under our revolving credit facility at December 31, 2023 and December 31, 2022.

For information on Finance Leases, see Note 15.

The current credit ratings on our long-term debt are:

• Fitch: “A” with a “stable” outlook

• S&P: “A-” with a “stable” outlook

• Moody's: "A2" with a "stable" outlook

We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity upon downgrade of our credit ratings. If our credit ratings are downgraded from their current levels, it could increase the cost of corporate debt available to us and restrict our access to the commercial paper markets. If our credit ratings were to deteriorate to a level prohibiting us from accessing the commercial paper market, we would still be able to access funds under our revolving credit facility.

At both December 31, 2023 and 2022, we had $283 million of certain variable rate demand bonds (VRDBs) outstanding with maturities ranging through 2035. The VRDBs are redeemable at the option of the bondholders on any business day. If they are ever redeemed, we have the ability and intent to refinance on a long-term basis, therefore, the VRDBs are included in the “Long-term debt” line on our consolidated balance sheet.

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Note 10—Guarantees

At December 31, 2023, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.

APLNG Guarantees

At December 31, 2023, we had outstanding multiple guarantees in connection with our 47.5 percent ownership interest in APLNG. The following is a description of the guarantees with values calculated utilizing December 2023 exchange rates:

• During the third quarter of 2016, we issued a guarantee to facilitate the withdrawal of our pro-rata portion of the funds in a project finance reserve account. We estimate the remaining term of this guarantee to be seven years. Our maximum exposure under this guarantee is approximately $210 million and may become payable if an enforcement action is commenced by the project finance lenders against APLNG. At December 31, 2023, the carrying value of this guarantee was approximately $14 million.

• In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy Limited in October 2008, we agreed to reimburse Origin Energy Limited for our share of the existing contingent liability arising under guarantees of an existing obligation of APLNG to deliver natural gas under several sales agreements. The final guarantee expires in the fourth quarter of 2041. Our maximum potential liability for future payments, or cost of volume delivery, under these guarantees is estimated to be $730 million ($1.2 billion in the event of intentional or reckless breach) and would become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-venturers do not make necessary equity contributions into APLNG.

• We have guaranteed the performance of APLNG with regard to certain other contracts executed in connection with the project’s continued development. The guarantees have remaining terms of 13 to 22 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $390 million and would become payable if APLNG does not perform. At December 31, 2023, the carrying value of these guarantees was approximately $29 million.

QatarEnergy LNG Limited Guarantee

We have guaranteed our portion of certain fiscal and other joint venture obligations as a shareholder in NFE4 and NFS3. This guarantee has an approximate 30-year term with no maximum limit. At December 31, 2023, the carrying value of this guarantee was approximately $14 million.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $620 million, which consist primarily of guarantees of the residual value of leased office buildings and guarantees of the residual value of corporate aircraft. These guarantees have remaining terms of two to five years and would become payable if certain asset values are lower than guaranteed amounts at the end of the lease or contract term, business conditions decline at guaranteed entities, or as a result of nonperformance of contractual terms by guaranteed parties. At December 31, 2023, there was no carrying value associated with these guarantees.

Indemnifications

Over the years, we have entered into agreements to sell ownership interests in certain legal entities, joint ventures and assets that gave rise to qualifying indemnifications. These agreements include indemnifications for taxes and environmental liabilities. The carrying amount recorded for these indemnifications at December 31, 2023, was approximately $20 million. Those related to environmental issues have terms that are generally indefinite and the maximum amounts of future payments are generally unlimited. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. See Note 11 for additional information about environmental liabilities.

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Note 11—Contingencies and Commitments

A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the low end of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. We accrue receivables for insurance or other third-party recoveries when applicable. With respect to income tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain. See Note 17, for additional information about income tax-related contingencies.

Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.

Environmental

We are subject to international, federal, state and local environmental laws and regulations and record accruals for environmental liabilities based on management’s best estimates. These estimates are based on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. EPA or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.

Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for other sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the agency concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit, and some of the indemnifications are subject to dollar limits and time limits.

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state and international sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings.

See Note 8 for a summary of our accrued environmental liabilities.

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Litigation and Other Contingencies

We are subject to various lawsuits and claims including but not limited to matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, climate change, personal injury, and property damage. Our primary exposures for such matters relate to alleged royalty and tax underpayments on certain federal, state and privately owned properties, claims of alleged environmental contamination and damages from historic operations, and climate change. We will continue to defend ourselves vigorously in these matters.

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.

We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at December 31, 2023, we had performance obligations secured by letters of credit of $340 million (issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, commercial activities and services incident to the ordinary conduct of business.

In 2007, ConocoPhillips was unable to reach agreement with respect to the empresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela, S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, ConocoPhillips initiated international arbitration on November 2, 2007, with the ICSID. On September 3, 2013, an ICSID arbitration tribunal held that Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in June 2007. On January 17, 2017, the Tribunal reconfirmed the decision that the expropriation was unlawful. In March 2019, the Tribunal unanimously ordered the government of Venezuela to pay ConocoPhillips approximately $8.7 billion in compensation for the government’s unlawful expropriation of the company’s investments in Venezuela in 2007. On August 29, 2019, the ICSID Tribunal issued a decision rectifying the award and reducing it by approximately $227 million. The award now stands at $8.5 billion plus interest. The government of Venezuela sought annulment of the award, which automatically stayed enforcement of the award. On September 29, 2021, the ICSID annulment committee lifted the stay of enforcement of the award. The annulment proceedings are underway.

In 2014, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against PDVSA under the contracts that had established the Petrozuata and Hamaca projects. The ICC Tribunal issued an award in April 2018, finding that PDVSA owed ConocoPhillips approximately $2 billion under their agreements in connection with the expropriation of the projects and other pre-expropriation fiscal measures. In August 2018, ConocoPhillips entered into a settlement with PDVSA to recover the full amount of this ICC award, plus interest through the payment period, including initial payments totaling approximately $500 million within a period of 90 days from the time of signing of the settlement agreement. The balance of the settlement is to be paid quarterly over a period of four and a half years. Per the settlement, PDVSA recognized the ICC award as a judgment in various jurisdictions, and ConocoPhillips agreed to suspend its legal enforcement actions. ConocoPhillips sent notices of default to PDVSA on October 14 and November 12, 2019, and to date PDVSA has failed to cure its breach. As a result, ConocoPhillips has resumed legal enforcement actions. To date, ConocoPhillips has received approximately $777 million in connection with the ICC award. ConocoPhillips has ensured that the settlement and any actions taken in enforcement thereof meet all appropriate U.S. regulatory requirements, including those related to any applicable sanctions imposed by the U.S. against Venezuela.

In 2016, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against PDVSA under the contracts that had established the Corocoro Project. On August 2, 2019, the ICC Tribunal awarded ConocoPhillips approximately $33 million plus interest under the Corocoro contracts. ConocoPhillips is seeking recognition and enforcement of the award in various jurisdictions. ConocoPhillips has ensured that all the actions related to the award meet all appropriate U.S. regulatory requirements, including those related to any applicable sanctions imposed by the U.S. against Venezuela.

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Beginning in 2017, governmental and other entities in several states/territories in the U.S. have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged climate change impacts. Additional lawsuits with similar allegations are expected to be filed. The amounts claimed by plaintiffs are unspecified and the legal and factual issues are unprecedented, therefore, there is significant uncertainty about the scope of the claims and alleged damages and any potential impact on the Company’s financial condition. ConocoPhillips believes these lawsuits are factually and legally meritless and are an inappropriate vehicle to address the challenges associated with climate change and will vigorously defend against such lawsuits.

Several Louisiana parishes and the State of Louisiana have filed numerous lawsuits under Louisiana’s State and Local Coastal Resources Management Act (SLCRMA) against oil and gas companies, including ConocoPhillips, seeking compensatory damages for contamination and erosion of the Louisiana coastline allegedly caused by historical oil and gas operations. ConocoPhillips entities are defendants in 22 of the lawsuits and will vigorously defend against them. On October 17, 2022, the Fifth Circuit affirmed remand of the lead case to state court and the subsequent request for rehearing was denied. Accordingly, the federal district courts have issued remands to state court. Because Plaintiffs’ SLCRMA theories are unprecedented, there is uncertainty about these claims (both as to scope and damages) and we continue to evaluate our exposure in these lawsuits.

In October 2020, the Bureau of Safety and Environmental Enforcement (BSEE) ordered the prior owners of Outer Continental Shelf (OCS) Lease P-0166, including ConocoPhillips, to decommission the lease facilities, including two offshore platforms located near Carpinteria, California. This order was sent after the current owner of OCS Lease P-0166 relinquished the lease and abandoned the lease platforms and facilities. BSEE’s order to ConocoPhillips is premised on its connection to Phillips Petroleum Company, a legacy company of ConocoPhillips, which held a historical 25 percent interest in this lease and operated these facilities, but sold its interest approximately 30 years ago. ConocoPhillips continues to evaluate its exposure in this matter.

On May 10, 2021, ConocoPhillips filed arbitration under the rules of the Singapore International Arbitration Centre (SIAC) against Santos KOTN Pty Ltd. and Santos Limited for their failure to timely pay the $200 million bonus due upon final investment decision of the Barossa development project under the sale and purchase agreement for the sale of our Australia-West asset and operations. The matter was resolved in April 2023 to our satisfaction.

In July 2021, a federal securities class action was filed against Concho, certain of Concho’s officers, and ConocoPhillips as Concho’s successor in the United States District Court for the Southern District of Texas. On October 21, 2021, the court issued an order appointing Utah Retirement Systems and the Construction Laborers Pension Trust for Southern California as lead plaintiffs (Lead Plaintiffs). On January 7, 2022, the Lead Plaintiffs filed their consolidated complaint alleging that Concho made materially false and misleading statements regarding its business and operations in violation of the federal securities laws and seeking unspecified damages, attorneys’ fees, costs, equitable/injunctive relief, and such other relief that may be deemed appropriate. The defendants filed a motion to dismiss the consolidated complaint on March 8, 2022. On June 23, 2023, the court denied defendants’ motion as to most defendants including Concho/ConocoPhillips. We believe the allegations in the action are without merit and are vigorously defending this litigation.

ConocoPhillips is involved in pending disputes with commercial counterparties relating to the propriety of its force majeure notices following Winter Storm Uri in 2021. We believe these claims are without merit and are vigorously defending them.

Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements

We have certain throughput agreements and take-or-pay agreements in support of financing arrangements. The agreements typically provide for natural gas or crude oil transportation and LNG purchase commitments. The fixed and determinable portion of the remaining estimated payments under these various agreements as of December 31, 2023 are: 2024—$7 million; 2025—$7 million; 2026—$7 million; 2027—$7 million; 2028—$283 million; and 2029 and after—$11 billion. Generally, variable components of these obligations include commodity futures prices and inflation rates. Purchases of LNG under these commitments are expected to be offset in the same or approximately same periods by cash received from the related sales transactions. Total payments under the agreements were $26 million in 2023, $26 million in 2022 and $27 million in 2021.

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Note 12—Derivative and Financial Instruments

We use futures, forwards, swaps and options in various markets to meet our customer needs, capture market opportunities and manage foreign exchange currency risk.

Commodity Derivative Instruments

Our commodity business primarily consists of natural gas, crude oil, bitumen, NGLs, LNG and power.

Commodity derivative instruments are held at fair value on our consolidated balance sheet. Where these balances have the right of setoff, they are presented on a net basis. Related cash flows are recorded as operating activities on our consolidated statement of cash flows. On our consolidated income statement, gains and losses are recognized either on a gross basis if directly related to our physical business or a net basis if held for trading. Gains and losses related to contracts that meet and are designated with the NPNS exception are recognized upon settlement. We generally apply this exception to eligible crude contracts and certain gas contracts. We do not apply hedge accounting for our commodity derivatives.

The following table presents the gross fair values of our commodity derivatives, excluding collateral, on our consolidated balance sheet:

			Millions of Dollars
			2023			2022
Assets
Prepaid expenses and other current assets			$	611		1,795
Other assets			113			242
Liabilities
Other accruals			567			1,800
Other liabilities and deferred credits			80			210

The gains (losses) from commodity derivatives included in our consolidated income statement are presented in the following table:

			Millions of Dollars
			2023			2022			2021
Sales and other operating revenues			$	86		(88)			(228)
Other income			(6)			(5)			25
Purchased commodities			(90)			(91)			75

On January 15, 2021, we assumed financial derivative instruments consisting of oil and natural gas swaps in connection with the acquisition of Concho. At the acquisition date, these financial derivative instruments acquired were recognized at fair value as a net liability of $456 million with settlement dates under the contracts through December 31, 2022. During 2021, we recognized a loss on settlement of these derivatives contracts of $305 million. This loss is recorded within the “Sales and other operating revenues” line on our consolidated income statement. In connection with the settlement, we issued a cash payment of $761 million during 2021 which is included within “Cash Flows From Operating Activities” on our consolidated statement of cash flows.

The table below summarizes our net exposures resulting from outstanding commodity derivative contracts:

			Open Position Long/(Short)
			2023			2022
Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price			(12)			(14)
Basis			(2)			(8)

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Interest Rate Derivative Instruments

During 2023, PALNG executed interest rate swaps that had the effect of converting 60 percent of the projected term loans outstanding to finance the cost of development and construction of Phase 1 from floating to fixed rate. These swaps were designated and qualify for hedge accounting under ASC Topic 815, “Derivatives and Hedging,” as a cash flow hedge with changes in the fair value of the designated hedging instruments reported as a component of other comprehensive income and reclassified into earnings in the same periods that the hedged transactions will affect earnings. We recognize our proportionate share of PALNG’s adjustments for other comprehensive income as a change to our equity method investment with corresponding adjustments in equity. For the year ended December 31, 2023, we recognized an unrealized gain of $78 million in other comprehensive income related to these swaps.

Financial Instruments

We invest in financial instruments with maturities based on our cash forecasts for the various accounts and currency pools we manage. The types of financial instruments in which we currently invest include:

• Time deposits: Interest bearing deposits placed with financial institutions for a predetermined amount of time.

• Demand deposits: Interest bearing deposits placed with financial institutions. Deposited funds can be withdrawn without notice.

• Commercial paper: Unsecured promissory notes issued by a corporation, commercial bank or government agency purchased at a discount to mature at par.

• U.S. government or government agency obligations: Securities issued by the U.S. government or U.S. government agencies.

• Foreign government obligations: Securities issued by foreign governments.

• Corporate bonds: Unsecured debt securities issued by corporations.

• Asset-backed securities: Collateralized debt securities.

The following investments are carried on our consolidated balance sheet at cost, plus accrued interest and the table reflects remaining maturities at December 31, 2023 and 2022:

			Millions of Dollars
			Carrying Amount
			Cash and Cash Equivalents						Short-Term Investments
			2023			2022			2023			2022
Cash			$	474		593
Demand Deposits			1,424			1,638
Time Deposits
1 to 90 days			3,713			4,116			511			1,288
91 to 180 days									22			883
Within one year									3			11
U.S. Government Obligations
1 to 90 days			24			14			—			—
			$	5,635		6,361			536			2,182

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The following investments in debt securities classified as available for sale are carried at fair value on our consolidated balance sheet at December 31, 2023 and 2022:

			Millions of Dollars
			Carrying Amount
			Cash and Cash Equivalents						Short-Term Investments						Investments and Long-Term Receivables
			2023			2022			2023			2022			2023			2022
Major Security Type
Corporate Bonds			$	—		—			201			323			606			309
Commercial Paper			—			97			131			156
U.S. Government Obligations			—			—			89			115			189			63
U.S. Government Agency Obligations									5			8			7			5
Foreign Government Obligations									7			—			4			7
Asset-backed Securities									2			1			183			138
			$	—		97			435			603			989			522

Cash and Cash Equivalents and Short-Term Investments have remaining maturities within one year. Investments and Long-Term Receivables have remaining maturities that vary from greater than one year through five years.

The following table summarizes the amortized cost basis and fair value of investments in debt securities classified as available for sale at December 31:

			Millions of Dollars
			Amortized Cost Basis						Fair Value
			2023			2022			2023			2022
Major Security Type
Corporate Bonds			$	806		641			807			632
Commercial Paper			131			253			131			253
U.S. Government Obligations			278			181			278			178
U.S. Government Agency Obligations			12			13			12			13
Foreign Government Obligations			11			7			11			7
Asset-backed Securities			184			139			185			139
			$	1,422		1,234			1,424			1,222

As of December 31, 2023, total unrealized gains for debt securities classified as available for sale with net unrealized gains were $5 million and as of December 31, 2022, total unrealized losses for debt securities classified as available for sale with net unrealized losses were $12 million. No allowance for credit losses has been recorded on investments in debt securities which are in an unrealized loss position.

For the years ended December 31, 2023 and 2022, proceeds from sales and redemptions of investments in debt securities classified as available for sale were $983 million and $644 million, respectively. Gross realized gains and losses included in earnings from those sales and redemptions were negligible. The cost of securities sold and redeemed is determined using the specific identification method.

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Credit Risk

Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, short-term investments, long-term investments in debt securities, OTC derivative contracts and trade receivables. Our cash equivalents and short-term investments are placed in high-quality commercial paper, government money market funds, U.S. government and government agency obligations, time deposits with major international banks and financial institutions, high-quality corporate bonds, foreign government obligations and asset-backed securities. Our long-term investments in debt securities are placed in high-quality corporate bonds, asset-backed securities, U.S. government and government agency obligations, foreign government obligations, and time deposits with major international banks and financial institutions.

The credit risk from our OTC derivative contracts, such as forwards, swaps and options, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because these trades are cleared primarily with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.

Our trade receivables result primarily from our petroleum operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less, and we continually monitor this exposure and the creditworthiness of the counterparties. We may require collateral to limit the exposure to loss including, letters of credit, prepayments and surety bonds, as well as master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due to us.

Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of credit as collateral, such as transactions administered through the New York Mercantile Exchange.

The aggregate fair value of all derivative instruments with such credit risk-related contingent features that were in a liability position on December 31, 2023 and December 31, 2022, was $181 million and $333 million, respectively. For these instruments, no collateral was posted as of December 31, 2023 and $42 million collateral was posted as of December 31, 2022. If our credit rating had been downgraded below investment grade on December 31, 2023, we would have been required to post $152 million of additional collateral, either with cash or letters of credit.

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Note 13—Fair Value Measurement

We carry a portion of our assets and liabilities at fair value that are measured at the reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclosed according to the quality of valuation inputs under the fair value hierarchy.

The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. There were no material transfers into or out of Level 3 during 2023 or 2022.

Recurring Fair Value Measurement

Financial assets and liabilities reported at fair value on a recurring basis primarily include our investments in debt securities classified as available for sale, commodity derivatives, and our contingent consideration arrangement related to the Surmont acquisition. See Note 3.

• Level 1 derivative assets and liabilities primarily represent exchange-traded futures and options that are valued using unadjusted prices available from the underlying exchange. Level 1 financial assets also include our investments in U.S. government obligations classified as available for sale debt securities, which are valued using exchange prices.

• Level 2 derivative assets and liabilities primarily represent OTC swaps, options and forward purchase and sale contracts that are valued using adjusted exchange prices, prices provided by brokers or pricing service companies that are all corroborated by market data. Level 2 financial assets also include our investments in debt securities classified as available for sale including investments in corporate bonds, commercial paper, asset-backed securities, U.S. government agency obligations and foreign government obligations that are valued using pricing provided by brokers or pricing service companies that are corroborated with market data.

• Level 3 derivative assets and liabilities consist of OTC swaps, options and forward purchase and sale contracts where a significant portion of fair value is calculated from underlying market data that is not readily available. The derived value uses industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value. Level 3 commodity derivative activity was not material for all periods presented.

• Level 3 liabilities include the fair value of future quarterly contingent payments to Total Energies EP Canada Ltd. in connection with the acquisition of the remaining 50 percent working interest in Surmont. Contingent consideration consists of payments up to approximately $0.4 billion CAD over a five-year term ending in the fourth quarter of 2028. The contingent payments represent $2.0 million for every dollar that the monthly WCS average pricing exceeds $52 per barrel. The terms include adjustments related to not achieving certain production targets. The fair value of the contingent consideration as of December 31, 2023 is calculated using the income approach and is largely based on the estimated commodity price outlook using a combination of external pricing service companies' and our internal price outlook (unobservable input) and a discount rate consistent with those used by principal market participants (observable input). Impact of other unobservable inputs on the fair value as of December 31, 2023 was not significant.

The following table summarizes the fair value hierarchy for gross financial assets and liabilities (i.e., unadjusted where the right of setoff exists for commodity derivatives accounted for at fair value on a recurring basis):

			Millions of Dollars
			December 31, 2023															December 31, 2022
			Level 1			Level 2			Level 3			Total						Level 1			Level 2			Level 3			Total
Assets
Investments in debt securities			$	278		1,146			—			1,424						178			1,044			—			1,222
Commodity derivatives			308			301			115			724						958			951			128			2,037
Total assets			$	586		1,447			115			2,148						1,136			1,995			128			3,259
Liabilities
Commodity derivatives			$	350		283			14			647						906			843			261			2,010
Contingent consideration			—			—			312			312						—			—			—			—
Total liabilities			$	350		283			326			959						906			843			261			2,010

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The range and arithmetic average of the significant unobservable input used in the Level 3 fair value measurement was as follows:

			Fair Value (Millions of Dollars)			Valuation Technique			Unobservable Input			Range (Arithmetic Average)
December 31, 2023
Contingent consideration - Surmont			$	312		Discounted cash flow			Commodity price outlook* ($/BOE)			$45.48 - $63.04 ($57.45)

*Commodity price outlook based on a combination of external pricing service companies' outlooks and our internal outlook.

The following table summarizes those commodity derivative balances subject to the right of setoff as presented on our consolidated balance sheet. We have elected to offset the recognized fair value amounts for multiple derivative instruments executed with the same counterparty in our financial statements when a legal right of setoff exists.

			Millions of Dollars
									Amounts Subject to Right of Setoff
			Gross Amounts Recognized			Amounts Not Subject to Right of Setoff			Gross Amounts			Gross Amounts Offset			Net Amounts Presented			Cash Collateral			Net Amounts
December 31, 2023
Assets			$	724		39			685			375			310			4			306
Liabilities			647			34			613			375			238			47			191
December 31, 2022
Assets			$	2,037		39			1,998			1,176			822			37			785
Liabilities			2,010			20			1,990			1,176			814			52			762

At December 31, 2023 and December 31, 2022, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.

Non-Recurring Fair Value Measurement

The following table summarizes the fair value hierarchy by major category and date of remeasurement for assets accounted for at fair value on a non-recurring basis:

			Millions of Dollars
						Fair Value Measurements Using
			Fair Value			Level 1 Inputs			Level 2 Inputs			Level 3 Inputs			Before-Tax Loss
Year ended December 31, 2021
Net PP&E (held for use)
December 31, 2021			$	472		—			—			472			80
Equity Method Investments
December 31, 2021			5,574			—			5,574			—			688

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Net PP&E (held for use)

During 2021, the estimated fair value of certain noncore assets included in our Lower 48 segment declined to amounts below the carrying values. The carrying values were written down to fair value. The fair values were estimated based on internal discounted cash flow models using the following estimated assumptions: estimated future production, an outlook of future prices from a combination of exchanges (short-term) coupled with pricing service companies and our internal outlook (long-term), future operating costs and capital expenditures, and a discount rate believed to be consistent with those used by principal market participants. The range and arithmetic average of significant unobservable inputs used in the Level 3 fair value measurements for significant assets were as follows:

			Fair Value (Millions of Dollars)			Valuation Technique			Unobservable Inputs			Range (Arithmetic Average)
December 31, 2021
Lower 48 Gulf Coast and Rockies noncore field			$	472		Discounted cash flow			Commodity production (MBOED)			0.2 - 17 (5.4)
									Commodity price outlook* ($/BOE)			$41.45 - $93.68 ($64.39)
									Discount rate**			7.3% - 9.7% (8.7%)

*Commodity price outlook based on a combination of external pricing service companies' and our internal outlook for years 2024-2050; future prices escalated at 2.0 percent annually after year 2050.

**Determined as the weighted average cost of capital of a group of peer companies, adjusted for risks where appropriate.

Equity Method Investments

During 2021, Origin Energy Limited agreed to the sale of 10 percent of their interest in APLNG for $1.645 billion, before customary adjustments. ConocoPhillips announced in December 2021 that we were exercising our preemption right under the APLNG Shareholders Agreement to purchase an additional 10 percent shareholding interest in APLNG, subject to government approvals. The sales price associated with this preemption right was determined to reflect a relevant observable market participant view of APLNG’s fair value which was below the carrying value of our existing investment in APLNG. As such, our investment in APLNG was written down to its fair value of $5,574 million, resulting in a before-tax charge of $688 million. See Note 4 and Note 7.

Reported Fair Values of Financial Instruments

We used the following methods and assumptions to estimate the fair value of financial instruments:

• Cash and cash equivalents and short-term investments: The carrying amount reported on the balance sheet approximates fair value. For those investments classified as available for sale debt securities, the carrying amount reported on the balance sheet is fair value.

• Accounts and notes receivable (including long-term and related parties): The carrying amount reported on the balance sheet approximates fair value.

• Investments in debt securities classified as available for sale: The fair value of investments in debt securities categorized as Level 1 in the fair value hierarchy is measured using exchange prices. The fair value of investments in debt securities categorized as Level 2 in the fair value hierarchy is measured using pricing provided by brokers or pricing service companies that are corroborated with market data. See Note 12.

• Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts payable and floating-rate debt reported on the balance sheet approximates fair value.

• Fixed-rate debt: The estimated fair value of fixed-rate debt is measured using prices available from a pricing service that is corroborated by market data; therefore, these liabilities are categorized as Level 2 in the fair value hierarchy.

• Commercial paper: The carrying amount of our commercial paper instruments approximates fair value and is reported on the balance sheet as short-term debt.

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The following table summarizes the net fair value of financial instruments (i.e., adjusted where the right of setoff exists for commodity derivatives):

			Millions of Dollars
			Carrying Amount									Fair Value
			2023			2022						2023			2022
Financial assets
Commodity derivatives			345			824						345			824
Investments in debt securities			1,424			1,222						1,424			1,222
Financial liabilities
Total debt, excluding finance leases			17,808			15,323						18,621			15,545
Commodity derivatives			225			782						225			782

Note 14—Equity

Common Stock

The changes in our shares of common stock, as categorized in the equity section of the balance sheet, were:

			Shares
			2023			2022			2021
Issued
Beginning of year			2,100,885,134			2,091,562,747			1,798,844,267
Acquisition of Concho			—			—			285,928,872
Distributed under benefit plans			2,887,382			9,322,387			6,789,608
End of year			2,103,772,516			2,100,885,134			2,091,562,747
Held in Treasury
Beginning of year			877,029,062			789,319,875			730,802,089
Repurchase of common stock			48,641,899			87,709,187			58,517,786
End of year			925,670,961			877,029,062			789,319,875

Preferred Stock

We have authorized 500 million shares of preferred stock, par value $0.01 per share, none of which was issued or outstanding at December 31, 2023 or 2022.

Repurchase of Common Stock

In late 2016, we initiated our current share repurchase program. In October 2022, our Board of Directors approved an increase to our authorization from $25 billion to $45 billion of our common stock to support our plan for future share repurchases. Share repurchases since inception of our current program totaled 383 million shares at a cost of $29 billion through the end of December 2023.

In May 2021, we began a paced monetization of our CVE common shares, the proceeds of which have been applied to share repurchases. During the first quarter of 2022, we sold our remaining 91 million CVE common shares.

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Note 15—Non-Mineral Leases

The company primarily leases office buildings and drilling equipment, as well as ocean transport vessels, tugboats, corporate aircraft, and other facilities and equipment. Certain leases include escalation clauses for adjusting rental payments to reflect changes in price indices, and other leases include payment provisions that vary based on the nature of usage of the leased asset. Additionally, the company has executed certain leases that provide it with the option to extend or renew the term of the lease, terminate the lease prior to the end of the lease term, or purchase the leased asset as of the end of the lease term. In other cases, the company has executed lease agreements that require it to guarantee the residual value of certain leased office buildings. For additional information about guarantees, see Note 10. There are no significant restrictions imposed on us by the lease agreements with regard to dividends, asset dispositions or borrowing ability.

We determine if an arrangement is or contains a lease at contract inception. Certain contractual arrangements may contain both lease and non-lease components. Only the lease components of these contractual arrangements are subject to the provisions of ASC Topic 842, and any non-lease components are subject to other applicable accounting guidance; however, we have elected to adopt the optional practical expedient not to separate lease components apart from non-lease components for existing asset classes (as of the adoption date of ASC 842) for accounting purposes. For contractual arrangements involving a new leased asset class, we determine at contract inception whether it will apply the optional practical expedient to the new leased asset class.

Leases are evaluated for classification as operating or finance leases at the commencement date of the lease and right-of-use assets and corresponding liabilities are recognized on our consolidated balance sheet based on the present value of future lease payments relating to the use of the underlying asset during the lease term. Future lease payments include variable lease payments that depend upon an index or rate using the index or rate at the commencement date and probable amounts owed under residual value guarantees. The amount of future lease payments may be increased to include additional payments related to lease extension, termination, and/or purchase options when the company has determined, at or subsequent to lease commencement, generally due to limited asset availability or operating commitments, it is reasonably certain of exercising such options. We use our incremental borrowing rate as the discount rate in determining the present value of future lease payments, unless the interest rate implicit in the lease arrangement is readily determinable. Lease payments that vary subsequent to the commencement date based on future usage levels, the nature of leased asset activities, or certain other contingencies are not included in the measurement of lease right-of-use assets and corresponding liabilities. We have elected not to record assets and liabilities on our consolidated balance sheet for lease arrangements with terms of 12 months or less.

We often enter into leasing arrangements acting in the capacity as operator for and/or on behalf of certain oil and gas joint ventures of undivided interests. If the lease arrangement can be legally enforced only against us as operator and there is no separate arrangement to sublease the underlying leased asset to our coventurers, we recognize at lease commencement a right-of-use asset and corresponding lease liability on our consolidated balance sheet on a gross basis. While we record lease costs on a gross basis in our consolidated income statement and statement of cash flows, such costs are offset by the reimbursement we receive from our coventurers for their share of the lease cost as the underlying leased asset is utilized in joint venture activities. As a result, lease cost is presented in our consolidated income statement and statement of cash flows on a proportional basis. If we are a nonoperating coventurer, we recognize a right-of-use asset and corresponding lease liability only if we were a specified contractual party to the lease arrangement and the arrangement could be legally enforced against us. In this circumstance, we would recognize both the right-of-use asset and corresponding lease liability on our consolidated balance sheet on a proportional basis consistent with our undivided interest ownership in the related joint venture.

The company has historically recorded finance lease assets and liabilities associated with certain oil and gas joint ventures on a proportional basis pursuant to accounting guidance applicable prior to the adoption date of ASC 842. In accordance with the transition provisions of ASC Topic 842, and since we have elected to adopt the package of optional transition-related practical expedients, the historical accounting treatment for these leases has been carried forward and is subject to reconsideration upon the modification or other required reassessment of the arrangements prior to lease term expiration.

109			ConocoPhillips 2023 10-K

Notes to Consolidated Financial Statements			Table of Contents

The following table summarizes the right-of-use assets and lease liabilities for both the operating and finance leases on our consolidated balance sheet as of December 31:

			Millions of Dollars
			2023						2022
			Operating Leases			Finance Leases			Operating Leases			Finance Leases
Right-of-Use Assets
Properties, plants and equipment
Gross						2,010						2,043
Accumulated DD&A						(1,185)						(1,022)
Net PP&E*						825						1,021
Other assets			691						536
Lease Liabilities
Short-term debt**						291						284
Other accruals			193						155
Long-term debt***						838						1,036
Other liabilities and deferred credits			504						390
Total lease liabilities			$	697		1,129			545			1,320

** Includes proportionately consolidated finance lease assets of $134 million at December 31, 2023 and $171 million at December 31, 2022.*

*** Includes proportionately consolidated finance lease liabilities of $175 million at December 31, 2023 and $169 million at December 31, 2022.*

**** Includes proportionately consolidated finance lease liabilities of $326 million at December 31, 2023 and $399 million at December 31, 2022.*

The following table summarizes our lease costs:

			Millions of Dollars
			2023			2022			2021
Lease Cost*
Operating lease cost			$	229		212			278
Finance lease cost
Amortization of right-of-use assets			180			189			148
Interest on lease liabilities			35			32			27
Short-term lease cost**			40			94			21
Total lease cost***			$	484		527			474

** The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers.*

*** Short-term leases are not recorded on our consolidated balance sheet.*

**** Variable lease cost and sublease income are immaterial for the periods presented and therefore are not included in the table above.*

The following table summarizes the lease terms and discount rates as of December 31:

			2023			2022
Lease Term and Discount Rate
Weighted-average term (years)
Operating leases			5.83			5.64
Finance leases			5.73			6.60
Weighted-average discount rate (percent)
Operating leases			4.13			2.99
Finance leases			3.39			3.40

ConocoPhillips 2023 10-K			110

The following table summarizes other lease information:

			Millions of Dollars
			2023			2022			2021
Other Information*
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases			$	173		148			204
Operating cash flows from finance leases			33			30			6
Financing cash flows from finance leases			169			166			73
Right-of-use assets obtained in exchange for operating lease liabilities			$	355		114			174
Right-of-use assets obtained in exchange for finance lease liabilities			9			256			447

*The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers. In addition, pursuant to other applicable accounting guidance, lease payments made in connection with preparing another asset for its intended use are reported in the "Cash Flows From Investing Activities" section of our consolidated statement of cash flows.

The following table summarizes future lease payments for operating and finance leases at December 31, 2023:

			Millions of Dollars
			Operating Leases			Finance Leases
Maturity of Lease Liabilities
2024			$	217		358
2025			150			207
2026			113			204
2027			88			161
2028			67			178
Remaining years			153			174
Total*			788			1,282
Less: portion representing imputed interest			(91)			(153)
Total lease liabilities			$	697		$	1,129

*Future lease payments for operating and finance leases commencing on or after January 1, 2019, also include payments related to non-lease components in accordance with our election to adopt the optional practical expedient not to separate lease components apart from non-lease components for accounting purposes. In addition, future payments related to operating and finance leases proportionately consolidated by the company have been included in the table on a proportionate basis consistent with our respective ownership interest in the underlying investee company or oil and gas venture.

111			ConocoPhillips 2023 10-K

Notes to Consolidated Financial Statements			Table of Contents

Note 16—Employee Benefit Plans

Pension and Postretirement Plans

An analysis of the projected benefit obligations for our pension plans and accumulated benefit obligations for our postretirement health and life insurance plans follows:

			Millions of Dollars
			Pension Benefits																		Other Benefits
			2023									2022									2023			2022
			U.S.			Int’l.						U.S.			Int’l.
Change in Benefit Obligation
Benefit obligation at January 1			$	1,478		2,776						1,924			4,124						102			137
Service cost			51			38						58			47						1			1
Interest cost			77			113						62			77						5			4
Plan participant contributions			—			—						—			—						14			16
Plan amendments			—			—						—			—						—			9
Actuarial (gain) loss			40			11						(325)			(847)						22			(27)
Benefits paid			(121)			(124)						(241)			(144)						(37)			(38)
Divestiture			—			—						—			(56)						—			—
Foreign currency exchange rate change			—			52						—			(425)						—			—
Benefit obligation at December 31*			$	1,525		2,866						1,478			2,776						107			102
*Accumulated benefit obligation portion of above at December 31:			$	1,414		2,642						1,384			2,542
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1			$	1,179		2,879						1,664			4,812						—			—
Actual return on plan assets			129			199						(319)			(1,372)						—			—
Company contributions			119			58						75			96						23			22
Plan participant contributions			—			—						—			1						14			16
Benefits paid			(121)			(124)						(241)			(144)						(37)			(38)
Divestiture			—			—						—			(46)						—			—
Foreign currency exchange rate change			—			73						—			(468)						—			—
Fair value of plan assets at December 31			$	1,306		3,085						1,179			2,879						—			—
Funded Status			$	(219)		219						(299)			103						(107)			(102)

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Notes to Consolidated Financial Statements			Table of Contents

			Millions of Dollars
			Pension Benefits																		Other Benefits
			2023									2022									2023			2022
			U.S.			Int’l.						U.S.			Int’l.
Amounts Recognized in the Consolidated Balance Sheet at December 31
Noncurrent assets			$	—		491						—			373						—			—
Current liabilities			(16)			(9)						(28)			(10)						(24)			(32)
Noncurrent liabilities			(203)			(263)						(271)			(260)						(83)			(70)
Total recognized			$	(219)		219						(299)			103						(107)			(102)
Weighted-Average Assumptions Used to Determine Benefit Obligations at December 31
Discount rate			5.35		%	4.10						5.65			4.20						5.30			5.65
Rate of compensation increase			5.00			3.65						5.00			3.65
Interest crediting rate for applicable benefits			4.20									3.55
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31
Discount rate			5.65		%	4.20						3.85			2.15						5.65			2.65
Expected return on plan assets			5.30			5.20						3.90			2.85
Rate of compensation increase			5.00			3.65						4.00			3.40
Interest crediting rate for applicable benefits			3.55									2.50

For both U.S. and international pension plans, the overall expected long-term rate of return is developed from the expected future return of each asset class, weighted by the expected allocation of pension assets to that asset class. We rely on a variety of independent market forecasts in developing the expected rate of return for each class of assets.

During 2023, the actuarial losses related to the benefit obligations for U.S. and international plans were primarily related to a decrease in the discount rates. During 2022 and 2021, the actuarial gains related to the benefit obligations for U.S. and international plans were primarily related to an increase in the discount rates.

The following tables summarize information related to the Company's pension plans with projected and accumulated benefit obligations in excess of the fair value of the plans' assets:

			Millions of Dollars
			Pension Benefits
			2023									2022
			U.S.			Int’l.						U.S.			Int’l.
Pension Plans with Projected Benefit Obligation in Excess of Plan Assets
Projected benefit obligation			$	1,525		279						1,478			277
Fair value of plan assets			1,306			6						1,179			6
Pension Plans with Accumulated Benefit Obligation in Excess of Plan Assets
Accumulated benefit obligation			$	165		243						1,384			239
Fair value of plan assets			—			6						1,179			6

113			ConocoPhillips 2023 10-K

Notes to Consolidated Financial Statements			Table of Contents

Included in accumulated other comprehensive income (loss) at December 31 were the following before-tax amounts that had not been recognized in net periodic benefit cost:

			Millions of Dollars
			Pension Benefits																		Other Benefits
			2023									2022									2023			2022
			U.S.			Int’l.						U.S.			Int’l.
Unrecognized net actuarial loss (gain)			$	123		585						172			681						3			(28)
Unrecognized prior service cost (credit)			—			1						—			1						(60)			(98)

			Millions of Dollars
			Pension Benefits																		Other Benefits
			2023									2022									2023			2022
			U.S.			Int’l.						U.S.			Int’l.
Sources of Change in Other Comprehensive Income (Loss)
Net gain (loss) arising during the period			$	30		29						(44)			(606)						(22)			27
Amortization of actuarial loss included in income (loss)*			18			67						61			11						(3)			—
Net change during the period			$	48		96						17			(595)						(25)			27
Prior service credit (cost) arising during the period			$	—		—						—			(1)						—			(9)
Amortization of prior service (credit) included in income (loss)			—			—						—			(1)						(38)			(38)
Net change during the period			$	—		—						—			(2)						(38)			(47)

*Includes settlement (gains) losses recognized in 2023 and 2022.

The components of net periodic benefit cost of all defined benefit plans are presented in the following table:

			Millions of Dollars
			Pension Benefits																											Other Benefits
			2023									2022									2021									2023			2022			2021
			U.S.			Int’l.						U.S.			Int’l.						U.S.			Int’l.
Components of Net Periodic Benefit Cost
Service cost			$	51		38						58			47						73			61						1			1			2
Interest cost			77			113						62			77						53			79						5			4			4
Expected return on plan assets			(58)			(148)						(50)			(124)						(80)			(120)						—			—			—
Amortization of prior service credit			—			—						—			(1)						—			(1)						(38)			(38)			(37)
Recognized net actuarial loss (gain)			12			67						24			11						43			33						(3)			—			—
Settlements loss (gain)			6			—						37			—						102			—						—			—			—
Curtailment loss (gain)			—			—						—			—						12			—						—			—			—
Net periodic benefit cost			$	88		70						131			10						203			52						(35)			(33)			(31)

The components of net periodic benefit cost, other than the service cost component, are included in the “Other expenses” line item on our consolidated income statement.

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Notes to Consolidated Financial Statements			Table of Contents

We recognized pension settlement losses of $6 million in 2023, $37 million in 2022, and $102 million in 2021 as lump-sum benefit payments from certain U.S. and international pension plans exceeded the sum of service and interest costs for those plans and led to recognition of settlement losses.

In determining net pension and other postretirement benefit costs, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. For net actuarial gains and losses, we amortize 10 percent of the unamortized balance each year.

We have multiple non-pension postretirement benefit plans for health and life insurance. The health care plans are contributory and subject to various cost sharing features, most with participant and company contributions adjusted annually; the life insurance plans are noncontributory. The measurement of the U.S. pre-65 retiree medical accumulated postretirement benefit obligation assumes a health care cost trend rate of 7 percent in 2024 that declines to 5 percent by 2031. The measurement of the U.S. post-65 retiree medical accumulated postretirement benefit obligation assumes a health care cost trend rate of 4.5 percent in 2024 that increases to 5 percent by 2030.

Plan Assets

We follow a policy of broadly diversifying pension plan assets across asset classes and individual holdings. As a result, our plan assets have no significant concentrations of credit risk. Asset classes that are considered appropriate include U.S. equities, non-U.S. equities, U.S. fixed income, non-U.S. fixed income, real estate and private equity investments. Plan fiduciaries may consider and add other asset classes to the investment program from time to time. The target allocations for plan assets, aggregated across U.S. and international plans, are 24 percent equity securities, 72 percent debt securities, and 4 percent real estate. Generally, the plan investments are publicly traded, therefore minimizing liquidity risk in the portfolio.

The following is a description of the valuation methodologies used for the pension plan assets. There have been no changes in the methodologies used at December 31, 2023 and 2022.

• Fair values of equity securities and government debt securities categorized in Level 1 are primarily based on quoted market prices in active markets for identical assets and liabilities.

• Fair values of corporate debt securities, agency and mortgage-backed securities and government debt securities categorized in Level 2 are estimated using recently executed transactions and quoted market prices for similar assets and liabilities in active markets and for identical assets and liabilities in markets that are not active. If there have been no market transactions in a particular fixed income security, its fair value is calculated by pricing models that benchmark the security against other securities with actual market prices. When observable quoted market prices are not available, fair value is based on pricing models that use something other than actual market prices (e.g., observable inputs such as benchmark yields, reported trades and issuer spreads for similar securities), and these securities are categorized in Level 3 of the fair value hierarchy.

• Fair values of investments in common/collective trusts are determined by the issuer of each fund based on the fair value of the underlying assets.

• Fair values of mutual funds are based on quoted market prices, which represent the net asset value of shares held.

• Time deposits are valued at cost, which approximates fair value.

• Cash is valued at cost, which approximates fair value. Fair values of international cash equivalents categorized in Level 2 are valued using observable yield curves, discounting and interest rates. U.S. cash balances held in the form of short-term fund units that are redeemable at the measurement date are categorized as Level 2.

• Fair values of exchange-traded derivatives classified in Level 1 are based on quoted market prices. For other derivatives classified in Level 2, the values are generally calculated from pricing models with market input parameters from third-party sources.

• Fair values of insurance contracts are valued at the present value of the future benefit payments owed by the insurance company to the plans’ participants.

• Fair values of real estate investments are valued using real estate valuation techniques and other methods that include reference to third-party sources and sales comparables where available.

115			ConocoPhillips 2023 10-K

Notes to Consolidated Financial Statements			Table of Contents

• A portion of U.S. pension plan assets is held as a participating interest in an insurance annuity contract, which is calculated as the market value of investments held under this contract, less the accumulated benefit obligation covered by the contract. The participating interest is classified as Level 3 in the fair value hierarchy as the fair value is determined via a combination of quoted market prices, recently executed transactions, and an actuarial present value computation for contract obligations. At December 31, 2023, the participating interest in the annuity contract was valued at $46 million and consisted of $130 million in debt securities, less $84 million for the accumulated benefit obligation covered by the contract. At December 31, 2022, the participating interest in the annuity contract was valued at $55 million and consisted of $144 million in debt securities, less $89 million for the accumulated benefit obligation covered by the contract. The participating interest is not available for meeting general pension benefit obligations in the near term. No future company contributions are required and no new benefits are being accrued under this insurance annuity contract.

The fair values of our pension plan assets at December 31, by asset class were as follows:

			Millions of Dollars
			U.S.															International
			Level 1			Level 2			Level 3			Total						Level 1			Level 2			Level 3			Total
2023
Equity securities
U.S.			$	6		—			—			6						—			—			—			—
International			35			—			—			35						—			—			—			—
Mutual funds			15			—			—			15						244			276			—			520
Debt securities
Corporate			—			1			—			1						—			—			—			—
Mutual funds			—			—			—			—						421			—			—			421
Cash and cash equivalents			—			—			—			—						25			—			—			25
Real estate			—			—			—			—						—			—			126			126
Total in fair value hierarchy			$	56		1			—			57						690			276			126			1,092
Investments measured at net asset value*
Equity securities
Common/collective trusts												300															198
Debt securities
Common/collective trusts												868															1,791
Cash and cash equivalents												6															—
Real estate												28															—
Total**			$	56		1			—			1,259						690			276			126			3,081

*In accordance with FASB ASC Topic 715, “Compensation—Retirement Benefits,” certain investments that are to be measured at fair value using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Change in Fair Value of Plan Assets.

**Excludes the participating interest in the insurance annuity contract with a net asset of $46 million and net receivables related to security transactions of $5 million.

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Notes to Consolidated Financial Statements			Table of Contents

The fair values of our pension plan assets at December 31, by asset class were as follows:

			Millions of Dollars
			U.S.															International
			Level 1			Level 2			Level 3			Total						Level 1			Level 2			Level 3			Total
2022
Equity securities
U.S.			$	4		—			—			4						—			—			—			—
International			36			—			—			36						—			—			—			—
Mutual funds			14			—			—			14						201			298			—			499
Debt securities
Corporate			—			1			—			1						—			—			—			—
Mutual funds			—			—			—			—						365			—			—			365
Cash and cash equivalents			—			—			—			—						36			—			—			36
Derivatives
Real estate			—			—			—			—						—			—			146			146
Total in fair value hierarchy			$	54		1			—			55						602			298			146			1,046
Investments measured at net asset value*
Equity securities
Common/collective trusts												265															192
Debt securities
Common/collective trusts												759															1,637
Cash and cash equivalents												10															—
Real estate												34															—
Total**			$	54		1			—			1,123						602			298			146			2,875

*In accordance with FASB ASC Topic 715, “Compensation—Retirement Benefits,” certain investments that are to be measured at fair value using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Change in Fair Value of Plan Assets.

**Excludes the participating interest in the insurance annuity contract with a net asset of $55 million and net receivables related to security transactions of $5 million.

Level 3 activity was not material for all periods.

Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code of 1986, as amended. Contributions to foreign plans are dependent upon local laws and tax regulations. In 2024, we expect to contribute approximately $125 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $75 million to our international qualified and nonqualified pension and postretirement benefit plans.

117			ConocoPhillips 2023 10-K

Notes to Consolidated Financial Statements			Table of Contents

The following benefit payments, which are exclusive of amounts to be paid from the insurance annuity contract and which reflect expected future service, as appropriate, are expected to be paid:

			Millions of Dollars
			Pension Benefits									Other Benefits
			U.S.			Int’l.
2024			$	205		128						16
2025			191			130						14
2026			175			133						14
2027			170			136						12
2028			162			141						11
2029–2033			664			778						45

The following table summarizes our severance accrual activity:

			Millions of Dollars
			2023			2022			2021
Balance at January 1			$	31		78			24
Accruals			1			1			170
Benefit payments			(20)			(48)			(116)
Balance at December 31			$	12		31			78

Accruals include severance costs associated with our company-wide restructuring program. Of the remaining balance at December 31, 2023, $3 million is classified as short-term.

Defined Contribution Plans

Most U.S. employees are eligible to participate in the ConocoPhillips Savings Plan (CPSP). Employees can contribute up to 75 percent of their eligible pay, subject to statutory limits, in the CPSP to a choice of 17 investment options. Employees who participate in the CPSP and contribute 1 percent of their eligible pay receive a 6 percent company cash match with a potential company discretionary cash contribution of up to 6 percent. Effective January 1, 2019, new employees, rehires and employees that elected to opt out of Title II of the ConocoPhillips Retirement Plan are eligible to receive a Company Retirement Contribution (CRC) of 6 percent of eligible pay into their CPSP. After three years of service with the company, the employee is 100 percent vested in any CRC. Company contributions charged to expense for the CPSP and predecessor plans were $151 million in 2023, $140 million in 2022 and $93 million in 2021.

We have several defined contribution plans for our international employees, each with its own terms and eligibility depending on location. Total compensation expense recognized for these international plans was approximately $23 million in 2023, $24 million in 2022 and $26 million in 2021.

Share-Based Compensation Plans

The 2023 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (Omnibus Plan) was approved by shareholders in May 2023, replacing similar prior plans and providing that no new awards shall be granted under the prior plans. Over its 10-year life, the Omnibus Plan allows the issuance of up to 36 million shares of our common stock for compensation to our employees and directors, but the available shares (i) are reduced by awards granted under the prior plan between the board adoption date (February 15, 2023) and the shareholder approval date (May 16, 2023) and (ii) are increased by any shares of common stock represented by awards granted under the Omnibus Plan or the prior plans that are forfeited, expire or are cancelled without delivery of shares of common stock or which result in the forfeiture of shares of common stock back to the company, excluding shares surrendered in payment of the exercise of a stock option or stock appreciation right, shares not issued in connection with the stock settlement of a stock appreciation right, or shares reacquired by the company using cash proceeds from the exercise of a stock option. The Human Resources and Compensation Committee of our Board of Directors is authorized to determine the types, terms, conditions and limitations of awards granted. Awards may be granted in the form of, but not limited to, stock options, restricted stock units and performance share units to employees and non-employee directors who contribute to the company’s continued success and profitability.

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Notes to Consolidated Financial Statements			Table of Contents

Total share-based compensation expense is measured using the grant date fair value for our equity-classified awards and the settlement date fair value for our liability-classified awards. We recognize share-based compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the award) or, for awards that provide for retirement-based vesting, the period beginning at the start of the service period and ending upon the later to occur of the date when an employee first becomes eligible for retirement or the date that is six months after the grant date (generally the minimum period of time required for an award to not be subject to forfeiture). Other than certain retention awards, our share-based compensation programs generally provide accelerated vesting (i.e., a waiver of the remaining period of service required to earn an award) for awards held by employees at the time of their retirement. Some of our share-based awards vest ratably (i.e., portions of the award vest at different times) while some of our awards cliff vest (i.e., all of the award vests at the same time). We recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.

Compensation Expense—Total share-based compensation expense recognized in net income (loss) and the associated tax benefit were:

			Millions of Dollars
			2023			2022			2021
Compensation cost			$	334		377			304
Tax benefit			84			95			76

Stock Options—Stock options granted under the provisions of the Omnibus Plan and prior plans permit purchase of our common stock at exercise prices equivalent to the average fair market value of ConocoPhillips common stock on the date the options were granted. The options have terms of 10 years and generally vest ratably, with one-third of the options awarded vesting and becoming exercisable on each anniversary date following the date of grant. Options awarded to certain employees already eligible for retirement vest within six months of the grant date, but those options do not become exercisable until the end of the normal vesting period. Beginning in 2018, stock option grants were discontinued and replaced with three-year, time-vested restricted stock units which generally were cash-settled for 2018 and 2019 awards and will be stock-settled beginning with 2020 awards.

The following summarizes our stock option activity for the year ended December 31, 2023:

															Millions of Dollars
			Options						Weighted-Average Exercise Price						Aggregate Intrinsic Value
Outstanding at December 31, 2022			4,303,575						$	55.28					$	266
Exercised			(1,038,900)						63.87						58
Expired or cancelled			—						—
Outstanding at December 31, 2023			3,264,675						$	52.55					$	209
Vested at December 31, 2023			3,264,675						$	52.55					$	209
Exercisable at December 31, 2023			3,264,675						$	52.55					$	209

The weighted-average remaining contractual term of outstanding options, vested options and exercisable options at December 31, 2023, were all 1.98 years. The aggregate intrinsic value of options exercised was $308 million in 2022 and $68 million in 2021.

During 2023, we received $66 million in cash and realized a tax benefit of $12 million from the exercise of options. At December 31, 2023, all outstanding stock options were fully vested and there was no remaining compensation cost to be recorded.

Stock Unit Programs—Restricted stock units (RSU) granted annually under the provisions of the Omnibus Plan and the general and executive RSU programs vest in one installment on the third anniversary of the grant date. RSUs granted under the Omnibus Plan for a variable long-term incentive retention program vest ratably in three equal annual installments beginning on the first anniversary of the grant date. Restricted stock units are also granted ad hoc to attract or retain key personnel, and the terms and conditions under which these restricted stock units vest vary by award.

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Stock-Settled

Upon vesting, these restricted stock units are settled by issuing one share of ConocoPhillips common stock per unit. Units awarded to retirement eligible employees under the general and executive RSU programs vest six months from the grant date; however, those units are not settled through the issuance of common stock until the earlier of separation from the company or the end of the regularly scheduled vesting period. Until issued as stock, most recipients of the RSUs receive a cash payment of a dividend equivalent or an accrued reinvested dividend equivalent that is charged to retained earnings. The grant date fair market value of these RSUs is deemed equal to the average ConocoPhillips stock price on the grant date. The grant date fair market value of RSUs that do not receive a dividend equivalent while unvested is deemed equal to the average ConocoPhillips stock price on the grant date, less the net present value of the estimated dividends that will not be received.

The following summarizes our stock-settled stock RSU activity for the year ended December 31, 2023:

			Stock Units						Weighted-Average Grant Date Fair Value						Millions of Dollars
									Total Fair Value
Outstanding at December 31, 2022			7,578,193						$	61.20
Granted			2,178,117						110.91
Forfeited			(144,021)						88.54
Issued			(2,518,599)						58.77						$	284
Outstanding at December 31, 2023			7,093,690						$	76.78
Not Vested at December 31, 2023			4,791,110						$	78.20

At December 31, 2023, the remaining unrecognized compensation cost from the unvested stock-settled RSUs was $166 million, which will be recognized over a weighted-average period of 1.70 years, the longest period being 2.58 years. The weighted-average grant date fair value of stock-settled RSUs granted during 2022 and 2021 was $90.57 and $46.56, respectively. The total fair value of stock-settled RSUs issued during 2022 and 2021 was $193 million and $144 million, respectively.

Cash-Settled

Cash-settled executive RSUs granted in 2018 and 2019 replaced the stock option program. These RSUs, subject to elections to defer, were settled in cash equal to the fair market value of a share of ConocoPhillips common stock per unit on the settlement date and are classified as liabilities on the balance sheet. Executive RSUs awarded to retirement eligible employees vest six months from the grant date; however, those units were not settled until the earlier of separation from the company or the end of the regularly scheduled vesting period. Compensation expense was initially measured using the average fair market value of ConocoPhillips common stock and was subsequently adjusted, based on changes in the ConocoPhillips stock price through the end of each subsequent reporting period, through the settlement date. Recipients received an accrued reinvested dividend equivalent that was charged to compensation expense. The accrued reinvested dividend was paid at the time of settlement, subject to the terms and conditions of the award. Beginning with executive RSUs granted in 2020, awards will be settled in stock.

There was no cash-settled stock unit activity and no remaining unrecognized compensation cost to be recorded for the unvested cash-settled units for the year ended December 31, 2023. The total fair value of cash-settled executive RSUs issued during 2022 and 2021 were $21 million and $20 million, respectively.

Performance Share Program—Under the Omnibus Plan, we also annually grant restricted performance share units (PSUs) to senior management. These PSUs are authorized three years prior to their effective grant date (the performance period). Compensation expense is initially measured using the average fair market value of ConocoPhillips common stock and is subsequently adjusted, based on changes in the ConocoPhillips stock price through the end of each subsequent reporting period, through the grant date for stock-settled awards and the settlement date for cash-settled awards.

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Stock-Settled

Stock-settled PSUs are settled by issuing one share of ConocoPhillips common stock per unit. For performance periods beginning before 2009, PSUs do not vest until the employee becomes eligible for retirement by reaching age 55 with five years of service, and restrictions do not lapse until the employee separates from the company. With respect to awards for performance periods beginning in 2009 through 2012, PSUs do not vest until the earlier of the date the employee becomes eligible for retirement by reaching age 55 with five years of service or five years after the grant date of the award, and restrictions do not lapse until the earlier of the employee’s separation from the company or five years after the grant date (although recipients can elect to defer the lapsing of restrictions until separation). We recognize compensation expense for these awards beginning on the grant date and ending on the date the PSUs are scheduled to vest. Because these awards are authorized three years prior to the effective grant date, for employees eligible for retirement by or shortly after the grant date, we recognize compensation expense over the period beginning on the date of authorization and ending on the date of grant. Until issued as stock, recipients of the stock-settled PSUs issued prior to 2013 receive a cash payment of a dividend equivalent that is charged to retained earnings. Beginning in 2013, stock-settled PSUs authorized for future grants will vest, absent employee election to defer, upon settlement following the conclusion of the three-year performance period. We recognize compensation expense over the period beginning on the date of authorization and ending on the conclusion of the performance period. Until issued as stock, recipients of these PSUs receive an accrued reinvested dividend equivalent that is charged to compensation expense.

The following summarizes our stock-settled Performance Share Program activity for the year ended December 31, 2023:

									Weighted-Average Grant Date Fair Value						Millions of Dollars
			Stock Units									Total Fair Value
Outstanding at December 31, 2022			1,231,615						$	50.68
Granted			3,797						112.50
Forfeited			(72)						55.13
Issued			(272,522)						51.15						$	29
Outstanding at December 31, 2023			962,818						$	50.79

At December 31, 2023, there was no remaining unrecognized compensation cost to be recorded on the unvested stock-settled performance shares. The weighted-average grant date fair value of stock-settled PSUs granted during 2022 was $91.58; however, there were no stock-settled PSUs granted during 2021. The total fair value of stock-settled PSUs issued during 2022 and 2021 were $21 million and $18 million, respectively.

Cash-Settled

In connection with and immediately following the separation of our Downstream businesses in 2012, grants of new cash-settled PSUs, subject to a shortened performance period, were authorized. Once granted, these PSUs vest, absent employee election to defer, on the earlier of five years after the grant date of the award or the date the employee becomes eligible for retirement. For employees eligible for retirement by or shortly after the grant date, we recognize compensation expense over the period beginning on the date of authorization and ending on the date of grant. Otherwise, we recognize compensation expense beginning on the grant date and ending on the date the PSUs are scheduled to vest. These PSUs are settled in cash equal to the fair market value of a share of ConocoPhillips common stock per unit on the settlement date and thus are classified as liabilities on the balance sheet. Until settlement occurs, recipients of the PSUs receive a cash payment of a dividend equivalent that is charged to compensation expense.

Beginning in 2013, cash-settled PSUs authorized for future grants will vest upon settlement following the conclusion of the three-year performance period. We recognize compensation expense over the period beginning on the date of authorization and ending at the conclusion of the performance period. These PSUs will be settled in cash equal to the fair market value of a share of ConocoPhillips common stock per unit on the settlement date and are classified as liabilities on the balance sheet. For performance periods beginning before 2018, during the performance period, recipients of the PSUs do not receive a cash payment of a dividend equivalent, but after the performance period ends, until settlement in cash occurs, recipients of the PSUs receive a cash payment of a dividend equivalent that is charged to compensation expense. For the performance periods beginning in 2018 or later, recipients of the PSUs receive an accrued reinvested dividend equivalent that is charged to compensation expense. The accrued reinvested dividend is paid at the time of settlement, subject to the terms and conditions of the award.

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The following summarizes our cash-settled Performance Share Program activity for the year ended December 31, 2023:

									Weighted-Average Grant Date Fair Value						Millions of Dollars
			Stock Units									Total Fair Value
Outstanding at December 31, 2022			109,823						$	117.11
Granted			1,044,251						112.50
Settled			(1,053,204)						104.94						$	111
Outstanding at December 31, 2023			100,870						$	116.68

At December 31, 2023, all outstanding cash-settled performance awards were fully vested and there was no remaining compensation cost to be recorded. The weighted-average grant date fair value of cash-settled PSUs granted during 2022 and 2021 was $91.58 and $46.65, respectively. The total fair value of cash-settled performance share awards settled during 2022 and 2021 was $88 million and $52 million, respectively.

From inception of the Performance Share Program through 2013, approved PSU awards were granted after the conclusion of performance periods. Beginning in February 2014, initial target PSU awards are issued near the beginning of new performance periods. These initial target PSU awards will terminate at the end of the performance periods and will be settled after the performance periods have ended. Also in 2014, initial target PSU awards were issued for open performance periods that began in prior years. For the open performance period beginning in 2012, the initial target PSU awards terminated at the end of the three-year performance period and were replaced with approved PSU awards. For the open performance period beginning in 2013, the initial target PSU awards terminated at the end of the three-year performance period and were settled after the performance period ended. There is no effect on recognition of compensation expense.

Other—In addition to the above active programs, we have outstanding shares of restricted stock and restricted stock units that were either issued as part of our non-employee director compensation program for current and former members of the company’s Board of Directors or as part of an executive compensation program that has been discontinued or acquired as a result of an acquisition. Generally, the recipients of the restricted shares or units receive a dividend or dividend equivalent.

The following summarizes the aggregate activity of these restricted shares and units for the year ended December 31, 2023:

									Weighted-Average Grant Date Fair Value						Millions of Dollars
			Stock Units									Total Fair Value
Outstanding at December 31, 2022			1,239,759						$	49.78
Granted			54,141						115.88
Cancelled			(6,904)						45.90
Issued			(392,728)						47.64						$	46
Outstanding at December 31, 2023			894,268						$	54.76
Not Vested at December 31, 2023			149,270						$	45.90

At December 31, 2023, the remaining compensation cost from the unvested restricted stock was negligible, which will be recognized over a weighted-average period of 0.01 years. The weighted-average grant date fair value of awards granted during 2022 and 2021 was $96.20 and $46.43, respectively. The total fair value of awards issued during 2022 and 2021 was $40 million and $8 million, respectively.

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Note 17—Income Taxes

Components of income tax provision (benefit) were:

			Millions of Dollars
			2023						2022						2021
Income Taxes
Federal
Current			$	1,054					1,263						32
Deferred			825						1,629						1,161
Foreign
Current			2,931						5,813						3,128
Deferred			254						387						66
State and local
Current			202						386						127
Deferred			65						70						119
Total tax provision (benefit)			$	5,331					9,548						4,633

Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Major components of deferred tax liabilities and assets at December 31 were:

			Millions of Dollars
			2023			2022
Deferred Tax Liabilities
PP&E and intangibles			$	11,992		11,100
Inventory			46			48
Other			216			190
Total deferred tax liabilities			12,254			11,338
Deferred Tax Assets
Benefit plan accruals			413			450
Asset retirement obligations and accrued environmental costs			2,608			2,333
Investments in joint ventures			2,133			1,917
Other financial accruals and deferrals			448			736
Loss and credit carryforwards			5,629			6,354
Other			121			112
Total deferred tax assets			11,352			11,902
Less: valuation allowance			(7,656)			(8,049)
Total deferred tax assets net of valuation allowance			3,696			3,853
Net deferred tax liabilities			$	8,558		7,485

At December 31, 2023, noncurrent assets and liabilities included deferred taxes of $255 million and $8,813 million, respectively. At December 31, 2022, noncurrent assets and liabilities included deferred taxes of $241 million and $7,726 million, respectively.

At December 31, 2023, the loss and credit carryforward deferred tax assets were primarily related to U.S. foreign tax credit carryforwards of $4.7 billion and various jurisdictions net operating loss and credit carryforwards of $0.9 billion. If not utilized, U.S. foreign tax credits and net operating losses will begin to expire in 2024.

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The following table shows a reconciliation of the beginning and ending deferred tax asset valuation allowance for 2023, 2022 and 2021:

			Millions of Dollars
			2023			2022			2021
Balance at January 1			$	8,049		8,342			9,965
Charged to expense (benefit)			(2)			5			(45)
Other*			(391)			(298)			(1,578)
Balance at December 31			$	7,656		8,049			8,342

*Represents changes due to originating deferred tax assets that have no impact to our effective tax rate, acquisitions/dispositions/revisions and the effect of translating foreign financial statements.

Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than not, be realized. At December 31, 2023, we have maintained a valuation allowance with respect to substantially all U.S. foreign tax credit carryforwards, basis differences in our APLNG investment, and certain net operating loss carryforwards for various jurisdictions. During 2022, the valuation allowance movement charged to earnings primarily relates to the impact of 2022 changes to Norway’s Petroleum Tax System which is partly offset by the U.S. tax impact of the disposition of our CVE common shares. Other movements are primarily related to valuation allowances on expiring tax attributes. Based on our historical taxable income, expectations for the future, and available tax-planning strategies, management expects deferred tax assets, net of valuation allowances, will primarily be realized as offsets to reversing deferred tax liabilities.

During the second quarter of 2022, Norway enacted changes to the Petroleum Tax System. As a result of the enactment, a valuation allowance of $58 million was recorded during the second quarter to reflect changes to our ability to realize certain deferred tax assets under the new law.

During 2021, the valuation allowance movement charged to earnings primarily relates to the fair value measurement of our CVE common shares that are not expected to be realized, and the expected realization of certain U.S. tax attributes associated with our planned disposition of our Indonesia assets. This is partially offset by Australian tax benefits associated with our impairment of APLNG that we do not expect to be realized. Other movements are primarily related to valuation allowances on expiring tax attributes. For more information on our Indonesia disposition see Note 3.

At December 31, 2023, unremitted income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures totaled approximately $4,975 million. Deferred income taxes have not been provided on this amount, as we do not plan to initiate any action that would require the payment of income taxes. The estimated amount of additional tax, primarily local withholding tax, that would be payable on this income if distributed is approximately $249 million.

The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2023, 2022 and 2021:

			Millions of Dollars
			2023			2022			2021
Balance at January 1			$	710		1,345			1,206
Additions based on tax positions related to the current year			5			6			15
Additions for tax positions of prior years			1			6			177
Reductions for tax positions of prior years			(9)			(62)			(5)
Settlements			(96)			(510)			—
Lapse of statute			(224)			(75)			(48)
Balance at December 31			$	387		710			1,345

Included in the balance of unrecognized tax benefits for 2023, 2022 and 2021 were $378 million, $701 million and $1,261 million, respectively, which, if recognized, would impact our effective tax rate.

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The balance of the unrecognized tax benefits decreased in 2023 due to the lapsing of the statute of limitations on certain of our foreign subsidiaries of $224 million as well as the closing of our 2018 Canadian domestic audit that resulted in a reduction of $92 million.

The balance of the unrecognized tax benefits decreased in 2022 due to the closing of the 2017 audit of our federal income tax return. As a result, we recognized federal and state tax benefits totaling $515 million relating to the recovery of outside tax basis previously offset by a full reserve. The balance of the unrecognized tax benefits increased in 2021 mainly due to U.S. tax credits acquired through our Concho acquisition. See Note 3 and Note 11.

At December 31, 2023, 2022 and 2021, accrued liabilities for interest and penalties totaled $45 million, $35 million and $47 million, respectively, net of accrued income taxes. Interest and penalties resulted in a reduction to earnings of $10 million in 2023, an increase of $12 million in 2022 and a reduction to earnings of $1 million in 2021.

We file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions. Audits in major jurisdictions are generally complete as follows: Canada (2016), Norway (2022) and U.S. (2019). Issues in dispute for audited years and audits for subsequent years are ongoing and in various stages of completion in the many jurisdictions in which we operate around the world. Consequently, the balance in unrecognized tax benefits can be expected to fluctuate from period to period. Within the next twelve months, we may have audit periods close that could significantly impact our total unrecognized tax benefits. It is reasonably possible such changes could be significant when compared with our total unrecognized tax benefits, but the amount of change is not estimable.

The amounts of U.S. and foreign income (loss) before income taxes, with a reconciliation of tax at the federal statutory rate to the provision for income taxes, were:

			Millions of Dollars												Percent of Pre-Tax Income (Loss)
			2023			2022			2021						2023			2022			2021
Income (loss) before income taxes
United States			$	9,472		16,739			8,024						58.2		%	59.3			63.1
Foreign			6,816			11,489			4,688						41.8			40.7			36.9
			$	16,288		28,228			12,712						100.0		%	100.0			100.0
Federal statutory income tax			$	3,421		5,928			2,670						21.0		%	21.0			21.0
Non-U.S. effective tax rates			2,063			3,866			1,915						12.7			13.7			15.1
Recovery of outside basis			(4)			(30)			(55)						—			(0.1)			(0.4)
Adjustment to tax reserves			(317)			(551)			(11)						(1.9)			(2.0)			(0.1)
Adjustment to valuation allowance			(2)			5			(45)						—			—			(0.4)
State income tax			214			405			194						1.3			1.4			1.5
Enhanced oil recovery credit			—			(37)			(99)						—			(0.1)			(0.8)
Other			(44)			(38)			64						(0.3)			(0.1)			0.5
Total			$	5,331		9,548			4,633						32.7		%	33.8			36.4

Our effective tax rate for 2023 was driven by our jurisdictional tax rates for this profit mix with a favorable impact from routine tax credits. The adjustment to tax reserves primarily relates to the lapsing of the statute of limitations on certain of our foreign subsidiaries and the closing of the 2018 Canadian domestic audit.

Our effective tax rate for 2022 was driven by our jurisdictional tax rates for this profit mix with net favorable impacts from routine tax credits and valuation allowance adjustments. The adjustment to tax reserves primarily relates to the closing of the audit of our 2017 U.S. federal tax return and the recognition of the U.S. federal and state tax benefits described above.

Our effective tax rate for 2021 was driven by our jurisdictional tax rates for this profit mix with net favorable impacts from routine tax credits and valuation allowance adjustments. The valuation allowance adjustment is primarily related to the fair value measurement and disposition of our CVE common shares of $218 million and the ability to utilize the U.S. foreign tax credit and capital loss carryforward due to our anticipated disposition of our Indonesia entities of $29 million. This was partially offset by an increase to our valuation allowance related to the tax impact of the impairment of our APLNG investment of $206 million for which we do not expect to receive a tax benefit.

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On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022, which among other things, implements a 15 percent minimum tax on book income of certain large corporations, a 1 percent excise tax on net stock repurchases and several tax incentives to promote lower carbon energy. Based upon our current analysis, these law changes are not expected to have a material impact to our consolidated financial statements.

Note 18—Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss) in the equity section of the balance sheet included:

			Millions of Dollars
			Defined Benefit Plans			Net Unrealized Holding Gain/(Loss) on Securities			Foreign Currency Translation			Unrealized Gain/(Loss) on Hedging Activities			Accumulated Other Comprehensive Income/(Loss)
December 31, 2020			$	(425)		2			(4,795)			—			(5,218)
Other comprehensive income (loss)			394			(2)			(124)			—			268
December 31, 2021			(31)			—			(4,919)			—			(4,950)
Other comprehensive income (loss)			(417)			(11)			(622)			—			(1,050)
December 31, 2022			(448)			(11)			(5,541)			—			(6,000)
Other comprehensive income (loss)			55			13			197			62			327
December 31, 2023			$	(393)		2			(5,344)			62			(5,673)

The following table summarizes reclassifications out of accumulated other comprehensive income (loss) during the years ended December 31:

			Millions of Dollars
			2023			2022
Defined Benefit Plans*			$	33		26
*Included in the computation of net periodic benefit cost and are presented net of tax expense of:			$	11		7
See Note 16.

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Note 19—Cash Flow Information

			Millions of Dollars
			2023			2022			2021
Noncash Investing and Financing Activities
Increase (decrease) in PP&E related to an increase (decrease) in asset retirement obligations			$	727		825			442
Fair value of contingent consideration on acquisition			320
Cash Payments
Interest			$	701		873			924
Income taxes			5,406			7,368			856
Net Sales (Purchases) of Investments
Short-term investments purchased			$	(1,463)		(5,046)			(5,554)
Short-term investments sold			3,574			3,102			8,810
Investments and long-term receivables purchased			(867)			(775)			(279)
Investments and long-term receivables sold			129			90			114
			$	1,373		(2,629)			3,091

Income tax payments increased in 2022 as the company returned to a tax paying position in the U.S. as well as, increased taxes in Norway, and timing of tax payments in Libya.

For additional information on cash and non-cash changes to our consolidated balance sheet, see Note 3 and Note 13 for the Surmont acquisition and see Note 3 and Note 12 for the Concho acquisition.

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Note 20—Other Financial Information

			Millions of Dollars
			2023			2022			2021
Interest and Debt Expense
Incurred
Debt			$	824		791			887
Other			109			72			59
			933			863			946
Capitalized			(153)			(58)			(62)
Expensed			$	780		805			884
Other Income
Interest income			$	412		195			33
Gain (loss) on investment in Cenovus Energy*			—			251			1,040
Other, net			73			58			130
			$	485		504			1,203
*See Note 5.
**Research and Development Expenditures—**expensed			$	81		71			62
Shipping and Handling Costs			$	1,695		1,595			1,047
**Foreign Currency Transaction (Gains) Losses—**after-tax
Alaska			$	—		—			—
Lower 48			—			—			—
Canada			11			(20)			(1)
Europe, Middle East and North Africa			(39)			(110)			(11)
Asia Pacific			12			30			2
Other International			—			(1)			1
Corporate and Other			86			21			(7)
			$	70		(80)			(16)

			Millions of Dollars
			2023			2022
Properties, Plants and Equipment
Proved properties			$	134,394		119,609
Unproved properties			5,206			7,325
Other			4,805			4,562
Gross properties, plants and equipment			144,405			131,496
Less: Accumulated depreciation, depletion and amortization			(74,361)			(66,630)
Net properties, plants and equipment			$	70,044		64,866

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Note 21—Related Party Transactions

Our related parties primarily include equity method investments and certain trusts for the benefit of employees. For disclosures on trusts for the benefit of employees, see Note 16.

Significant transactions with our equity affiliates were:

			Millions of Dollars
			2023			2022			2021
Operating revenues and other income			$	90		88			88
Purchases			—			1			5
Operating expenses and selling, general and administrative expenses			282			189			196
Net interest (income)/loss*			—			(1)			(2)

We paid interest to, or received interest from, various affiliates. See Note 4, for additional information on loans to affiliated companies.*

Note 22—Sales and Other Operating Revenues

Revenue from Contracts with Customers

The following table provides further disaggregation of our consolidated sales and other operating revenues:

			Millions of Dollars
			2023			2022			2021
Revenue from contracts with customers			$	48,522		61,049			34,590
Revenue from contracts outside the scope of ASC Topic 606
Physical contracts meeting the definition of a derivative			8,203			17,150			11,500
Financial derivative contracts			(584)			295			(262)
Consolidated sales and other operating revenues			$	56,141		78,494			45,828

Revenues from contracts outside the scope of ASC Topic 606 relate primarily to physical gas contracts at market prices, which qualify as derivatives accounted for under ASC Topic 815, “Derivatives and Hedging,” and for which we have not elected NPNS. There is no significant difference in contractual terms or the policy for recognition of revenue from these contracts and those within the scope of ASC Topic 606. The following disaggregation of revenues is provided in conjunction with Note 24—Segment Disclosures and Related Information:

			Millions of Dollars
			2023			2022			2021
Revenue from Contracts Outside the Scope of ASC Topic 606 by Segment
Lower 48			$	6,607		13,919			9,050
Canada			1,248			2,717			1,457
Europe, Middle East and North Africa			348			514			993
Physical contracts meeting the definition of a derivative			$	8,203		17,150			11,500

			Millions of Dollars
			2023			2022			2021
Revenue from Contracts Outside the Scope of ASC Topic 606 by Product
Crude oil			$	143		495			757
Natural gas			6,622			15,368			10,034
Other			1,438			1,287			709
Physical contracts meeting the definition of a derivative			$	8,203		17,150			11,500

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Practical Expedients

Typically, our commodity sales contracts are less than 12 months in duration; however, in certain specific cases may extend longer, which may be out to the end of field life. We have long-term commodity sales contracts which use prevailing market prices at the time of delivery, and under these contracts, the market-based variable consideration for each performance obligation (i.e., delivery of commodity) is allocated to each wholly unsatisfied performance obligation within the contract. Accordingly, we have applied the practical expedient allowed in ASC Topic 606 and do not disclose the aggregate amount of the transaction price allocated to performance obligations or when we expect to recognize revenues that are unsatisfied (or partially unsatisfied) as of the end of the reporting period.

Receivables and Contract Liabilities

Receivables from Contracts with Customers

At December 31, 2023, the “Accounts and notes receivable” line on our consolidated balance sheet included trade receivables of $4,414 million compared with $5,241 million at December 31, 2022, and included both contracts with customers within the scope of ASC Topic 606 and those that are outside the scope of ASC Topic 606. We typically receive payment within 30 days or less (depending on the terms of the invoice) once delivery is made. Revenues that are outside the scope of ASC Topic 606 relate primarily to physical gas sales contracts at market prices for which we do not elect NPNS and are therefore accounted for as a derivative under ASC Topic 815. There is little distinction in the nature of the customer or credit quality of trade receivables associated with gas sold under contracts for which NPNS has not been elected compared with trade receivables where NPNS has been elected.

Contract Liabilities from Contracts with Customers

We have entered into certain agreements under which we license our proprietary technology, including the Optimized Cascade® process technology, to customers to maximize the efficiency of LNG plants. These agreements typically provide for milestone payments to be made during and after the construction phases of the LNG plant. The payments are not directly related to our performance obligations under the contract and are recorded as deferred revenue to be recognized when the customer is able to benefit from their right to use the applicable licensed technology. Revenue recognized during the year ended December 31, 2023 was immaterial. We expect to recognize the outstanding contract liabilities of $26 million as of December 31, 2023, as revenue during the years 2026, 2028 and 2029.

Note 23—Earnings Per Share

The following table presents the calculation of net income (loss) available to common shareholders and basic and diluted EPS for the years ended December 31, 2023, 2022, and 2021. For each of the periods with net income presented in the table below, diluted EPS calculated under the two-class method was more dilutive.

			Millions of Dollars (except per share amounts)
Years Ended December 31			2023			2022			2021
Basic earnings per share
Net Income (Loss)			$	10,957		18,680			8,079
Less: Dividends and undistributed earnings
allocated to participating securities			35			60			19
Net Income (Loss) available to common shareholders			$	10,922		18,620			8,060
Average common shares outstanding (in Millions)			1,203			1,274			1,324
Net Income (Loss) Per Share of Common Stock			$	9.08		14.62			6.09
Diluted earnings per share
Net Income (Loss) available to common shareholders			$	10,922		18,620			8,060
Average common shares outstanding (in Millions)			1,203			1,274			1,324
Add: Dilutive impact of options and unvested
non-participating RSU/PSUs			3			4			4
Average diluted shares outstanding (in Millions)			1,206			1,278			1,328
Net Income (Loss) Per Share of Common Stock			$	9.06		14.57			6.07

ConocoPhillips 2023 10-K			130

Notes to Consolidated Financial Statements			Table of Contents

Note 24—Segment Disclosures and Related Information

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide basis. We manage our operations through six operating segments, which are primarily defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International.

Corporate and Other represents income and costs not directly associated with an operating segment, such as most interest expense, premiums on early retirement of debt, corporate overhead and certain technology activities, including licensing revenues. Corporate assets include all cash and cash equivalents and short-term investments.

We evaluate performance and allocate resources based on net income (loss). Segment accounting policies are the same as those in Note 1. Intersegment sales are at prices that approximate market.

Analysis of Results by Operating Segment

			Millions of Dollars
			2023			2022			2021
Sales and Other Operating Revenues
Alaska			7,098			7,905			5,480
Lower 48			38,244			52,921			29,306
Intersegment eliminations			(7)			(18)			(12)
Lower 48			38,237			52,903			29,294
Canada			4,873			6,159			4,077
Intersegment eliminations			(1,867)			(2,445)			(1,583)
Canada			3,006			3,714			2,494
Europe, Middle East and North Africa			5,854			11,271			5,902
Intersegment eliminations			—			(1)			—
Europe, Middle East and North Africa			5,854			11,270			5,902
Asia Pacific			1,913			2,606			2,579
Other International			—			—			4
Corporate and Other			33			96			75
Consolidated sales and other operating revenues			$	56,141		78,494			45,828

In 2023, sales by our Lower 48 segment to a certain pipeline company accounted for approximately $5.8 billion or approximately 10 percent of our total consolidated sales and other operating revenues.

			Millions of Dollars
			2023			2022			2021
Depreciation, Depletion, Amortization and Impairments
Alaska			$	1,061		941			1,002
Lower 48			5,729			4,854			4,067
Canada			425			400			392
Europe, Middle East and North Africa			587			735			862
Asia Pacific			455			518			1,483
Other International			—			—			—
Corporate and Other			27			44			76
Consolidated depreciation, depletion, amortization and impairments			$	8,284		7,492			7,882

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			Millions of Dollars
			2023			2022			2021
Equity in Earnings of Affiliates
Alaska			$	1		4			5
Lower 48			(9)			(14)			(18)
Canada			—			—			—
Europe, Middle East and North Africa			580			780			502
Asia Pacific			1,151			1,310			343
Other International			—			1			—
Corporate and Other			(3)			—			—
Consolidated equity in earnings of affiliates			$	1,720		2,081			832

Income Tax Provision (Benefit)
Alaska			$	642		885			402
Lower 48			1,763			3,088			1,390
Canada			26			206			150
Europe, Middle East and North Africa			3,065			5,445			2,543
Asia Pacific			42			480			483
Other International			—			53			(53)
Corporate and Other			(207)			(609)			(282)
Consolidated income tax provision (benefit)			$	5,331		9,548			4,633

Net Income (Loss)
Alaska			$	1,778		2,352			1,386
Lower 48			6,461			11,015			4,932
Canada			402			714			458
Europe, Middle East and North Africa			1,189			2,244			1,167
Asia Pacific			1,961			2,736			453
Other International			(13)			(51)			(107)
Corporate and Other			(821)			(330)			(210)
Consolidated net income (loss)			$	10,957		18,680			8,079

Investments in and Advances to Affiliates
Alaska			$	32		55			58
Lower 48			118			235			242
Canada			—			—			—
Europe, Middle East and North Africa			1,191			1,049			797
Asia Pacific			5,419			6,154			5,603
Other International			—			—			1
Corporate and Other			1,145			—			—
Consolidated investments in and advances to affiliates			$	7,905		7,493			6,701

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			Millions of Dollars
			2023			2022			2021
Total Assets
Alaska			$	16,174		15,126			14,812
Lower 48			42,415			42,950			41,699
Canada			10,277			6,971			7,439
Europe, Middle East and North Africa			8,396			8,263			9,125
Asia Pacific			8,903			9,511			9,840
Other International			—			—			1
Corporate and Other			9,759			11,008			7,745
Consolidated total assets			$	95,924		93,829			90,661

Capital Expenditures and Investments
Alaska			$	1,705		1,091			982
Lower 48			6,487			5,630			3,129
Canada			456			530			203
Europe, Middle East and North Africa			1,111			998			534
Asia Pacific			354			1,880			390
Other International			—			—			33
Corporate and Other			1,135			30			53
Consolidated capital expenditures and investments			$	11,248		10,159			5,324

Interest Income and Expense
Interest income
Alaska			$	—		—			—
Lower 48			—			—			—
Canada			—			—			—
Europe, Middle East and North Africa			1			1			2
Asia Pacific			8			9			9
Other International			—			—			—
Corporate and Other			403			185			22
Interest and debt expense
Corporate and Other			$	780		805			884

Sales and Other Operating Revenues by Product
Crude oil			$	37,833		41,492			23,648
Natural gas			10,725			26,941			16,904
Natural gas liquids			2,609			3,650			1,668
Other*			4,974			6,411			3,608
Consolidated sales and other operating revenues by product			$	56,141		78,494			45,828

*Includes bitumen and power.

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Geographic Information

			Millions of Dollars
			Sales and Other Operating Revenues(1)												Long-Lived Assets(2)
			2023			2022			2021						2023			2022			2021
U.S.			$	45,101		60,899			34,847						53,955			51,200			50,580
Australia			—			—			—						5,426			6,158			5,579
Canada			3,006			3,714			2,494						9,666			6,269			6,608
China			952			1,135			724						1,635			1,538			1,476
Indonesia(3)			—			159			879						—			—			28
Libya			1,730			1,582			1,102						703			714			659
Malaysia			961			1,312			975						939			1,107			1,252
Norway			2,408			3,415			2,563						4,489			4,369			4,681
U.K.			1,978			6,273			2,236						2			1			1
Other foreign countries			5			5			8						1,134			1,003			748
Worldwide consolidated			$	56,141		78,494			45,828						77,949			72,359			71,612

*(1)*Sales and other operating revenues are attributable to countries based on the location of the selling operation.

*(2)*Defined as net PP&E plus equity investments and advances to affiliated companies.

*(3)*Assets divested in 2022. See Note 3**.

Note 25—New Accounting Standards

In November 2023, the FASB issued ASU No. 2023-07, “Improvements to Reportable Segment Disclosures” which sets forth improvements to the current segment disclosure requirements in accordance with Topic 280 “Segment Reporting”. The amendments do not change how we identify our operating segments. On adoption, the disclosure improvements will be applied retrospectively to prior periods presented. The ASU is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024 and early adoption is permitted. We are currently evaluating the impact of the adoption of this ASU.

In December 2023, the FASB issued ASU No. 2023-09, “Improvements to Income Tax Disclosures” which enhances the disclosure requirements within Topic 740 “Income Taxes”. The enhancements will impact our financial statement disclosures only and will be applied prospectively with retrospective application permitted. The ASU is effective for annual periods beginning after December 15, 2024 and early adoption is permitted. We are currently evaluating the impact of the adoption of this ASU.

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Supplementary Data			Table of Contents

Oil and Gas Operations (Unaudited)

In accordance with FASB ASC Topic 932, “Extractive Activities—Oil and Gas,” and regulations of the SEC, we are making certain supplemental disclosures about our oil and gas exploration and production operations.

These disclosures include information about our consolidated oil and gas activities and our proportionate share of our equity affiliates’ oil and gas activities in our operating segments. As a result, amounts reported as equity affiliates in Oil and Gas Operations may differ from those shown in the individual segment disclosures reported elsewhere in this report. Our disclosures by geographic area include the U.S., Canada, Europe, Asia Pacific/Middle East (inclusive of equity affiliates) and Africa.

As required by current authoritative guidelines, the estimated future date when an asset will be permanently shut down for economic reasons is based on historical 12-month first-of-month average prices and current costs. This estimated date when production will end affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Generally, our proved reserves decrease as prices decline and increase as prices rise.

Our proved reserves include estimated quantities related to PSCs, which are reported under the “economic interest” method, as well as variable-royalty regimes, and are subject to fluctuations in commodity prices, recoverable operating expenses and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. For example, if prices increase, then our applicable reserve quantities would decline. At December 31, 2023, approximately 3 percent of our total proved reserves were under PSCs, located in our Asia Pacific/Middle East geographic reporting area, and 7 percent of our total proved reserves were under a variable-royalty regime, located in our Canada geographic reporting area.

Reserves Governance

The recording and reporting of proved reserves are governed by criteria established by regulations of the SEC and FASB. Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain it will commence the project within a reasonable time.

Proved reserves are further classified as either developed or undeveloped. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared with the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are proved reserves expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence provided by reliable technologies exists that establishes reasonable certainty of economic producibility at greater distances. As defined by SEC regulations, reliable technologies may be used in reserve estimation when they have been demonstrated in the field to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. The technologies and data used in the estimation of our proved reserves include, but are not limited to, performance-based methods, volumetric-based methods, geologic maps, seismic interpretation, well logs, well test data, core data, analogy and statistical analysis.

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We have a company-wide, comprehensive, SEC-compliant internal policy that governs the determination and reporting of proved reserves. This policy is applied by the geoscientists and reservoir engineers in our business units around the world. As part of our internal control process, each business unit’s reserves processes and controls are reviewed annually by an internal team which is headed by the company’s Manager of Reserves Compliance and Reporting. This team, composed of internal reservoir engineers, geoscientists, finance personnel and a senior representative from DeGolyer and MacNaughton (D&M), a third-party petroleum engineering consulting firm, reviews the business unit's reserves for adherence to SEC guidelines and company policy through on-site visits, teleconferences and review of documentation. In addition to providing independent reviews, this internal team also ensures reserves are calculated using consistent and appropriate standards and procedures. This team is independent of business unit line management and is responsible for reporting its findings to senior management. The team is responsible for communicating our reserves policy and procedures and is available for internal peer reviews and consultation on major projects or technical issues throughout the year. All of our proved reserves held by consolidated companies and our share of equity affiliates have been estimated by ConocoPhillips.

During 2023, our processes and controls used to assess over 90 percent of proved reserves as of December 31, 2023, were reviewed by D&M. The purpose of their review was to assess whether the adequacy and effectiveness of our internal processes and controls used to determine estimates of proved reserves are in accordance with SEC regulations. In such review, ConocoPhillips’ technical staff presented D&M with an overview of the reserves data, as well as the methods and assumptions used in estimating reserves. The data presented included pertinent seismic information, geologic maps, well logs, production tests, material balance calculations, reservoir simulation models, well performance data, operating procedures and relevant economic criteria. Management’s intent in retaining D&M to review its processes and controls was to provide objective third-party input on these processes and controls. D&M’s opinion was the general processes and controls employed by ConocoPhillips in estimating its December 31, 2023 proved reserves for the properties reviewed are in accordance with the SEC reserves definitions. D&M’s report is included as Exhibit 99 of this Annual Report on Form 10-K.

The technical person primarily responsible for overseeing the processes and internal controls used in the preparation of the company’s reserves estimates is the Manager of Reserves Compliance and Reporting. This individual holds a master’s degree in petroleum engineering. He is a member of the Society of Petroleum Engineers with over 30 years of oil and gas industry experience and has held positions of increasing responsibility in reservoir engineering, subsurface and asset management in the U.S. and several international field locations.

Engineering estimates of the quantities of proved reserves are inherently imprecise. See the “Critical Accounting Estimates” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional discussion of the sensitivities surrounding these estimates.

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Supplementary Data			Table of Contents

Proved Reserves
Years Ended December 31			Crude Oil
Millions of Barrels
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Total Consolidated Operations			Equity Affiliates*			Total
Developed and Undeveloped
End of 2020			879			693			1,572			6			174			108			191			2,051			68			2,119
Revisions			209			(52)			157			2			14			37			6			216			—			216
Improved recovery			1			—			1			—			—			—			—			1			—			1
Purchases			—			691			691			—			—			—			—			691			—			691
Extensions and discoveries			10			289			299			5			2			1			—			307			—			307
Production			(64)			(160)			(224)			(3)			(29)			(24)			(13)			(293)			(5)			(298)
Sales			—			(9)			(9)			—			—			—			—			(9)			—			(9)
End of 2021			1,035			1,452			2,487			10			161			122			184			2,964			63			3,027
Revisions			(31)			24			(7)			—			31			19			(3)			40			—			40
Improved recovery			—			—			—			—			—			3			—			3			—			3
Purchases			—			6			6			—			—			—			42			48			—			48
Extensions and discoveries			15			250			265			—			8			—			—			273			35			308
Production			(64)			(193)			(257)			(2)			(25)			(22)			(13)			(319)			(5)			(324)
Sales			—			(31)			(31)			—			—			(3)			—			(34)			—			(34)
End of 2022			955			1,508			2,463			8			175			119			210			2,975			93			3,068
Revisions			(57)			126			69			1			(1)			8			10			87			1			88
Improved recovery			—			—			—			—			—			—			—			—			—			—
Purchases			—			2			2			—			—			—			—			2			—			2
Extensions and discoveries			219			54			273			15			3			19			—			310			—			310
Production			(64)			(202)			(266)			(3)			(23)			(22)			(17)			(331)			(5)			(336)
Sales			—			(11)			(11)			—			—			—			—			(11)			—			(11)
End of 2023			1,053			1,477			2,530			21			154			124			203			3,032			89			3,121

Years Ended December 31			Crude Oil
Millions of Barrels
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Total Consolidated Operations			Equity Affiliates*			Total
Developed
End of 2020			765			263			1,028			6			129			77			175			1,415			68			1,483
End of 2021			912			916			1,828			4			122			98			171			2,223			63			2,286
End of 2022			867			828			1,695			5			124			102			191			2,117			58			2,175
End of 2023			790			793			1,583			7			109			91			181			1,971			54			2,025
Undeveloped
End of 2020			114			430			544			—			45			31			16			636			—			636
End of 2021			123			536			659			6			39			24			13			741			—			741
End of 2022			88			680			768			3			51			17			19			858			35			893
End of 2023			263			684			947			14			45			33			22			1,061			35			1,096

*All Equity Affiliate reserves are located in our Asia Pacific/Middle East Region.

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Supplementary Data			Table of Contents

Notable changes in proved crude oil reserves in the three years ended December 31, 2023, included:

• Revisions: In 2023, upward revisions in Lower 48 were due to development drilling of 161 million barrels and technical revisions in the unconventional plays of 31 million barrels, partially offset by downward revisions of 52 million barrels due to lower prices and 14 million barrels for changes in development plans. An upward revision of 10 million barrels in Africa was primarily development drilling in Libya. Upward revisions of 8 million barrels in the consolidated operations in Asia Pacific/Middle East were due to technical revisions. In Alaska, where future production is constrained by the Trans-Alaska Pipeline System minimum flow limit, updated total North Slope development phasing indicated that the flow limit will be reached earlier than previously premised, resulting in downward revisions of 25 million barrels. Further downward revisions in Alaska include development plan changes of 14 million barrels, cost escalation of 13 million barrels, and 7 million barrels due to lower prices, partially offset by 2 million barrels of technical revisions.

In 2022, upward revisions in Lower 48 were due to additional development drilling in the unconventional plays of 81 million barrels and higher prices of 33 million barrels, partially offset by increasing operating costs of 72 million barrels and technical revisions of 18 million barrels. Upward revisions in Europe were primarily due to technical revisions of 23 million barrels and 8 million barrels due to higher prices. Upward revisions of 19 million barrels in our consolidated operations in Asia Pacific/Middle East were primarily due to technical revisions.

In 2021, Alaska upward revisions were primarily driven by higher prices. Downward revisions in Lower 48 were due to development timing for specific well locations from unconventional plays of 203 million barrels and technical revisions of 35 million barrels, partially offset by upward revisions due to higher prices of 115 million barrels and additional infill drilling in the unconventional plays of 71 million barrels. Upward revisions in Europe were primarily due to higher prices. In Asia Pacific/Middle East, increases were due to higher prices of 21 million barrels and technical revisions of 16 million barrels.

• Purchases: In 2022, crude oil reserve purchases were primarily in Africa, as a result of the acquisition of additional interest in the Libya Waha Concession.

In 2021, Lower 48 purchases were due to the Concho and Shell Permian acquisitions.

• Extensions and discoveries: In 2023, extensions and discoveries in Alaska were driven primarily by the Willow and Nuna projects. Lower 48 extensions and discoveries were primarily within unconventional plays in the Permian Basin. Extensions and discoveries in Canada and Asia Pacific/Middle East were driven primarily by Montney and Bohai Phase 4B in China, respectively.

In 2022, extensions and discoveries in Lower 48 were primarily within unconventional plays in the Permian Basin. Extensions and discoveries in our equity affiliates were in the Middle East.

In 2021, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the unconventional plays which more than offset the decreases resulting from development plan timing in the revisions category.

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Supplementary Data			Table of Contents

Years Ended December 31			Natural Gas Liquids
Millions of Barrels
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Total Consolidated Operations			Equity Affiliates*			Total
Developed and Undeveloped
End of 2020			94			230			324			4			12			—			340			36			376
Revisions			(6)			213			207			—			1			—			208			—			208
Improved recovery			—			—			—			—			—			—			—			—			—
Purchases			—			72			72			—			—			—			72			—			72
Extensions and discoveries			—			82			82			2			—			—			84			—			84
Production			(6)			(50)			(56)			(1)			(2)			—			(59)			(3)			(62)
Sales			—			(1)			(1)			—			—			—			(1)			—			(1)
End of 2021			82			546			628			5			11			—			644			33			677
Revisions			1			208			209			1			3			—			213			—			213
Improved recovery			—			—			—			—			—			—			—			—			—
Purchases			—			3			3			—			—			—			3			—			3
Extensions and discoveries			—			80			80			—			1			—			81			20			101
Production			(5)			(81)			(86)			(1)			(2)			—			(89)			(3)			(92)
Sales			—			(7)			(7)			—			—			—			(7)			—			(7)
End of 2022			78			749			827			5			13			—			845			50			895
Revisions			(1)			119			118			—			2			—			120			1			121
Improved recovery			—			—			—			—			—			—			—			—			—
Purchases			—			1			1			—			—			—			1			—			1
Extensions and discoveries			—			20			20			6			—			—			26			—			26
Production			(5)			(90)			(95)			(1)			(2)			—			(98)			(3)			(101)
Sales			—			(2)			(2)			—			—			—			(2)			—			(2)
End of 2023			72			797			869			10			13			—			892			48			940

Years Ended December 31			Natural Gas Liquids
Millions of Barrels
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Total Consolidated Operations			Equity Affiliates*			Total
Developed
End of 2020			94			83			177			4			9			—			190			36			226
End of 2021			82			334			416			3			9			—			428			33			461
End of 2022			78			409			487			3			10			—			500			31			531
End of 2023			72			426			498			4			9			—			511			28			539
Undeveloped
End of 2020			—			147			147			—			3			—			150			—			150
End of 2021			—			212			212			2			2			—			216			—			216
End of 2022			—			340			340			2			3			—			345			19			364
End of 2023			—			371			371			6			4			—			381			20			401

*All Equity Affiliate reserves are located in our Asia Pacific/Middle East Region.

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Notable changes in proved NGL reserves in the three years ended December 31, 2023, included:

• Revisions: In 2023, upward revisions in Lower 48 were due to additional development drilling in the unconventional plays of 86 million barrels and technical revisions of 71 million barrels. This was partially offset by lower prices impacting 34 million barrels and development plan changes of 4 million barrels.

In 2022, upward revisions in Lower 48 were due to additional development drilling in the unconventional plays of 88 million barrels, technical revisions of 75 million barrels, continued conversion of acquired Concho Permian two-stream contracts to a three-stream (crude oil, natural gas and NGLs) basis adding 70 million barrels, and higher prices of 13 million barrels. This was partially offset by increasing operating costs of 38 million barrels.

In 2021, upward revisions in Lower 48 were due to conversion of acquired Concho Permian two-stream contracts to a three-stream (crude oil, natural gas and NGLs) basis, adding 182 million barrels, additional infill drilling in the unconventional plays of 44 million barrels, technical revisions of 21 million barrels and higher prices of 28 million barrels, partially offset by downward revisions related to development timing for specific well locations from unconventional plays of 62 million barrels.

• Purchases: In 2021, Lower 48 purchases were due to the Shell Permian acquisition.

• Extensions and discoveries: In 2023, extensions and discoveries in Lower 48 were primarily within unconventional plays in the Permian Basin. Canada extensions and discoveries were in Montney.

In 2022, extensions and discoveries in Lower 48 were primarily within unconventional plays in the Permian Basin. Extensions and discoveries in our equity affiliates were in the Middle East.

In 2021, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the unconventional plays which more than offset the decreases in the revisions category.

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Years Ended December 31			Natural Gas
Billions of Cubic Feet
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Total Consolidated Operations			Equity Affiliates*			Total
Developed and Undeveloped
End of 2020			1,996			2,100			4,096			74			825			851			224			6,070			3,724			9,794
Revisions			715			41			756			15			54			60			—			885			247			1,132
Improved recovery			—			—			—			—			—			—			—			—			—			—
Purchases			—			2,438			2,438			—			—			—			—			2,438			—			2,438
Extensions and discoveries			—			822			822			46			2			—			—			870			116			986
Production			(86)			(473)			(559)			(30)			(113)			(147)			(7)			(856)			(390)			(1,246)
Sales			—			(270)			(270)			—			—			—			—			(270)			—			(270)
End of 2021			2,625			4,658			7,283			105			768			764			217			9,137			3,697			12,834
Revisions			(35)			361			326			8			108			(2)			(14)			426			898			1,324
Improved recovery			—			—			—			—			—			—			—			—			—			—
Purchases			—			23			23			—			—			—			48			71			479			550
Extensions and discoveries			—			505			505			4			103			—			—			612			1,118			1,730
Production			(88)			(543)			(631)			(23)			(117)			(51)			(10)			(832)			(439)			(1,271)
Sales			—			(262)			(262)			—			—			(385)			—			(647)			—			(647)
End of 2022			2,502			4,742			7,244			94			862			326			241			8,767			5,753			14,520
Revisions			(243)			521			278			27			73			6			(57)			327			(90)			237
Improved recovery			—			—			—			—			—			—			—			—			—			—
Purchases			—			4			4			—			—			—			—			4			—			4
Extensions and discoveries			—			121			121			144			1			4			—			270			58			328
Production			(84)			(570)			(654)			(25)			(113)			(24)			(12)			(828)			(446)			(1,274)
Sales			—			(97)			(97)			—			—			—			—			(97)			—			(97)
End of 2023			2,175			4,721			6,896			240			823			312			172			8,443			5,275			13,718

Years Ended December 31			Natural Gas
Billions of Cubic Feet
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Total Consolidated Operations			Equity Affiliates*			Total
Developed
End of 2020			1,961			1,051			3,012			74			598			806			224			4,714			3,293			8,007
End of 2021			2,579			3,100			5,679			52			679			688			217			7,315			3,204			10,519
End of 2022			2,474			2,628			5,102			64			641			322			241			6,370			3,974			10,344
End of 2023			2,156			2,525			4,681			92			591			305			172			5,841			3,558			9,399
Undeveloped
End of 2020			35			1,049			1,084			—			227			45			—			1,356			431			1,787
End of 2021			46			1,558			1,604			53			89			76			—			1,822			493			2,315
End of 2022			28			2,114			2,142			30			221			4			—			2,397			1,779			4,176
End of 2023			19			2,196			2,215			148			232			7			—			2,602			1,717			4,319

*All Equity Affiliate reserves are located in our Asia Pacific/Middle East Region.

Natural gas production in the reserves table may differ from gas production (delivered for sale) in our statistics disclosure, primarily because the quantities above include gas consumed in production operations. Quantities consumed in production operations are not significant in the periods presented. The value of net production consumed in operations is not reflected in net revenues and production expenses, nor do the volumes impact the respective per unit metrics.

Reserve volumes include natural gas to be consumed in operations of 2,263 BCF, 2,416 BCF and 2,748 BCF, as of December 31, 2023, 2022 and 2021, respectively. These volumes are not included in the calculation of our Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities.

Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.

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Notable changes in proved natural gas reserves in the three years ended December 31, 2023, included:

• Revisions: In 2023, upward revisions in Lower 48 were due to additional development drilling in the unconventional plays of 502 BCF, technical revisions of 268 BCF, partly offset by lower prices of 211 BCF and development plan downward revisions of 38 BCF. In Europe, technical revisions contributed 64 BCF and development drilling of 14 BCF, partially offset by lower prices of 5 BCF. In Canada, upward revisions were driven by technical revisions of 37 BCF, partially offset by lower prices of 10 BCF. In Alaska, where future production is constrained by the Trans-Alaska Pipeline System minimum flow limit, updated total North Slope development phasing indicated that the flow limit will be reached earlier than previously premised, resulting in downward revisions of 121 BCF. Further downward revisions in Alaska included 72 BCF from operating efficiencies resulting in less gas to be consumed in operations, 22 BCF due to lower prices, 14 BCF from cost escalation, and 14 BCF due to technical revisions. Downward revisions in Africa of 57 BCF due to infrastructure constraints and sales demand revisions. In our equity affiliates, downward revisions were due to lower prices of 288 BCF, offset by upward technical revisions of 198 BCF.

In 2022, upward revisions in Lower 48 were due to additional development drilling in the unconventional plays of 544 BCF, higher prices of 109 BCF, and technical revisions of 41 BCF. These were partially offset by decreases of 233 BCF due to increasing operating costs, and 100 BCF due to the continued conversion of acquired Concho Permian two-stream contracts to a three-stream (crude oil, natural gas and natural gas liquids) basis. Upward revisions in Canada were driven by higher prices of 26 BCF, partially offset by technical revisions of 18 BCF. In Europe, technical revisions contributed 96 BCF, and higher prices 12 BCF of upward revisions. Downward revisions in Africa were primarily due to technical revisions. In our equity affiliates in Asia Pacific/Middle East, upward revisions were due to higher prices of 423 BCF, changing dynamics and improved prices in the regional LNG spot market of 331 BCF, and technical revisions of 204 BCF, partially offset by downward revisions due to increasing operating costs of 60 BCF.

In 2021, upward revisions in Alaska were due to higher prices of 587 BCF and technical revisions of 128 BCF. In Lower 48, upward revisions of 614 BCF were due to higher prices, additional infill drilling in the unconventional plays of 277 BCF and technical revisions of 60 BCF, partially offset by downward revisions due to development timing for specific well locations from unconventional plays of 498 BCF and conversion of previously acquired Permian two-stream contracted volumes to a three-stream (crude oil, natural gas and natural gas liquids) basis of 412 BCF. Upward revisions in Canada were due to higher prices of 29 BCF, partially offset by downward revisions due to technical revisions of 14 BCF. In Europe, upward revisions were primarily due to higher prices. Upward revisions in our consolidated operations in Asia Pacific/Middle East were due to technical revisions of 76 BCF, partially offset by price revisions of 16 BCF. In our equity affiliates in Asia Pacific/Middle East, upward revisions were due to higher prices of 124 BCF and technical and cost revisions of 123 BCF.

• Purchases: In 2022, purchases in Africa were a result of the acquisition of additional interest in the Libya Waha Concession. In our equity affiliates, purchases were due to the acquisition of additional affiliate interest in Asia Pacific.

In 2021, Lower 48 purchases were due to the Concho and Shell Permian acquisitions.

• Extensions and discoveries: In 2023, extensions and discoveries in Lower 48 were primarily within unconventional plays in the Permian Basin. Canada extensions and discoveries were in Montney. Extensions and discoveries in our equity affiliates were in Australia.

In 2022, extensions and discoveries in Lower 48 were primarily within unconventional plays in the Permian Basin. In Europe, extensions and discoveries were due to additional planned development. Extensions and discoveries in our equity affiliates were primarily in the Middle East.

In 2021, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the unconventional plays which more than offset the decreases resulting from development plan timing in the revisions category. Extensions and discoveries in Canada were primarily driven by ongoing drilling successes in Montney.

• Sales: In 2023, Lower 48 sales represent the disposition of noncore assets.

In 2022, Lower 48 sales represent the disposition of noncore assets. Sales in our consolidated operations in Asia Pacific/Middle East represent the disposition of our Indonesia assets.

In 2021, Lower 48 sales represent the disposition of noncore assets.

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Years Ended December 31			Bitumen
Millions of Barrels
			Canada			Total*
Developed and Undeveloped
End of 2020			332			332
Revisions			(50)			(50)
Improved recovery			—			—
Purchases			—			—
Extensions and discoveries			—			—
Production			(25)			(25)
Sales			—			—
End of 2021			257			257
Revisions			(17)			(17)
Improved recovery			—			—
Purchases			—			—
Extensions and discoveries			—			—
Production			(24)			(24)
Sales			—			—
End of 2022			216			216
Revisions			15			15
Improved recovery			—			—
Purchases			209			209
Extensions and discoveries			—			—
Production			(30)			(30)
Sales			—			—
End of 2023			410			410

Years Ended December 31			Bitumen
Millions of Barrels
			Canada			Total*
Developed
End of 2020			117			117
End of 2021			150			150
End of 2022			127			127
End of 2023			293			293
Undeveloped
End of 2020			215			215
End of 2021			107			107
End of 2022			89			89
End of 2023			117			117

*There are no Bitumen reserves associated with our Equity Affiliates.

Notable changes in proved bitumen reserves in the three years ended December 31, 2023, included:

• Revisions: In 2023, the upward revision of 15 million barrels is primarily due to the impact of price on variable royalties.

In 2022, the impact of variable royalties on price resulted in downward revisions of 30 million barrels, partially offset by upward revisions primarily due to changes in development timing for specific pad locations from the Surmont development program.

In 2021, downward revisions of 64 million barrels were driven by changes in carbon tax costs and 39 million barrels due to changes in development timing for specific pad locations from the Surmont development program, partially offset by upward revisions from price of 53 million barrels.

*•*Purchases: In 2023, purchases in Canada were a result of the acquisition of the remaining 50 percent working interest in Surmont.

• Extensions and discoveries: In 2021, extensions and discoveries in Canada were primarily due to planned development to add specific pad locations from the Surmont development program, which more than offset the decrease in the revisions category.

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Years Ended December 31			Total Proved Reserves
Millions of Barrels of Oil Equivalent
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Total Consolidated Operations			Equity Affiliates*			Total
Developed and Undeveloped
End of 2020			1,306			1,273			2,579			355			323			249			228			3,734			725			4,459
Revisions			322			168			490			(45)			23			47			6			521			42			563
Improved recovery			1			—			1			—			—			—			—			1			—			1
Purchases			—			1,169			1,169			—			—			—			—			1,169			—			1,169
Extensions and discoveries			10			508			518			15			3			1			—			537			19			556
Production			(84)			(289)			(373)			(35)			(50)			(48)			(14)			(520)			(73)			(593)
Sales			—			(54)			(54)			—			—			—			—			(54)			—			(54)
End of 2021			1,555			2,775			4,330			290			299			249			220			5,388			713			6,101
Revisions			(35)			292			257			(15)			52			19			(5)			308			149			457
Improved recovery			—			—			—			—			—			3			—			3			—			3
Purchases			—			13			13			—			—			—			50			63			80			143
Extensions and discoveries			15			414			429			1			26			—			—			456			241			697
Production			(85)			(364)			(449)			(31)			(46)			(31)			(15)			(572)			(81)			(653)
Sales			—			(82)			(82)			—			—			(67)			—			(149)			—			(149)
End of 2022			1,450			3,048			4,498			245			331			173			250			5,497			1,102			6,599
Revisions			(98)			332			234			20			12			9			1			276			(14)			262
Improved recovery			—			—			—			—			—			—			—			—			—			—
Purchases			—			4			4			209			—			—			—			213			—			213
Extensions and discoveries			219			94			313			45			3			20			—			381			10			391
Production			(83)			(387)			(470)			(38)			(43)			(26)			(19)			(596)			(82)			(678)
Sales			—			(29)			(29)			—			—			—			—			(29)			—			(29)
End of 2023			1,488			3,062			4,550			481			303			176			232			5,742			1,016			6,758

Years Ended December 31			Total Proved Reserves
Millions of Barrels of Oil Equivalent
Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Total Consolidated Operations			Equity Affiliates*			Total
Developed
End of 2020			1,186			521			1,707			140			238			211			212			2,508			653			3,161
End of 2021			1,424			1,767			3,191			166			244			212			207			4,020			631			4,651
End of 2022			1,357			1,676			3,033			147			240			155			231			3,806			751			4,557
End of 2023			1,222			1,639			2,861			320			216			142			210			3,749			675			4,424
Undeveloped
End of 2020			120			752			872			215			85			38			16			1,226			72			1,298
End of 2021			131			1,008			1,139			124			55			37			13			1,368			82			1,450
End of 2022			93			1,372			1,465			98			91			18			19			1,691			351			2,042
End of 2023			266			1,423			1,689			161			87			34			22			1,993			341			2,334

*All Equity Affiliate reserves are located in our Asia Pacific/Middle East Region.

Natural gas reserves are converted to barrels of oil equivalent (BOE) based on a 6:1 ratio: six MCF of natural gas converts to one BOE.

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Proved Undeveloped Reserves

The following table shows changes in total proved undeveloped reserves for 2023:

			Proved Undeveloped Reserves
			Millions of Barrels of Oil Equivalent
End of 2022			2,042
Revisions			354
Improved recovery			—
Purchases			60
Extensions and discoveries			335
Sales			(10)
Transfers to Proved Developed			(447)
End of 2023			2,334

Revisions of 354 MMBOE were predominately driven by progression of development plans in the Lower 48 unconventional plays partially offset by 23 MMBOE due to product price changes across the portfolio.

Extensions and discoveries were largely driven by the addition of 219 MMBOE in Alaska, primarily due to Willow and Nuna projects, 44 MMBOE in the Lower 48 unconventional plays and 39 MMBOE in Canada for Montney development. The remaining extensions and discoveries were driven by the continued development planned in the other geographic regions, including 10 MMBOE from equity affiliates in Asia Pacific/Middle East.

Transfers to proved developed reserves were driven by the ongoing development of our assets. Approximately 75 percent of the transfers were from the development of our Lower 48 unconventional plays. The remainder of transfers were from development across the other geographic regions.

At December 31, 2023, our PUDs represented 35 percent of total proved reserves, compared with 31 percent at December 31, 2022. Costs incurred for the year ended December 31, 2023, relating to the development of PUDs were $7.9 billion. A portion of our costs incurred each year relates to development projects where the PUDs will be converted to proved developed reserves in future years.

At the end of 2023, approximately 86 percent of total PUDs were under development or scheduled for development within five years of initial disclosure, including all of our Lower 48 PUDs. Increases in 2023 to PUDs scheduled for development beyond five years are primarily in Alaska, due to the initial recognition of PUDs associated with the Willow project, a development that is currently underway with production anticipated in 2029 due to its large scale and remote location. The remaining PUDs to be developed beyond five years are in major development areas which are currently producing and located within our Canada and Asia Pacific/Middle East geographic areas.

Results of Operations

The company’s results of operations from oil and gas activities for the years 2023, 2022 and 2021 are shown in the following tables. Non-oil and gas activities, such as pipeline and marine operations, LNG operations, crude oil and gas marketing activities, and the profit element of transportation operations in which we have an ownership interest are excluded. Additional information about selected line items within the results of operations tables is shown below:

• Sales include sales to unaffiliated entities attributable primarily to the company’s net working interests and royalty interests. Sales are net of fees to transport our produced hydrocarbons beyond the production function to a final delivery point using transportation operations which are not consolidated.

• Transportation costs reflect fees to transport our produced hydrocarbons beyond the production function to a final delivery point using transportation operations which are consolidated.

• Other revenues include gains and losses from asset sales, certain amounts resulting from the purchase and sale of hydrocarbons, and other miscellaneous income.

• Production costs include costs incurred to operate and maintain wells, related equipment and facilities used in the production of petroleum liquids and natural gas.

• Taxes other than income taxes include production, property and other non-income taxes.

• Depreciation of support equipment is reclassified as applicable.

• Other related expenses include inventory fluctuations, foreign currency transaction gains and losses and other miscellaneous expenses.

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Results of Operations

Year Ended December 31, 2023			Millions of Dollars
Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Other Areas			Total
Consolidated operations
Sales			$	5,918		18,976			24,894			1,517			3,449			1,914			1,447			—			33,221
Transfers			5			—			5			—			—			—			—			—			5
Transportation costs			(611)			—			(611)			—			—			—			—			—			(611)
Other revenues			(4)			142			138			(1)			3			(1)			181			3			323
Total revenues			5,308			19,118			24,426			1,516			3,452			1,913			1,628			3			32,938
Production costs excluding taxes			1,242			4,175			5,417			602			499			348			74			1			6,941
Taxes other than income taxes			442			1,347			1,789			26			35			115			3			—			1,968
Exploration expenses			72			153			225			49			73			44			4			3			398
Depreciation, depletion and amortization			938			5,702			6,640			374			532			454			50			—			8,050
Impairments			—			7			7			6			—			—			—			—			13
Other related expenses			71			42			113			60			(24)			17			3			12			181
Accretion			94			65			159			12			61			27			—			—			259
			2,449			7,627			10,076			387			2,276			908			1,494			(13)			15,128
Income tax provision (benefit)			640			1,667			2,307			5			1,704			66			1,375			—			5,457
Results of operations			$	1,809		5,960			7,769			382			572			842			119			(13)			9,671
Equity affiliates
Sales			$	—		—			—			—			—			822			—			—			822
Transfers			—			—			—			—			—			3,429			—			—			3,429
Transportation costs			—			—			—			—			—			—			—			—			—
Other revenues			—			—			—			—			—			14			—			—			14
Total revenues			—			—			—			—			—			4,265			—			—			4,265
Production costs excluding taxes			—			—			—			—			—			493			—			—			493
Taxes other than income taxes			—			—			—			—			—			1,208			—			—			1,208
Exploration expenses			—			—			—			—			—			—			—			—			—
Depreciation, depletion and amortization			—			—			—			—			—			390			—			—			390
Impairments			—			—			—			—			—			—			—			—			—
Other related expenses			—			—			—			—			—			(8)			—			—			(8)
Accretion			—			—			—			—			—			30			—			—			30
			—			—			—			—			—			2,152			—			—			2,152
Income tax provision (benefit)			—			—			—			—			—			658			—			—			658
Results of operations			$	—		—			—			—			—			1,494			—			—			1,494

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Year Ended December 31,2022			Millions of Dollars
Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Other Areas			Total
Consolidated operations
Sales			$	7,210		24,309			31,519			1,622			6,594			2,602			1,339			—			43,676
Transfers			6			—			6			—			—			—			—			—			6
Transportation costs			(647)			—			(647)			—			—			—			—			—			(647)
Other revenues			(1)			115			114			338			1			536			184			10			1,183
Total revenues			6,568			24,424			30,992			1,960			6,595			3,138			1,523			10			44,218
Production costs excluding taxes			1,160			3,600			4,760			581			511			342			55			—			6,249
Taxes other than income taxes			1,265			1,687			2,952			21			36			243			2			—			3,254
Exploration expenses			34			189			223			149			122			49			19			2			564
Depreciation, depletion and amortization			833			4,843			5,676			354			693			517			36			—			7,276
Impairments			2			(11)			(9)			(2)			(1)			—			—			—			(12)
Other related expenses			(19)			4			(15)			(41)			(178)			40			5			6			(183)
Accretion			78			55			133			11			62			25			—			—			231
			3,215			14,057			17,272			887			5,350			1,922			1,406			2			26,839
Income tax provision (benefit)			866			3,113			3,979			198			4,057			512			1,301			53			10,100
Results of operations			$	2,349		10,944			13,293			689			1,293			1,410			105			(51)			16,739
Equity affiliates
Sales			$	—		—			—			—			—			1,000			—			—			1,000
Transfers			—			—			—			—			—			4,272			—			—			4,272
Transportation costs			—			—			—			—			—			—			—			—			—
Other revenues			—			—			—			—			—			41			—			—			41
Total revenues			—			—			—			—			—			5,313			—			—			5,313
Production costs excluding taxes			—			—			—			—			—			491			—			—			491
Taxes other than income taxes			—			—			—			—			—			1,536			—			—			1,536
Exploration expenses			—			—			—			—			—			—			—			—			—
Depreciation, depletion and amortization			—			—			—			—			—			530			—			—			530
Impairments			—			—			—			—			—			—			—			—			—
Other related expenses			—			—			—			—			—			(2)			—			—			(2)
Accretion			—			—			—			—			—			27			—			—			27
			—			—			—			—			—			2,731			—			—			2,731
Income tax provision (benefit)			—			—			—			—			—			836			—			—			836
Results of operations			$	—		—			—			—			—			1,895			—			—			1,895

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Year Ended December 31,2021			Millions of Dollars
Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Other Areas			Total
Consolidated operations
Sales			$	4,832		14,093			18,925			1,219			3,568			2,525			917			—			27,154
Transfers			4			—			4			—			—			—			—			—			4
Transportation costs			(626)			—			(626)			—			—			—			—			—			(626)
Other revenues			14			135			149			323			(5)			237			141			(161)			684
Total revenues			4,224			14,228			18,452			1,542			3,563			2,762			1,058			(161)			27,216
Production costs excluding taxes			1,073			2,414			3,487			518			487			466			43			—			5,001
Taxes other than income taxes			442			937			1,379			23			36			91			1			1			1,531
Exploration expenses			80			98			178			39			21			51			2			15			306
Depreciation, depletion and amortization			864			4,053			4,917			383			844			787			35			—			6,966
Impairments			5			(8)			(3)			6			(24)			7			—			—			(14)
Other related expenses			(31)			12			(19)			(22)			(42)			4			4			12			(63)
Accretion			71			47			118			10			70			26			—			—			224
			1,720			6,675			8,395			585			2,171			1,330			973			(189)			13,265
Income tax provision (benefit)			378			1,467			1,845			145			1,673			494			870			(53)			4,974
Results of operations			$	1,342		5,208			6,550			440			498			836			103			(136)			8,291
Equity affiliates
Sales			$	—		—			—			—			—			745			—			—			745
Transfers			—			—			—			—			—			1,797			—			—			1,797
Transportation costs			—			—			—			—			—			—			—			—			—
Other revenues			—			—			—			—			—			5			—			—			5
Total revenues			—			—			—			—			—			2,547			—			—			2,547
Production costs excluding taxes			—			—			—			—			—			329			—			—			329
Taxes other than income taxes			—			—			—			—			—			824			—			—			824
Exploration expenses			—			—			—			—			—			268			—			—			268
Depreciation, depletion and amortization			—			—			—			—			—			593			—			—			593
Impairments			—			—			—			—			—			718			—			—			718
Other related expenses			—			—			—			—			—			3			—			—			3
Accretion			—			—			—			—			—			17			—			—			17
			—			—			—			—			—			(205)			—			—			(205)
Income tax provision (benefit)			—			—			—			—			—			(42)			—			—			(42)
Results of operations			$	—		—			—			—			—			(163)			—			—			(163)

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Statistics

Net Production			2023			2022			2021
			Thousands of Barrels Daily
Crude Oil
Consolidated operations
Alaska			173			177			178
Lower 48			569			534			447
United States			742			711			625
Canada			9			6			8
Europe			64			71			81
Asia Pacific			60			61			65
Africa			48			36			37
Total consolidated operations			923			885			816
Equity affiliates—Asia Pacific/Middle East			13			13			13
Total company			936			898			829
Delaware Basin Area (Lower 48)*			274			258			162
Greater Prudhoe Area (Alaska)*			66			67			67
Natural Gas Liquids
Consolidated operations
Alaska			16			17			16
Lower 48			256			221			110
United States			272			238			126
Canada			3			3			4
Europe			4			3			4
Asia Pacific			—			—			—
Total consolidated operations			279			244			134
Equity affiliates—Asia Pacific/Middle East			8			8			8
Total company			287			252			142
Delaware Basin Area (Lower 48)*			135			114			27
Greater Prudhoe Area (Alaska)*			16			17			16
Bitumen
Consolidated operations—Canada			81			66			69
Total company			81			66			69
Natural Gas			Millions of Cubic Feet Daily
Consolidated operations
Alaska			38			34			16
Lower 48			1,457			1,402			1,340
United States			1,495			1,436			1,356
Canada			65			61			80
Europe			279			306			298
Asia Pacific			48			114			360
Africa			29			22			15
Total consolidated operations			1,916			1,939			2,109
Equity affiliates—Asia Pacific/Middle East			1,219			1,191			1,053
Total company			3,135			3,130			3,162
Delaware Basin Area (Lower 48)*			768			752			584
Greater Prudhoe Area (Alaska)*			35			32			12

*At year-end 2023, 2022 and 2021, the Delaware Basin Area in Lower 48 contained more than 15 percent of our total proved reserves. At year-end 2021, the Greater Prudhoe Area in Alaska contained more than 15 percent of our total proved reserves.

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Average Sales Prices			2023			2022			2021
Crude Oil Per Barrel
Consolidated operations
Alaska*			$	74.46		92.58			60.81
Lower 48			76.19			94.46			66.12
United States			75.75			93.96			64.53
Canada			66.19			79.94			56.38
Europe			84.56			99.88			68.94
Asia Pacific			84.79			105.52			70.36
Africa			83.07			97.85			69.06
Total international			83.33			100.75			68.85
Total consolidated operations			77.19			95.27			65.53
Equity affiliates—Asia Pacific/Middle East			78.45			97.31			69.45
Total operations			77.21			95.30			65.59
Natural Gas Liquids Per Barrel
Consolidated operations
Lower 48			$	21.73		35.36			30.63
United States			21.73			35.36			30.63
Canada			26.13			37.70			31.18
Europe			41.13			54.52			43.97
Total international			34.56			46.16			37.50
Total consolidated operations			22.12			35.67			31.04
Equity affiliates—Asia Pacific/Middle East			47.09			61.22			54.16
Total operations			22.82			36.50			32.45
Bitumen Per Barrel
Consolidated operations—Canada			$	42.15		55.56			37.52
Natural Gas Per Thousand Cubic Feet
Consolidated operations
Alaska			$	4.47		3.64			2.81
Lower 48			2.12			5.92			4.38
United States			2.13			5.92			4.38
Canada**			1.80			3.62			2.54
Europe			13.33			35.33			13.75
Asia Pacific			3.95			5.84			6.56
Africa			6.49			6.59			3.73
Total international			10.01			23.54			8.91
Total consolidated operations			3.89			10.56			6.00
Equity affiliates—Asia Pacific/Middle East			8.46			9.39			5.31
Total operations			5.69			10.60			5.77

*Average sales prices for Alaska crude oil above reflects a reduction for transportation costs in which we have an ownership interest that are incurred subsequent to the terminal point of the production function. Accordingly, the average sales prices differ from those discussed in Item 7 of Management's Discussion and Analysis of Financial Condition and Results of Operations.

**Average sales prices include unutilized transportation costs.

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			2023			2022			2021
Average Production Costs Per Barrel of Oil Equivalent*
Consolidated operations
Alaska			$	17.45		15.89			14.92
Lower 48			10.72			9.97			8.48
United States			11.76			10.97			9.78
Canada			15.86			18.73			15.10
Europe			11.89			11.20			9.88
Asia Pacific			14.02			11.71			10.21
Africa			3.83			3.77			2.95
Total international			12.28			12.36			10.53
Total consolidated operations			11.87			11.27			9.99
Equity affiliates—Asia Pacific/Middle East			6.03			6.14			4.60
Average Production Costs Per Barrel—Bitumen
Consolidated operations—Canada			$	14.42		17.62			13.41
Taxes Other Than Income Taxes Per Barrel of Oil Equivalent
Consolidated operations
Alaska			$	6.21		17.33			6.15
Lower 48			3.46			4.67			3.29
United States			3.88			6.80			3.87
Canada			0.68			0.68			0.67
Europe			0.83			0.79			0.73
Asia Pacific			4.63			8.32			1.99
Africa			0.16			0.14			0.07
Total international			1.44			2.51			1.06
Total consolidated operations			3.37			5.87			3.06
Equity affiliates—Asia Pacific/Middle East			14.77			19.22			11.52
Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent
Consolidated operations
Alaska			$	13.18		11.41			12.02
Lower 48			14.64			13.42			14.24
United States			14.42			13.08			13.79
Canada			9.85			11.41			11.16
Europe			12.67			15.19			17.13
Asia Pacific			18.29			17.71			17.25
Africa			2.58			2.47			2.40
Total international			11.36			13.28			14.25
Total consolidated operations			13.77			13.12			13.92
Equity affiliates—Asia Pacific/Middle East			4.77			6.63			8.29

*Includes bitumen.

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Development and Exploration Activities

The following two tables summarize our net interest in productive and dry exploratory and development wells in the years ended December 31, 2023, 2022 and 2021. A “development well” is a well drilled within the proved area of a reservoir to the depth of a stratigraphic horizon known to be productive. An “exploratory well” is a well drilled to find and produce crude oil or natural gas in an unknown field or a new reservoir within a proven field. Exploratory wells also include wells drilled in areas near or offsetting current production, or in areas where well density or production history have not achieved statistical certainty of results. Excluded from the exploratory well count are stratigraphic-type exploratory wells, primarily relating to oil sands delineation wells located in Canada and CBM test wells located in Asia Pacific/Middle East.

Net Wells Completed
			Productive												Dry
			2023			2022			2021						2023			2022			2021
Exploratory
Consolidated operations
Alaska			—			—			—						2			—			1
Lower 48			38			118			87						2			—			—
United States			38			118			87						4			—			1
Canada			6			6			12						—			—			—
Europe			—			—			—						*****			2			—
Asia Pacific/Middle East			—			—			*						—			1			*
Africa			—			—			—						—			3			—
Other areas			—			—			—						—			—			—
Total consolidated operations			44			124			99						4			6			1
Equity affiliates
Asia Pacific/Middle East			3			*			3						*****			—			—
Total equity affiliates			3			*			3						*****			—			—
Development
Consolidated operations
Alaska			11			11			1						—			—			—
Lower 48			494			388			339						—			—			—
United States			505			399			340						—			—			—
Canada			21			11			2						—			—			—
Europe			4			3			7						—			—			—
Asia Pacific/Middle East			20			22			21						—			—			—
Africa			4			2			1						—			—			—
Other areas			—			—			—						—			—			—
Total consolidated operations			554			437			371						—			—			—
Equity affiliates
Asia Pacific/Middle East			45			28			30						—			—			—
Total equity affiliates			45			28			30						—			—			—

*Our total proportionate interest was less than one.

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The table below represents the status of our wells drilling at December 31, 2023, and includes wells in the process of drilling or in active completion. It also represents gross and net productive wells, including producing wells and wells capable of production at December 31, 2023.

Wells at December 31, 2023

												Productive
			In Progress									Oil									Gas
			Gross			Net						Gross			Net						Gross			Net
Consolidated operations
Alaska			4			4						1,554			910						—			—
Lower 48			786			391						14,251			6,954						2,276			1,393
United States			790			395						15,805			7,864						2,276			1,393
Canada			36			36						201			201						158			158
Europe			23			5						481			79						60			3
Asia Pacific/Middle East			4			2						447			211						6			2
Africa			13			3						886			181						10			2
Other areas			—			—						—			—						—			—
Total consolidated operations			866			441						17,820			8,536						2,510			1,558
Equity affiliates
Asia Pacific/Middle East			331			54						—			—						5,139			1,563
Total equity affiliates			331			54						—			—						5,139			1,563

Acreage at December 31, 2023

			Thousands of Acres
			Developed									Undeveloped
			Gross			Net						Gross			Net
Consolidated operations
Alaska			718			533						1,075			1,044
Lower 48			3,381			2,243						10,229			8,038
United States			4,099			2,776						11,304			9,082
Canada			304			280						3,406			2,014
Europe			451			60						798			300
Asia Pacific/Middle East			422			152						11,088			7,439
Africa			358			73						12,545			2,561
Other areas			—			—						156			125
Total consolidated operations			5,634			3,341						39,297			21,521
Equity affiliates
Asia Pacific/Middle East			1,055			319						4,238			1,100
Total equity affiliates			1,055			319						4,238			1,100

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Costs Incurred

Year Ended December 31			Millions of Dollars
Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Other Areas			Total
2023
Consolidated operations
Unproved property acquisition			$	—		157			157			156			—			—			—			—			313
Proved property acquisition			—			106			106			2,973			—			—			—			—			3,079
			—			263			263			3,129			—			—			—			—			3,392
Exploration			67			396			463			144			45			49			4			3			708
Development			1,884			6,266			8,150			367			843			383			38			—			9,781
			$	1,951		6,925			8,876			3,640			888			432			42			3			13,881
Equity affiliates
Unproved property acquisition			$	—		—			—			—			—			—			—			—			—
Proved property acquisition			—			—			—			—			—			—			—			—			—
			—			—			—			—			—			—			—			—			—
Exploration			—			—			—			—			—			46			—			—			46
Development			—			—			—			—			—			416			—			—			416
			$	—		—			—			—			—			462			—			—			462
2022
Consolidated operations
Unproved property acquisition			$	—		255			255			—			—			—			—			—			255
Proved property acquisition			—			249			249			—			—			—			104			—			353
			—			504			504			—			—			—			104			—			608
Exploration			61			1,278			1,339			99			121			59			3			2			1,623
Development			1,316			4,559			5,875			475			711			425			4			—			7,490
			$	1,377		6,341			7,718			574			832			484			111			2			9,721
Equity affiliates
Unproved property acquisition			$	—		—			—			—			—			—			—			—			—
Proved property acquisition			—			—			—			—			—			881			—			—			881
			—			—			—			—			—			881			—			—			881
Exploration			—			—			—			—			—			25			—			—			25
Development			—			—			—			—			—			244			—			—			244
			$	—		—			—			—			—			1,150			—			—			1,150
2021
Consolidated operations
Unproved property acquisition			$	1		11,261			11,262			4			—			—			—			—			11,266
Proved property acquisition			—			16,101			16,101			1			—			—			—			—			16,102
			1			27,362			27,363			5			—			—			—			—			27,368
Exploration			84			765			849			80			31			51			2			40			1,053
Development			949			2,461			3,410			175			398			433			24			—			4,440
			$	1,034		30,588			31,622			260			429			484			26			40			32,861
Equity affiliates
Unproved property acquisition			$	—		—			—			—			—			—			—			—			—
Proved property acquisition			—			—			—			—			—			—			—			—			—
			—			—			—			—			—			—			—			—			—
Exploration			—			—			—			—			—			5			—			—			5
Development			—			—			—			—			—			21			—			—			21
			$	—		—			—			—			—			26			—			—			26

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Capitalized Costs

At December 31			Millions of Dollars
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Other Areas			Total
2023
Consolidated operations
Proved property			$	26,358		70,621			96,979			11,255			14,124			10,923			1,113						134,394
Unproved property			108			3,393			3,501			1,443			65			90			98			9			5,206
			26,466			74,014			100,480			12,698			14,189			11,013			1,211			9			139,600
Accumulated depreciation, depletion and amortization			12,789			36,829			49,618			3,377			9,978			8,423			508			9			71,913
			$	13,677		37,185			50,862			9,321			4,211			2,590			703			—			67,687
Equity affiliates
Proved property			$	—		—			—			—			—			11,159			—			—			11,159
Unproved property			—			—			—			—			—			2,263			—			—			2,263
			—			—			—			—			—			13,422			—			—			13,422
Accumulated depreciation, depletion and amortization																		8,779									8,779
			$	—		—			—			—			—			4,643			—			—			4,643
2022
Consolidated operations
Proved property			$	24,041		62,756			86,797			7,487			13,716			10,534			1,075			—			119,609
Unproved property			589			5,145			5,734			1,291			100			93			98			9			7,325
			24,630			67,901			92,531			8,778			13,816			10,627			1,173			9			126,934
Accumulated depreciation, depletion and amortization			11,906			31,455			43,361			2,927			9,774			7,970			458			9			64,499
			$	12,724		36,446			49,170			5,851			4,042			2,657			715			—			62,435
Equity affiliates
Proved property			$	—		—			—			—			—			10,823			—			—			10,823
Unproved property			—			—			—			—			—			2,162			—			—			2,162
			—			—			—			—			—			12,985			—			—			12,985
Accumulated depreciation, depletion and amortization			—			—			—			—			—			8,400			—			—			8,400
			$	—		—			—			—			—			4,585			—			—			4,585

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Supplementary Data			Table of Contents

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities

In accordance with SEC and FASB requirements, amounts were computed using 12-month average prices (adjusted only for existing contractual terms) and end-of-year costs, appropriate statutory tax rates and a prescribed 10 percent discount factor. Twelve-month average prices are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. For all years, continuation of year-end economic conditions was assumed. The calculations were based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, were not considered. The calculations also require assumptions as to the timing of future production of proved reserves and the timing and amount of future development costs, including dismantlement, and future production costs, including taxes other than income taxes.

While due care was taken in its preparation, we do not represent that this data is the fair value of our oil and gas properties, or a fair estimate of the present value of cash flows to be obtained from their development and production.

Discounted Future Net Cash Flows

			Millions of Dollars
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Total
2023
Consolidated operations
Future cash inflows			$	83,793		140,961			224,754			19,937			23,569			11,322			21,562			301,144
Less:
Future production costs			39,069			50,757			89,826			8,699			6,576			4,586			1,008			110,695
Future development costs			13,685			21,391			35,076			2,058			3,802			1,458			400			42,794
Future income tax provisions			7,386			13,163			20,549			880			10,140			1,316			18,687			51,572
Future net cash flows			23,653			55,650			79,303			8,300			3,051			3,962			1,467			96,083
10 percent annual discount			11,522			19,329			30,851			2,723			432			1,257			570			35,833
Discounted future net cash flows			$	12,131		36,321			48,452			5,577			2,619			2,705			897			60,250
Equity affiliates
Future cash inflows			$	—		—			—			—			—			51,887			—			51,887
Less:
Future production costs			—			—			—			—			—			28,579			—			28,579
Future development costs			—			—			—			—			—			2,299			—			2,299
Future income tax provisions			—			—			—			—			—			5,647			—			5,647
Future net cash flows			—			—			—			—			—			15,362			—			15,362
10 percent annual discount			—			—			—			—			—			5,543			—			5,543
Discounted future net cash flows			$	—		—			—			—			—			9,819			—			9,819
Total company
Discounted future net cash flows			$	12,131		36,321			48,452			5,577			2,619			12,524			897			70,069

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			Millions of Dollars
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Total
2022
Consolidated operations
Future cash inflows			$	94,332		195,605			289,937			13,768			44,942			13,458			27,067			389,172
Less:
Future production costs			47,979			63,987			111,966			5,722			7,559			5,582			1,085			131,914
Future development costs			8,501			21,379			29,880			960			4,378			1,159			531			36,908
Future income tax provisions			8,882			23,136			32,018			863			25,416			1,780			23,615			83,692
Future net cash flows			28,970			87,103			116,073			6,223			7,589			4,937			1,836			136,658
10 percent annual discount			13,733			31,191			44,924			1,936			1,827			1,505			746			50,938
Discounted future net cash flows			$	15,237		55,912			71,149			4,287			5,762			3,432			1,090			85,720
Equity affiliates
Future cash inflows			$	—		—			—			—			—			87,644			—			87,644
Less:
Future production costs			—			—			—			—			—			51,912			—			51,912
Future development costs			—			—			—			—			—			2,685			—			2,685
Future income tax provisions			—			—			—			—			—			8,988			—			8,988
Future net cash flows			—			—			—			—			—			24,059			—			24,059
10 percent annual discount			—			—			—			—			—			10,787			—			10,787
Discounted future net cash flows			$	—		—			—			—			—			13,272			—			13,272
Total company
Discounted future net cash flows			$	15,237		55,912			71,149			4,287			5,762			16,704			1,090			98,992

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			Millions of Dollars
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Total
2021
Consolidated operations
Future cash inflows			$	65,910		125,197			191,107			10,847			21,670			11,583			15,778			250,985
Less:
Future production costs			34,444			43,034			77,478			4,960			6,090			4,987			801			94,316
Future development costs			8,033			13,386			21,419			923			3,960			1,314			413			28,029
Future income tax provisions			5,310			13,167			18,477			117			8,345			1,542			13,506			41,987
Future net cash flows			18,123			55,610			73,733			4,847			3,275			3,740			1,058			86,653
10 percent annual discount			7,963			22,290			30,253			1,639			696			930			440			33,958
Discounted future net cash flows			$	10,160		33,320			43,480			3,208			2,579			2,810			618			52,695
Equity affiliates
Future cash inflows			$	—		—			—			—			—			27,851			—			27,851
Less:
Future production costs			—			—			—			—			—			15,491			—			15,491
Future development costs			—			—			—			—			—			1,649			—			1,649
Future income tax provisions			—			—			—			—			—			3,071			—			3,071
Future net cash flows			—			—			—			—			—			7,640			—			7,640
10 percent annual discount			—			—			—			—			—			2,640			—			2,640
Discounted future net cash flows			$	—		—			—			—			—			5,000			—			5,000
Total company
Discounted future net cash flows			$	10,160		$	33,320		$	43,480		$	3,208		$	2,579		$	7,810		$	618		$	57,695

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Sources of Change in Discounted Future Net Cash Flows

			Millions of Dollars
			Consolidated Operations												Equity Affiliates												Total Company
			2023			2022			2021						2023			2022			2021						2023			2022			2021
Discounted future net cash flows at the beginning of the year			$	85,720		$	52,695		4,674						$	13,272		5,000			2,862						$	98,992		57,695			7,536
Changes during the year
Revenues less production costs for the year			(23,706)			(33,532)			(20,000)						(2,550)			(3,245)			(1,389)						(26,256)			(36,777)			(21,389)
Net change in prices, and production costs			(48,717)			61,902			50,956						(4,519)			8,184			3,822						(53,236)			70,086			54,778
Extensions, discoveries and improved recovery, less estimated future costs			1,864			7,882			10,420						118			1,472			(44)						1,982			9,354			10,376
Development costs for the year			9,129			6,687			4,396						326			272			91						9,455			6,959			4,487
Changes in estimated future development costs			(6,754)			(4,088)			(33)						(150)			189			(104)						(6,904)			(3,899)			(137)
Purchases of reserves in place, less estimated future costs			3,029			3,353			17,833						—			1,282			—						3,029			4,635			17,833
Sales of reserves in place, less estimated future costs			(472)			(3,847)			(468)						—			—			—						(472)			(3,847)			(468)
Revisions of previous quantity estimates			9,503			13,080			2,985						492			2,193			178						9,995			15,273			3,163
Accretion of discount			12,414			7,021			964						1,635			616			344						14,049			7,637			1,308
Net change in income taxes			18,240			(25,433)			(19,032)						1,195			(2,691)			(760)						19,435			(28,124)			(19,792)
Total changes			(25,470)			33,025			48,021						(3,453)			8,272			2,138						(28,923)			41,297			50,159
Discounted future net cash flows at year end			$	60,250		$	85,720		52,695						$	9,819		13,272			5,000						$	70,069		98,992			57,695

• The net change in prices and production costs is the beginning-of-year reserve-production forecast multiplied by the net annual change in the per-unit sales price and production cost, discounted at 10 percent.

• Purchases and sales of reserves in place, along with extensions, discoveries and improved recovery, are calculated using production forecasts of the applicable reserve quantities for the year multiplied by the 12-month average sales prices, less future estimated costs, discounted at 10 percent.

• Revisions of previous quantity estimates are calculated using production forecast changes for the year, including changes in the timing of production, multiplied by the 12-month average sales prices, less future estimated costs, discounted at 10 percent.

• The accretion of discount is 10 percent of the prior year’s discounted future cash inflows, less future production and development costs.

• The net change in income taxes is the annual change in the discounted future income tax provisions.

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