Item 8. Financial Statements and Supplementary Data

ConocoPhillips

Index to Financial Statements
			Page
Reports of Management			67
Reports of Independent Registered Public Accounting Firm (PCAOB ID #42)			68
Financial Statements
Consolidated Income Statement for the years ended December 31, 2025, 2024 and 2023			71
Consolidated Statement of Comprehensive Income for the years ended December 31, 2025, 2024 and 2023			72
Consolidated Balance Sheet at December 31, 2025 and 2024			73
Consolidated Statement of Cash Flows for the years ended December 31, 2025, 2024 and 2023			74
Consolidated Statement of Changes in Equity for the years ended December 31, 2025, 2024 and 2023			75
Notes to Consolidated Financial Statements
Note 1—Accounting Policies			76
Note 2—Inventories			80
Note 3—Acquisitions and Dispositions			80
Note 4—Investments, Loans and Long-Term Receivables			84
Note 5—Suspended Wells and Exploration Expenses			86
Note 6—Asset Retirement Obligations and Accrued Environmental Costs			88
Note 7—Debt			89
Note 8—Guarantees			93
Note 9—Contingencies and Commitments			94
Note 10—Derivatives and Financial Instruments			96
Note 11—Fair Value Measurement			100
Note 12—Equity			102
Note 13—Non-Mineral Leases			103
Note 14—Employee Benefit Plans			106
Note 15—Income Taxes			118
Note 16—Accumulated Other Comprehensive Income (Loss)			122
Note 17—Cash Flow Information			122
Note 18—Sales and Other Operating Revenues			123
Note 19—Related Party Transactions			123
Note 20—Other Financial Information			124
Note 21—Earnings Per Share			125
Note 22—Segment Disclosures and Related Information			125
Note 23—New Accounting Standards			129
Supplementary Information
Oil and Gas Operations			130

ConocoPhillips 2025 10-K			66

			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, 2025. 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, 2025.

Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2025, and their report is included herein.

/s/ Ryan M. Lance			/s/ Andrew M. O'Brien
Ryan M. Lance			Andrew M. O'Brien
Chairman and Chief Executive Officer			Chief Financial Officer and Executive Vice President, Strategy & Commercial

67			ConocoPhillips 2025 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, 2025 and 2024, the related consolidated income statement, consolidated statements of comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, 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, 2025, 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 17, 2026 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 disclosures to which it relates.

ConocoPhillips 2025 10-K			68

			Table of Contents

			Depreciation, depletion and amortization of proved oil and gas properties, plants and equipment associated with the Lower 48 segment
Description of the Matter			At December 31, 2025, the net book value of the Company’s proved oil and gas properties, plants and equipment (PP&E) associated with the Lower 48 segment was $47 billion, and depreciation, depletion and amortization (DD&A) expense associated with the Lower 48 segment 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 related assets 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. 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 costs assumptions, among others. Auditing the Lower 48 segment’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 certain 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 the Lower 48 segment DD&A, including management’s controls over the completeness and accuracy of significant data provided to the internal reservoir engineers for use in estimating proved oil and gas reserves associated with the Lower 48 segment. 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 associated with the Lower 48 segment. In addition, in assessing whether we can use the work of the internal reservoir engineers, we evaluated the completeness and accuracy of the significant 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 associated with the Lower 48 segment, including comparing the proved oil and gas reserves amounts used in the calculation to the Company’s reserve report.

/s/ Ernst & Young LLP

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

Houston, Texas

February 17, 2026

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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, 2025, 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, 2025, 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, 2025 and 2024, the related consolidated income statement, consolidated statements of comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2025, and the related notes and our report dated February 17, 2026 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 17, 2026

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Financial Statements			Table of Contents

Consolidated Income Statement			ConocoPhillips

Years Ended December 31			Millions of Dollars
			2025			2024			2023
Revenues and other income
Sales and other operating revenues			$	58,944		54,745			56,141
Equity in earnings of affiliates			1,335			1,705			1,720
Gain (loss) on dispositions			731			51			228
Other income			538			452			485
Total revenues and other income			61,548			56,953			58,574
Costs and expenses
Purchased commodities			22,325			20,012			21,975
Production and operating expenses			10,331			8,751			7,693
Selling, general and administrative expenses			893			1,158			705
Exploration expenses			407			355			398
Depreciation, depletion and amortization			11,500			9,599			8,270
Impairments			26			80			14
Taxes other than income taxes			2,146			2,087			2,074
Accretion on discounted liabilities			378			325			283
Interest and debt expense			855			783			780
Foreign currency transaction (gain) loss			11			(50)			92
Other expenses			20			181			2
Total costs and expenses			48,892			43,281			42,286
Income (loss) before income taxes			12,656			13,672			16,288
Income tax provision (benefit)			4,668			4,427			5,331
Net income (loss)			$	7,988		9,245			10,957
Net income (loss) per share of common stock (dollars)
Basic			$	6.36		7.82			9.08
Diluted			6.35			7.81			9.06
Weighted-average common shares outstanding (in thousands)
Basic			1,252,042			1,178,920			1,202,757
Diluted			1,253,446			1,180,871			1,205,675

See Notes to Consolidated Financial Statements.

71			ConocoPhillips 2025 10-K

Financial Statements			Table of Contents

Consolidated Statement of Comprehensive Income			ConocoPhillips

Years Ended December 31			Millions of Dollars
			2025			2024			2023
Net income (loss)			$	7,988		9,245			10,957
Other comprehensive income (loss), net of tax:
Defined benefit plans			55			3			55
Unrealized holding gain (loss) on securities			5			1			13
Foreign currency translation adjustments			502			(760)			197
Unrealized gain (loss) on hedging activities			—			(44)			62
Other comprehensive income (loss), net of tax			562			(800)			327
Comprehensive income (loss)			$	8,550		8,445			11,284

See Notes to Consolidated Financial Statements.

ConocoPhillips 2025 10-K			72

Financial Statements			Table of Contents

Consolidated Balance Sheet			ConocoPhillips

At December 31			Millions of Dollars
			2025			2024
Assets
Cash and cash equivalents			$	6,497		5,607
Short-term investments			484			507
Accounts and notes receivable (net of allowance of $4 and $7, respectively)			5,813			6,695
Inventories			1,873			1,809
Prepaid expenses and other current assets			865			1,029
Total current assets			15,532			15,647
Investments and long-term receivables			10,185			9,869
Net properties, plants and equipment (net of accumulated DD&A of $90,396 and $81,072, respectively)			93,239			94,356
Other assets			2,983			2,908
Total assets			$	121,939		122,780
Liabilities
Accounts payable			$	6,218		6,044
Short-term debt			1,020			1,035
Accrued income and other taxes			1,835			2,460
Employee benefit obligations			1,136			1,087
Other accruals			1,763			1,498
Total current liabilities			11,972			12,124
Long-term debt			22,424			23,289
Asset retirement obligations and accrued environmental costs			8,214			8,089
Deferred income taxes			12,237			11,426
Employee benefit obligations			969			1,022
Other liabilities and deferred credits			1,636			2,034
Total liabilities			57,452			57,984
Equity
Common stock (2,500,000,000 shares authorized at $0.01 par value) Issued (2025—2,253,518,282 shares; 2024—2,250,672,734 shares)
Par value			23			23
Capital in excess of par			77,728			77,529
Treasury stock (at cost: 2025—1,028,350,186 shares; 2024—974,806,010 shares)			(76,217)			(71,152)
Accumulated other comprehensive income (loss)			(5,911)			(6,473)
Retained earnings			68,864			64,869
Total equity			64,487			64,796
Total liabilities and equity			$	121,939		122,780

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
			2025			2024			2023
Cash flows from operating activities
Net income (loss)			$	7,988		9,245			10,957
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization			11,500			9,599			8,270
Impairments			26			80			14
Dry hole costs and leasehold impairments			181			46			162
Accretion on discounted liabilities			378			325			283
Deferred taxes			549			367			1,145
Distributions more (less) than income from equity affiliates			200			564			964
(Gain) loss on dispositions			(731)			(51)			(228)
Other			(219)			130			(220)
Working capital adjustments
Decrease (increase) in accounts and notes receivable			803			(262)			1,333
Decrease (increase) in inventories			(116)			(68)			(103)
Decrease (increase) in prepaid expenses and other current assets			(24)			79			337
Increase (decrease) in accounts payable			(212)			(543)			(1,118)
Increase (decrease) in taxes and other accruals			(527)			613			(1,831)
Net cash provided by operating activities			19,796			20,124			19,965
Cash flows from investing activities
Capital expenditures and investments			(12,553)			(12,118)			(11,248)
Working capital changes associated with investing activities			546			302			30
Acquisition of businesses, net of cash acquired			—			(24)			(2,724)
Proceeds from asset dispositions			3,248			261			632
Net sales (purchases) of investments			(55)			415			1,373
Other			(22)			14			(63)
Net cash used in investing activities			(8,836)			(11,150)			(12,000)
Cash flows from financing activities
Issuance of debt			—			5,591			3,787
Repayment of debt			(913)			(4,981)			(1,379)
Issuance of company common stock			(100)			(78)			(52)
Repurchase of company common stock			(5,018)			(5,463)			(5,400)
Dividends paid			(3,995)			(3,646)			(5,583)
Other			(76)			(258)			(34)
Net cash used in financing activities			(10,102)			(8,835)			(8,661)
Effect of exchange rate changes on cash, cash equivalents and restricted cash			153			(133)			(99)
Net change in cash, cash equivalents and restricted cash			1,011			6			(795)
Cash, cash equivalents and restricted cash at beginning of period			5,905			5,899			6,694
Cash, cash equivalents and restricted cash at end of period			$	6,916		5,905			5,899

Restricted cash of $65 million is included in the "Prepaid expenses and other current assets" line of our Consolidated Balance Sheet

as of December 31, 2025.

Restricted cash of $354 million and $298 million is included in the “Other assets” line of our Consolidated Balance Sheet at December 31, 2025, and December 31, 2024, 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, 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
Net income (loss)															9,245						9,245
Other comprehensive income (loss)												(800)									(800)
Dividends declared
Ordinary ($2.52 per share of common stock)															(2,942)						(2,942)
Variable return of cash ($0.60 per share of common stock)															(704)						(704)
Acquisition of Marathon Oil			2			16,037															16,039
Repurchase of company common stock									(5,463)												(5,463)
Excise tax on share repurchases									(50)												(50)
Distributed under benefit plans						189															189
Other									1						2						3
Balances at December 31, 2024			$	23		77,529			(71,152)			(6,473)			64,869						64,796
Net income (loss)															7,988						7,988
Other comprehensive income (loss)												562									562
Dividends declared
Ordinary ($3.18 per share of common stock)															(3,995)						(3,995)
Repurchase of company common stock									(5,018)												(5,018)
Excise tax on share repurchases									(47)												(47)
Distributed under benefit plans						199															199
Other									—						2						2
Balances at December 31, 2025			$	23		77,728			(76,217)			(5,911)			68,864						64,487

See Notes to Consolidated Financial Statements.

75			ConocoPhillips 2025 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. We manage our operations through five operating segments, defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; and Asia Pacific. See Note 22.

• 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.

ConocoPhillips 2025 10-K			76

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 commodity 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 5.

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 developed and proved undeveloped 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 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 6.

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 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 Restricted Stock Units (RSUs) under its share-based compensation programs, the majority of which entitle recipients to receive non-forfeitable dividends during the vesting period on a basis equivalent to dividends paid to holders of the company’s common stock. See Note 14. 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 21.

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Note 2—Inventories

Inventories at December 31 were:

			Millions of Dollars
			2025			2024
Crude oil and products			$	1,000		907
Materials and supplies			873			902
Total inventories			$	1,873		1,809
Inventories valued on the LIFO basis			$	609		578

The estimated excess of current replacement cost over LIFO cost of inventories was approximately $65 million and $113 million at December 31, 2025 and 2024, 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. Cash proceeds and payments are included in the “Cash flows from investing activities” section of our consolidated statement of cash flows except for cash payments associated with a contingent consideration arrangement that are included in the "Cash flows from financing activities" section.

2025

Assets Sold

In the second quarter of 2025, we sold our interests in the Ursa and Europa fields and Ursa Oil Pipeline Company LLC for net proceeds of $699 million. We recognized a $274 million before-tax and $266 million after-tax gain for this transaction, inclusive of the reduction of our valuation allowance recognized in the first quarter of 2025. At the time of disposition, these assets, in our Lower 48 segment, had a net carrying value of $444 million, comprised of $536 million of assets, primarily $522 million of PP&E, and $92 million of liabilities, primarily related to noncurrent AROs. For tax-related impacts of this disposition, see Note 15.

In the fourth quarter of 2025, we sold Lower 48 assets in the Anadarko basin for net proceeds of $1.2 billion, after customary closing adjustments. At the time of the disposition, these assets had a net carrying value of approximately $1.2 billion, comprised primarily of PP&E.

Additionally, during 2025, we sold our interests in other noncore assets in the Lower 48 segment for $1.1 billion and recognized a $404 million before-tax and $310 million after-tax net gain. Our interests in the disposed assets had an aggregate net carrying value of $719 million, comprised of $770 million of assets, primarily related to $645 million of PP&E and $51 million of liabilities related to noncurrent AROs.

2024

Acquisition of Marathon Oil Corporation (Marathon Oil)

In November 2024, we completed our acquisition of Marathon Oil, an independent oil and gas exploration and production company with operations across the Lower 48 and in Equatorial Guinea. At close, the transaction was valued at $16.5 billion, which primarily represented 0.255 shares of ConocoPhillips common stock exchanged for each outstanding share of Marathon Oil common stock.

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Total fair value			Millions of Dollars
Value of ConocoPhillips common stock issued*			15,972
Cash transferred at close**			451
Value attributable to Marathon Oil share-based awards			67
Other liabilities incurred***			17
Total fair value			$	16,507

*Represents the fair value of approximately 143 million shares of ConocoPhillips common stock issued to Marathon Oil stockholders. The fair value is based on the number of eligible shares of Marathon Oil common stock at a 0.255 exchange ratio and ConocoPhillips' average stock price on November 22, 2024, which was $111.93.

**Cash transferred at close primarily represents funds contributed to Marathon Oil for repayment of Marathon Oil's estimated commercial paper liabilities as of the closing date.

***Liabilities incurred are related to cash settled share-based awards and payment of cash in lieu of fractional Marathon Oil shares outstanding. These liabilities were settled prior to the end of 2024.

The transaction was 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. In the fourth quarter of 2025, we finalized the allocation of the purchase price to specific assets and liabilities. It was based on the fair value of the final consideration and the conclusion of the fair value determination of long-lived assets and all other assets acquired and liabilities assumed.

Oil and gas properties were valued using a discounted cash flow approach incorporating market participant and internally generated price assumptions; production profiles; and operating and development cost assumptions. Debt assumed in the acquisition was valued based on observable market prices. The fair values of 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 acquisition, valued at $16.5 billion, was allocated to the identifiable assets and liabilities based on their estimated fair values as of the acquisition date of November 22, 2024.

Assets acquired			Millions of Dollars
Cash and cash equivalents			$	385
Accounts receivable, net			976
Inventories			302
Investments and long-term receivables			562
Net properties, plants and equipment			24,215
Other assets			215
Total assets acquired			$	26,655
Liabilities assumed
Accounts payable			$	1,183
Accrued income and other taxes			201
Employee benefit obligations			187
Long-term debt			4,719
Asset retirement obligations			781
Deferred income taxes			2,471
Other liabilities			606
Total liabilities assumed			$	10,148
Net assets acquired			$	16,507

With the completion of the transaction, we acquired proved properties of approximately $13.2 billion, with $12.1 billion in Lower 48 and $1.1 billion in Equatorial Guinea, and unproved properties of $10.8 billion in Lower 48.

We have recognized approximately $587 million of transaction-related costs, the majority of which were expensed in the fourth quarter of 2024. These non-recurring costs related primarily to employee severance and related benefits, fees paid to advisors and the settlement of share-based awards for certain Marathon Oil employees based on the terms of the Merger Agreement. These transaction-related costs included $334 million of employee severance expense. See Note 14.

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For the year ended December 31, 2024, "Total revenues and other income" and "Net income (loss)" associated with the acquired assets were $677 million and income of $66 million, respectively.

Alaska Acquisition

In the fourth quarter of 2024, after exercising our preferential rights, we completed an acquisition that increased our working interest by approximately 5 percent in the Kuparuk River Unit and approximately 0.4 percent in the Prudhoe Bay Unit from Chevron U.S.A. Inc. and Union Oil Company of California for $296 million, before customary adjustments. The transaction was accounted for as an asset acquisition, with the consideration allocated primarily to PP&E.

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 final consideration for the all-cash transaction was $3.0 billion (CAD $4.1 billion) after customary adjustments:

Fair value of consideration			Millions of Dollars
Cash paid			$	2,635
Contingent consideration			320
Total consideration			$	2,955

For information related to the contingent consideration arrangement, see Note 11.

The transaction was 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. By the end of the first quarter of 2024, we finalized the allocation of the purchase price to specific assets and liabilities. It was based on the fair value of the final consideration and the conclusion of the fair value determination of long-lived assets and all other assets acquired and liabilities assumed.

Oil and gas properties were valued using a discounted cash flow approach incorporating market participant 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 of October 4, 2023.

Recognized amounts of identifiable assets acquired and liabilities assumed			Millions of Dollars
Oil and gas properties			3,082
Asset retirement obligations			(112)
Other			(15)
Total identifiable net assets			$	2,955

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. For the year ended December 31, 2023, we 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.

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Supplemental Pro Forma (unaudited)

The following tables summarize the unaudited supplemental pro forma financial information combining the consolidated income statement of ConocoPhillips with assets acquired as shown for the year ended December 31, 2024 and 2023, as if we had completed the acquisition of Marathon Oil on January 1, 2023 and the remaining working interest in Surmont on January 1, 2022, respectively.

			Millions of Dollars
			Year Ended December 31, 2024
			As reported									Pro forma Marathon Oil			Pro forma Combined
Total revenues and other income			$	56,953								6,168			63,121
Net income (loss)			9,245									1,312			10,557
Earnings per share:
Basic net income (loss)			$	7.82											8.06
Diluted net income (loss)			7.81												8.05
			Millions of Dollars
			Year Ended December 31, 2023
			As reported						Pro forma Surmont			Pro forma Marathon Oil			Pro forma Combined
Total revenues and other income			$	58,574					2,561			6,705			67,840
Net income (loss)			10,957						501			1,657			13,115
Earnings per share:
Basic net income (loss)			$	9.08											9.72
Diluted net income (loss)			9.06												9.70

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 Surmont and Marathon Oil transactions been completed on January 1, 2022, and January 1, 2023, respectively, nor is it necessarily indicative of future operating results of the combined entity. The pro forma results do not include 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 oil and gas properties as well as adjustments for the timing of transaction costs and tax impacts. We believe the estimates and assumptions are reasonable, and the relative effects of the transaction are properly reflected.

QatarEnergy LNG NFS(3) (NFS3)

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 in Qatar. 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.

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Note 4—Investments, Loans and Long-Term Receivables

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

			Millions of Dollars
			2025			2024
Equity investments			$	8,833		8,611
Long-term receivables			110			113
Long-term investments in debt securities			1,148			1,055
Other investments			94			90
Total			$	10,185		9,869

Equity Investments

Affiliated companies in which we had a significant equity investment at December 31, 2025, 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.

• 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)—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)—25 percent owned joint venture with affiliates of QatarEnergy (70 percent) and China National Petroleum Corporation (5 percent)—participant in the North Field East LNG project.

• NFS3—25 percent owned joint venture with an affiliate of QatarEnergy (75 percent)—participant in the North Field South LNG project. See Note 3.

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

			Millions of Dollars
			2025			2024			2023
Revenues			$	13,607		15,286			15,314
Income (loss) before income taxes			5,022			6,446			6,301
Net income (loss)			3,441			4,389			4,214

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

			Millions of Dollars
			2025			2024
Current assets			$	5,793		4,608
Noncurrent assets			43,935			41,417
Current liabilities			3,521			3,829
Noncurrent liabilities			18,815			16,947

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, 2025, retained earnings included $112 million related to the undistributed earnings of affiliated companies. Dividends received from affiliates were $1,531 million, $2,283 million and $2,684 million in 2025, 2024 and 2023, respectively.

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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, 2025, a balance of $3.4 billion was outstanding on the facilities. See Note 8.

At December 31, 2025, the carrying value of our equity method investment in APLNG was approximately $4.9 billion.

PALNG

PALNG is a joint venture for the development of a large-scale LNG facility. At December 31, 2025, the carrying value of our equity method investment in PALNG was approximately $1.6 billion. See Note 3.

Investments in Qatar

N3

N3 is a 30 percent owned joint venture in an integrated large-scale LNG project. 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 participating in the NFE LNG project. NFE4 has a 12.5 percent interest in the NFE project.

We have concluded NFE4 is a VIE as it currently requires advances from the joint venture participants to fund the project. We are not the primary beneficiary of the VIE because we do not have the power to direct the activities that most significantly impact economic performance of NFE4, which involve activities related to the production and commercialization of natural gas, as well as LNG processing and export marketing. As a result, we do not consolidate NFE4, and it is accounted for under the equity method. As of December 31, 2025, the carrying value of our equity is included in the total carrying value of our equity method investments in Qatar. This equity together with the guarantee is the only financial support that we have provided NFE4. See Note 8.

NFS3

NFS3 is a joint venture participating in the NFS LNG project. NFS3 has a 25 percent interest in the NFS project. See Note 3.

At December 31, 2025, the carrying value of our equity method investments in Qatar was approximately $1.7 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, 2025, there were no outstanding loans to affiliated companies.

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Note 5—Suspended Wells and Exploration Expenses

The following table reflects the net changes in suspended exploratory well costs during 2025, 2024 and 2023:

			Millions of Dollars
			2025			2024			2023
Beginning balance			$	196		184			527
Additions pending the determination of proved reserves			113			32			—
Reclassifications to proved properties			—			(2)			(285)
Sales of suspended wells			(30)			—			—
Charged to dry hole expense			(36)			(18)			(58)
Ending balance			$	243		196			184

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

			Millions of Dollars
			2025			2024			2023
Exploratory well costs capitalized for a period of one year or less			$	110		33			—
Exploratory well costs capitalized for a period greater than one year			133			163			184
Ending balance			$	243		196			184
Number of projects with exploratory well costs capitalized for a period greater than one year			13			13			14

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, 2025:

			Millions of Dollars
						Suspended Since
			Total			2021-2024			2018-2020			2017 and Prior
PL891—Norway(1)			31			—			31			—
West Willow—Alaska(2)			30			—			30			—
Narwhal Trend—Alaska(1)			25			—			25			—
Montney—Canada(2)			15			7			8			—
Other of $10 million or less each(1)(2)			32			4			—			28
Total			$	133		11			94			28

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

*(2)*Additional appraisal wells planned.

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Exploration Expenses

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

2025

We divested certain Lower 48 offshore interests in partner-operated assets, which included $30 million of suspended wells costs.

We recognized dry hole expenses of $80 million in our Asia Pacific segment, which included $36 million related to certain previously suspended wells that were capitalized for a period greater than one year.

2024

In our Europe, Middle East and North Africa segment, we recorded approximately $40 million before-tax as dry hole expenses, which included $22 million for two partner-operated exploration wells in the Alvheim area in the Norwegian sector of the North Sea, and $18 million for the Busta suspended discovery well on license PL782S in the North Sea.

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.

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Note 6—Asset Retirement Obligations and Accrued Environmental Costs

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

			Millions of Dollars
			2025			2024
Asset retirement obligations			$	8,364		8,215
Accrued environmental costs			220			206
Total asset retirement obligations and accrued environmental costs			8,584			8,421
Asset retirement obligations and accrued environmental costs due within one year*			(370)			(332)
Long-term asset retirement obligations and accrued environmental costs			$	8,214		8,089

*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. Changes to estimated liabilities for assets that are no longer producing are recorded as 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 2025 and 2024, our overall ARO changed as follows:

			Millions of Dollars
			2025			2024
Balance at January 1			$	8,215		7,227
Accretion of discount			366			319
New obligations, including acquisitions			162			926
Changes in estimates of existing obligations			(150)			140
Spending on existing obligations			(259)			(182)
Property dispositions			(186)			(6)
Foreign currency translation			216			(209)
Balance at December 31			$	8,364		8,215

Accrued Environmental Costs

Total accrued environmental costs at December 31, 2025 and 2024, were $220 million and $206 million, respectively.

We had accrued environmental costs of $142 million and $139 million at December 31, 2025 and 2024, respectively, related to remediation activities in the U.S. and Canada. We had also accrued in Corporate and Other $68 million and $56 million of environmental costs associated with sites no longer in operation at December 31, 2025 and 2024, respectively. In addition, December 31, 2025 and 2024, included a $10 million and $11 million accrual, respectively, where the company has been named a potentially responsible party under the CERCLA, 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 $119 million at December 31, 2025. The total expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are $133 million.

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Note 7—Debt

Long-term debt at December 31 was:

			Millions of Dollars
			2025			2024
2.4% Notes due 2025			—			366
8.2% Debentures due 2025			—			134
3.35% Notes due 2025			—			199
6.875% Debentures due 2026			67			67
7.8% Debentures due 2027			120			120
4.4% Notes due 2027			422			424
3.75% Notes due 2027			196			196
4.3% Notes due 2028			223			223
7.375% Debentures due 2029			66			66
7.0% Debentures due 2029			95			95
5.3% Notes due 2029			84			86
6.95% Notes due 2029			705			705
4.7% Notes due 2030			1,350			1,350
8.125% Notes due 2030			207			207
2.4% Notes due 2031			227			227
7.2% Notes due 2031			447			447
7.25% Notes due 2031			268			268
7.4% Notes due 2031			232			232
4.85% Notes due 2032			650			650
6.8% Notes due 2032			180			180
5.9% Notes due 2032			505			505
5.05% Notes due 2033			1,000			1,000
5.7% Notes due 2034			103			103
4.15% Notes due 2034			246			246
5.0% Notes due 2035			1,250			1,250
5.95% Notes due 2036			326			326
5.951% Notes serially maturing 2022 through 2037			541			573
6.6% Notes due 2037			335			335
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
5.2% Notes due 2045			186			186
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			1,100
5.55% Notes due 2054			1,000			1,000
5.5% Notes due 2055			1,300			1,300
4.025% Notes due 2062			1,770			1,770
5.7% Notes due 2063			700			700
5.65% Notes due 2065			650			650
Marine Terminal Revenue Refunding Bonds due 2031 at 1.23% – 5.05% during 2025 and 1.78% – 4.80% during 2024			265			265

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Industrial Development Bonds due 2035 at 1.23% – 5.05% during 2025 and 1.78% – 4.22% during 2024			18			18
St. John the Baptist Parish, State of Louisiana—Revenue Refunding Bonds due 20371: $200 at 2.20%, $200 at 2.375%, $200 at 4.05%, $400 at 3.30%1			1,000			1,000
Other			13			16
Debt at face value			23,347			24,085
Finance leases			801			940
Net unamortized premiums, discounts and debt issuance costs			(704)			(701)
Total debt			23,444			24,324
Short-term debt			(1,020)			(1,035)
Long-term debt			$	22,424		23,289

1**Future mandatory purchase dates for these bonds: July 1, 2026 for the 2.20% bonds of $200 million, 2.375% bonds of $200 million, 4.05% bonds of $200 million and July 3, 2028 for the 3.30% bonds of $400 million. Subsequent to the mandatory purchase dates, we will also have the right to remarket

these bonds any time up to the 2037 maturity date.

The principal amounts of long-term debt, excluding finance lease obligations, maturing in 2026 through 2030 are: $713 million, of which $600 million are municipal bonds we intend to remarket, $786 million, $670 million, $992 million and $1,599 million, respectively.

2025

In 2025, the company retired $0.7 billion principal amount of debt at maturity, consisting of $0.2 billion of our 3.35% Notes, $0.4 billion of our 2.4% Notes and $0.1 billion of our 8.2% Debentures.

2024

In the fourth quarter of 2024, we acquired Marathon Oil and assumed its outstanding debt upon close. Shortly thereafter, we launched and completed concurrent debt transactions consisting of: tender offers to repurchase certain existing Marathon Oil and ConocoPhillips debt for cash (with priority for Marathon Oil debt assumed), an obligor exchange offer to retire certain Marathon Oil debt in exchange for new ConocoPhillips debt, new debt issuances to fund the repurchase tender offers and the remarketing of available municipal bonds. See Note 3.

Marathon Oil Debt Assumed at Fair Value

As part of the acquisition, we assumed Marathon Oil's publicly traded debt, with an outstanding principal balance of $4.6 billion, which was recorded at fair value of $4.7 billion. See Note 3.

• 4.4% Notes due 2027 with principal amount of $1,000 million

• 5.3% Notes due 2029 with principal amount of $600 million

• 6.8% Notes due 2032 with principal amount of $550 million

• 5.7% Notes due 2034 with principal amount of $600 million

• 6.6% Notes due 2037 with principal amount of $750 million

• 5.2% Notes due 2045 with principal amount of $500 million

• St. John the Baptist Parish, State of Louisiana—Revenue Refunding Bonds due 2037 with future mandatory purchase dates of July 1, 2026:

*◦*2.20% Bonds with principal amount of $200 million

*◦*2.375% Bonds with principal amount of $200 million

◦4.05% Bonds with principal amount of $200 million

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Repurchase Offers

In December 2024, we completed tender offers through which we repurchased a total of $3,768 million in aggregate principal amount of debt as listed below. We paid premiums above face value of $283 million to repurchase these debt instruments.

Marathon Oil Debt Repurchased:

• 4.4% Notes due 2027 partial repurchase of $576 million

• 5.3% Notes due 2029 partial repurchase of $514 million

• 6.8% Notes due 2032 partial repurchase of $370 million

• 5.7% Notes due 2034 partial repurchase of $497 million

• 6.6% Notes due 2037 partial repurchase of $415 million

• 5.2% Notes due 2045 partial repurchase of $314 million

ConocoPhillips Debt Repurchased:

• 7.8% Debentures due 2027 with principal amount of $203 million (partial repurchase of $83 million)

• 7.0% Debentures due 2029 with principal amount of $112 million (partial repurchase of $17 million)

• 7.375% Debentures due 2029 with principal amount of $92 million (partial repurchase of $26 million)

• 6.95% Notes due 2029 with principal amount of $1,195 million (partial repurchase of $490 million)

• 8.125% Notes due 2030 with principal amount of $390 million (partial repurchase of $183 million)

• 7.4% Notes due 2031 with principal amount of $382 million (partial repurchase of $151 million)

• 7.25% Notes due 2031 with principal amount of $400 million (partial repurchase of $132 million)

Exchange Offer

Concurrently in December 2024, we completed a debt exchange offer through which $863 million in aggregate principal of existing Marathon Oil notes were tendered and accepted in exchange for $862 million of new ConocoPhillips notes. The debt exchange offers were treated as debt modifications for accounting purposes resulting in a portion of the unamortized debt discount and premiums of the existing notes being allocated to the new notes on the settlement dates of the exchange offers. No premiums were paid to bondholders in this exchange offer.

The notes tendered and accepted in the exchange offers were:

• 4.4% Notes due 2027 partial exchange of $228 million

• 5.3% Notes due 2029 partial exchange of $59 million

• 6.8% Notes due 2032 partial exchange of $102 million

• 5.7% Notes due 2034 partial exchange of $63 million

• 6.6% Notes due 2037 partial exchange of $259 million

• 5.2% Notes due 2045 partial exchange of $151 million

New Debt Issuance

In December 2024, we issued new debt of $5.2 billion through our universal shelf registration statement and prospectus supplement consisting of the following new notes and used the proceeds to repurchase existing debt as discussed:

• 4.7% Notes due 2030 with principal of $1,350 million

• 4.85% Notes due 2032 with principal of $650 million

• 5.0% Notes due 2035 with principal of $1,250 million

• 5.5% Notes due 2055 with principal of $1,300 million

• 5.65% Notes due 2065 with principal of $650 million

Municipal Bonds Reoffering and Issuance

We completed a $400 million remarketing of sub-series 2017C bonds that are part of the $1 billion St. John the Baptist Parish, State of Louisiana—Revenue Refunding Bonds Series 2017. The bonds are subject to an interest rate of 3.30% and a mandatory purchase date of July 3, 2028.

As a result of the concurrent debt transactions as described above, we recognized a net loss on debt extinguishments of $173 million which is included in the "Other expenses" line on our consolidated income statement.

Other Debt Activity

Apart from the concurrent debt transactions discussed above, in November 2024, the company retired $265 million principal amount of our 3.35% Notes at maturity and in March 2024, the company retired $461 million principal amount of our 2.125% Notes at maturity.

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Revolving Credit Facility and Credit Rating Information

In February 2025, we refinanced our revolving credit facility maintaining a total aggregate principal amount of $5.5 billion and extended the expiration to February 2030. 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, 2025 and 2024.

For information on Finance Leases, see Note 13.

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, 2025 and 2024, 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 8—Guarantees

At December 31, 2025, 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, 2025, we had multiple outstanding 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 2025 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 five 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, 2025, 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 $600 million ($1.0 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 11 to 20 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $520 million and would become payable if APLNG does not perform. At December 31, 2025, the carrying value of these guarantees was approximately $35 million.

QatarEnergy LNG Limited Guarantees

We have guaranteed our portion of certain fiscal and other joint venture obligations as a shareholder in NFE4 and NFS3. These guarantees have an approximate 30-year term with no maximum limit. At December 31, 2025, the carrying value of these guarantees was approximately $14 million.

Equatorial Guinea Guarantees

We have guaranteed payment obligations as a shareholder in both Equatorial Guinea LNG Operations, S.A., a fully owned subsidiary of Equatorial Guinea LNG Holdings Limited, and Alba Plant LLC with regard to certain agreements to process third-party gas. These guarantees have two years remaining, and the maximum potential future payments related to these guarantees is approximately $116 million. At December 31, 2025, the carrying value of these guarantees was approximately $4 million.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $580 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 one 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, 2025, there was no liability recognized for 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, 2025, was

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approximately $30 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 9 for additional information about environmental liabilities.

Note 9—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 15, 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 U.S. 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 other 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 6 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, 2025, we had performance obligations secured by letters of credit of $331 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, the government of Venezuela expropriated ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures, as well as the offshore Corocoro development project. In response, ConocoPhillips initiated international arbitration proceedings before the ICSID. In March 2019, an ICSID tribunal unanimously ordered the government of Venezuela to pay ConocoPhillips approximately $8.7 billion (later reduced to $8.5 billion) plus interest for the unlawful expropriation of the projects. On January 22, 2025, an ICSID annulment committee dismissed Venezuela’s application to annul the tribunal’s decision and upheld the $8.5 billion award plus interest in full. Separate arbitrations before the ICC resulted in additional awards against Petróleos de Venezuela, S.A. (PDVSA) and three of its affiliates, including an award for approximately $2 billion plus interest, for the Petrozuata and Hamaca projects, and a $33 million award, for the Corocoro project, plus interest. Cumulatively, as of December 31, 2025, the company has received approximately $794 million in connection with the first ICC award. Collection actions for all three awards are ongoing.

ConocoPhillips has ensured that all actions related to these arbitration awards meet all appropriate U.S. regulatory requirements, including those related to any applicable sanctions imposed by the U.S. against Venezuela.

Beginning in 2017, governmental entities and individuals 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 related impacts. Additional lawsuits with similar allegations are expected to be filed. 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 several of the lawsuits and will vigorously defend against them. 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 while assessing options for early resolution.

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.

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In July 2021, a federal securities class action was filed against Concho Resources Inc. (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. On April 7, 2025, the court certified a class. We believe the allegations in the action are without merit and are vigorously defending this litigation.

ConocoPhillips is involved in a pending dispute with commercial counterparties relating to the propriety of its force majeure notices following Winter Storm Uri in 2021. We believe this claim is without merit and we are vigorously defending the dispute.

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 are primarily related to LNG offtake purchase commitments. The fixed and determinable portion of the remaining estimated payments under these various agreements as of December 31, 2025 is: 2026—$7 million; 2027—$7 million; 2028—$397 million; 2029—$558 million; 2030—$602 million; and 2031 and after—$23 billion. Generally, variable components of these obligations include commodity futures prices and estimated future 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 these agreements were $25 million in 2025, $24 million in 2024 and $26 million in 2023.

Note 10—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
			2025			2024
Assets
Prepaid expenses and other current assets			$	491		394
Other assets			113			94
Liabilities
Other accruals			438			397
Other liabilities and deferred credits			100			83

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

			Millions of Dollars
			2025			2024			2023
Sales and other operating revenues			$	230		133			86
Other income			(8)			(4)			(6)
Purchased commodities			(97)			(133)			(90)

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

			Open Position Long/(Short)
			2025			2024
Commodity
Natural gas and power (BCF equivalent)
Fixed price			(15)			(17)
Basis			(17)			—

Interest Rate Derivative Instruments

In 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. In 2024, PALNG dedesignated a portion of the interest rate swaps as a cash flow hedge and the remaining portion was dedesignated during the first quarter of 2025. Changes in the fair value of the dedesignated hedging instruments are reported in the "Equity in earnings of affiliates" line on our consolidated income statement.

For the years ended December 31, 2025 and 2024, we recognized gains of $18 million and $35 million, respectively, in "Equity in earnings of affiliates" related to these swaps. For the year ended December 31, 2025, unrealized gains/losses recognized in other comprehensive income (loss) related to these swaps was nil. For the years ended December 31, 2024 and 2023, we recognized an unrealized loss of $56 million and an unrealized gain of $78 million, respectively, in other comprehensive income (loss) 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.

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The following investments are carried on our consolidated balance sheet at cost, plus accrued interest and the table reflects remaining maturities at December 31, 2025 and 2024:

			Millions of Dollars
			Carrying Amount
			Cash and cash equivalents						Short-term investments
			2025			2024			2025			2024
Cash			$	543		770
Demand Deposits			3,781			3,211
Time Deposits
1 to 90 days			975			1,364			6			1
91 to 180 days									17			5
Within one year									8			6
U.S. Government Obligations
1 to 90 days			1,198			260			—			—
			$	6,497		5,605			31			12

The following investments in debt securities classified as available for sale are carried at fair value on our consolidated balance sheet at December 31, 2025 and 2024:

			Millions of Dollars
			Carrying Amount
			Cash and cash equivalents						Short-term investments						Investments and long-term receivables
			2025			2024			2025			2024			2025			2024
Major Security Type
Corporate Bonds			$	—		—			308			338			651			612
Commercial Paper			—			2			72			77
U.S. Government Obligations			—			—			46			43			224			218
U.S. Government Agency Obligations									—			—			1			7
Foreign Government Obligations									9			4			9			12
Asset-backed Securities									18			33			263			205
			$	—		2			453			495			1,148			1,054

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 13 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:

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			Millions of Dollars
			Amortized Cost Basis						Fair Value
			2025			2024			2025			2024
Major Security Type
Corporate Bonds			$	953		947			959			950
Commercial Paper			72			79			72			79
U.S. Government Obligations			268			262			270			261
U.S. Government Agency Obligations			1			7			1			7
Foreign Government Obligations			18			16			18			16
Asset-backed Securities			280			237			281			238
			$	1,592		1,548			1,601			1,551

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, 2025 and 2024, proceeds from sales and redemptions of investments in debt securities classified as available for sale were $962 million and $868 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.

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 could be 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 and foreign government obligations.

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 at December 31, 2025 and 2024, was $73 million and $70 million, respectively. For these instruments, no collateral was posted at December 31, 2025 and 2024. If our credit rating had been downgraded below investment grade at December 31, 2025, we would have been required to post $32 million of additional collateral, either with cash or letters of credit.

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Note 11—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 2025 or 2024.

Recurring Fair Value Measurement

Financial assets and liabilities reported at fair value on a recurring basis 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 associated with the 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. The consideration for the acquisition included a contingent consideration arrangement requiring payment of up to $0.4 billion CAD over a five-year term. The contingent payments represent $2 million for every dollar that WCS pricing exceeds $52 per barrel during the month, subject to certain production targets being achieved. The undiscounted amount we could pay under this arrangement was up to $0.3 billion USD at closing.

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, 2025															December 31, 2024
			Level 1			Level 2			Level 3			Total						Level 1			Level 2			Level 3			Total
Assets
Investments in debt securities			$	270		1,331			—			1,601						261			1,290			—			1,551
Commodity derivatives			306			230			68			604						201			252			35			488
Total assets			$	576		1,561			68			2,205						462			1,542			35			2,039
Liabilities
Commodity derivatives			$	354		124			60			538						275			160			45			480
Contingent consideration			—			—			—			—						—			—			145			145
Total liabilities			$	354		124			60			538						275			160			190			625

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For the year ended December 31, 2025, we have made payments of $80 million, and $237 million in total under the contingent consideration arrangement since the date of the Surmont acquisition, included in the "Other" line within the financing activities section of our consolidated statement of cash flows. As of December 31, 2025, the fair value of the contingent consideration liability was zero due to the commodity price outlook over the remaining term. 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)
Contingent Consideration - Surmont as of:
December 31, 2025			$	—		Discounted cash flow			Commodity price outlook* ($/BOE)			$43.17 - $51.97 ($46.47)
December 31, 2024			145			$48.63 - $57.53 ($53.38)

*Commodity price outlook based on a combination of external pricing service companies' outlooks and 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, 2025
Assets			$	604		2			602			361			241			6			235
Liabilities			538			1			537			361			176			53			123
December 31, 2024
Assets			$	488		—			488			278			210			—			210
Liabilities			480			—			480			278			202			73			129

At December 31, 2025 and 2024, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.

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 10.

• 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
			2025			2024						2025			2024
Financial assets
Commodity derivatives			237			210						237			210
Investments in debt securities			1,601			1,551						1,601			1,551
Financial liabilities
Total debt, excluding finance leases			22,643			23,384						22,698			22,997
Commodity derivatives			124			129						124			129

Note 12—Equity

Common Stock

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

			Shares
			2025			2024			2023
Issued
Beginning of year			2,250,672,734			2,103,772,516			2,100,885,134
Acquisition of Marathon Oil			—			142,941,624			—
Distributed under benefit plans			2,845,548			3,958,594			2,887,382
End of year			2,253,518,282			2,250,672,734			2,103,772,516
Held in Treasury
Beginning of year			974,806,010			925,670,961			877,029,062
Repurchase of common stock			53,544,176			49,135,049			48,641,899
End of year			1,028,350,186			974,806,010			925,670,961

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, 2025 or 2024.

Repurchase of Common Stock

In late 2016, we initiated our current share repurchase program. In October 2024, our Board of Directors approved an increase from our prior authorization of $45 billion by a total of the lesser of $20 billion or the number of shares issued in our acquisition of Marathon Oil, such that the company is not to exceed $65 billion in aggregate purchases. Since inception of our current program, shares repurchased totaled 486 million shares at a cost of $39.3 billion through the end of December 2025.

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Note 13—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 8.

For those leasing arrangements where the underlying asset is not yet constructed, the company does not control the asset during construction. 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, “Leases,” 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, except for crude oil and LNG Vessels. 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 Topic 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.

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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
			2025						2024
			Operating Leases			Finance Leases			Operating Leases			Finance Leases
Right-of-Use Assets
Properties, plants and equipment
Gross						2,007						1,983
Accumulated DD&A						(1,507)						(1,336)
Net PP&E*						500						647
Other assets			950						1,017
Lease Liabilities
Short-term debt**						306						292
Other accruals			383						329
Long-term debt***						495						648
Other liabilities and deferred credits			567						695
Total lease liabilities			$	950		801			1,024			940

** Includes proportionately consolidated finance lease assets of $83 million at December 31, 2025 and $107 million at December 31, 2024.*

*** Includes proportionately consolidated finance lease liabilities of $188 million at December 31, 2025 and $181 million at December 31, 2024.*

**** Includes proportionately consolidated finance lease liabilities of $192 million at December 31, 2025 and $259 million at December 31, 2024.*

The following table summarizes our lease costs:

			Millions of Dollars
			2025			2024			2023
Lease Cost*
Operating lease cost			$	447		325			229
Finance lease cost
Amortization of right-of-use assets			171			173			180
Interest on lease liabilities			24			29			35
Short-term lease cost**			65			49			40
Total lease cost***			$	707		576			484

** 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:

Lease Term and Discount Rate			2025			2024
Weighted-average term (years)
Operating leases			4.06			4.41
Finance leases			4.18			4.86
Weighted-average discount rate (percent)
Operating leases			4.58			4.62
Finance leases			3.47			3.40

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The following table summarizes other lease information:

			Millions of Dollars
			2025			2024			2023
Other Information*
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases			$	385		248			173
Operating cash flows from finance leases			24			29			33
Financing cash flows from finance leases			175			172			169
Right-of-use assets obtained in exchange for operating lease liabilities			$	320		628			355
Right-of-use assets obtained in exchange for finance lease liabilities			25			—			9

*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, 2025:

			Millions of Dollars
			Operating Leases			Finance Leases
Maturity of Lease Liabilities
2026			$	417		363
2027			219			164
2028			143			181
2029			102			91
2030			55			57
Remaining years			109			48
Total			1,045			904
Less: portion representing imputed interest			(95)			(103)
Total lease liabilities			$	950		801

As of December 31, 2025 and December 31, 2024, the company had approximately $1 billion and nil in future undiscounted cash flows for leases not yet commenced related to time-chartered LNG vessels in support of future LNG offtake, respectively.

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Note 14—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
			2025									2024									2025			2024
			U.S.			Int’l.						U.S.			Int’l.
Change in Benefit Obligation
Benefit obligation at January 1			$	1,806		2,591						1,525			2,866						145			107
Service cost			58			34						49			38						2			1
Interest cost			93			130						76			114						8			5
Plan participant contributions			—			—						—			—						14			12
Plan amendments			—			—						—			57						(2)			—
Business combinations												237												42
Actuarial (gain) loss			89			(59)						(4)			(202)						(3)			5
Benefits paid			(204)			(142)						(98)			(134)						(39)			(27)
Curtailment			3			(8)						8			—						1			—
Recognition of termination benefits			—			—						13			—						—			—
Foreign currency exchange rate change			—			243						—			(148)						—			—
Benefit obligation at December 31*			$	1,845		2,789						1,806			2,591						126			145
*Accumulated benefit obligation portion of above at December 31:			$	1,767		2,577						1,703			2,392
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1			$	1,556		2,907						1,306			3,085						—			—
Actual return on plan assets			166			192						66			18						—			—
Company contributions			148			50						83			88						25			15
Plan participant contributions			—			—						—			—						14			12
Business combinations												199
Benefits paid			(204)			(142)						(98)			(134)						(39)			(27)
Foreign currency exchange rate change			—			277						—			(150)						—			—
Fair value of plan assets at December 31			$	1,666		3,284						1,556			2,907						—			—
Funded Status			$	(179)		495						(250)			316						(126)			(145)

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			Millions of Dollars
			Pension Benefits																		Other Benefits
			2025									2024									2025			2024
			U.S.			Int’l.						U.S.			Int’l.
Amounts Recognized in the Consolidated Balance Sheet at December 31
Noncurrent assets			$	29		744						1			553						—			—
Current liabilities			(81)			(10)						(28)			(10)						(24)			(26)
Noncurrent liabilities			(127)			(239)						(223)			(227)						(102)			(119)
Total recognized			$	(179)		495						(250)			316						(126)			(145)
Weighted-Average Assumptions Used to Determine Benefit Obligations at December 31
Discount rate			5.25		%	4.95						5.70			4.90						5.60			5.60
Rate of compensation increase			4.50			4.05						5.00			4.05
Interest crediting rate for applicable benefits			4.75									4.30
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31
Discount rate			5.70		%	4.90						5.35			4.10						4.25			5.35
Expected return on plan assets			5.30			6.20						5.30			5.40
Rate of compensation increase			5.00			4.10						5.00			3.65
Interest crediting rate for applicable benefits			4.35									4.20

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 2025, the actuarial losses related to the benefit obligations for U.S. plans were primarily related to a decrease in the discount rate and an increase in compensation and benefits. In addition, international plans recognized actuarial gains due to higher discount rates and lower inflation rate assumptions. During 2024, the actuarial gains related to the benefit obligations for international plans were primarily related to an increase in the discount rates.

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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
			2025									2024
			U.S.			Int’l.						U.S.			Int’l.
Pension Plans with Projected Benefit Obligation in Excess of Plan Assets
Projected benefit obligation			$	208		258						450			242
Fair value of plan assets			—			9						199			6
Pension Plans with Accumulated Benefit Obligation in Excess of Plan Assets
Accumulated benefit obligation			$	190		223						425			210
Fair value of plan assets			—			9						199			6

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
			2025									2024									2025			2024
			U.S.			Int’l.						U.S.			Int’l.
Unrecognized net actuarial loss (gain)			$	92		364						112			445						—			2
Unrecognized prior service cost (credit)			—			61						—			58						1			(21)

			Millions of Dollars
			Pension Benefits																		Other Benefits
			2025									2024									2025			2024
			U.S.			Int’l.						U.S.			Int’l.
Sources of Change in Other Comprehensive Income (Loss)
Net gain (loss) arising during the period			$	5		34						3			83						3			(5)
Amortization of actuarial (gain) loss included in income (loss)*			15			47						8			57						(1)			—
Net change during the period			$	20		81						11			140						2			(5)
Prior service credit (cost) arising during the period			$	—		2						—			(57)						2			—
Amortization of prior service cost (credit) included in income (loss)			—			3						—			—						(24)			(38)
Net change during the period			$	—		5						—			(57)						(22)			(38)

*Includes settlement (gains) losses recognized in 2025 and 2024.

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

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			Millions of Dollars
			Pension Benefits																											Other Benefits
			2025									2024									2023									2025			2024			2023
			U.S.			Int’l.						U.S.			Int’l.						U.S.			Int’l.
Components of Net Periodic Benefit Cost
Service cost			$	58		34						49			38						51			38						2			1			1
Interest cost			93			130						76			114						77			113						8			5			5
Expected return on plan assets			(77)			(189)						(66)			(163)						(58)			(148)						—			—			—
Amortization of prior service credit			—			3						—			—						—			—						(24)			(38)			(38)
Recognized net actuarial loss (gain)			10			47						8			58						12			67						—			—			(3)
Settlements loss (gain)			5			—						—			(1)						6			—						—			—			—
Curtailment loss (gain)			8			(3)						8			—						—			—						1			—			—
Net periodic benefit cost			$	97		22						75			46						88			70						(13)			(32)			(35)

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.

We recognized a pension settlement loss of $5 million in 2025, a gain of $1 million in 2024, and a loss of $6 million in 2023 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 gains or 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 6.50 percent in 2026 that declines to 5 percent by 2032. The measurement of the U.S. post-65 retiree medical accumulated postretirement benefit obligation assumes a health care cost trend rate of 4.7 percent in 2026 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 28 percent in equity securities, 68 percent in debt securities and 4 percent in 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, 2025 and 2024.

• 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

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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.

• 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, 2025, the participating interest in the annuity contract was valued at $40 million and consisted of $107 million in debt securities, less $67 million for the accumulated benefit obligation covered by the contract. At December 31, 2024, the participating interest in the annuity contract was valued at $42 million and consisted of $113 million in debt securities, less $71 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.

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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
2025
Equity securities
International			1			—			—			1						1			—			—			1
Mutual funds			20			—			—			20						514			103			—			617
Debt securities
Corporate			—			—			1			1						—			—			—			—
Mutual funds			—			—			—			—						572			—			—			572
Private equity funds									2			2
Cash and cash equivalents			1			—			—			1						18			—			—			18
Insurance contracts									4			4
Real estate			—			—			2			2						—			—			169			169
Total in fair value hierarchy			$	22		—			9			31						1,105			103			169			1,377
Investments measured at net asset value*
Equity securities
Common/collective trusts												353															325
Debt securities
Common/collective trusts												1,213															1,579
Cash and cash equivalents												9															—
Real estate												21															—
Total**			$	22		—			9			1,627						1,105			103			169			3,281

*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 $40 million and net receivables related to security transactions of $2 million.

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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
2024
Equity securities
U.S.			$	5		—			—			5						—			—			—			—
International			38			—			—			38						—			—			—			—
Mutual funds			17			—			—			17						445			77			—			522
Debt securities
Corporate			—			1			—			1						—			—			—			—
Mutual funds			—			—			—			—						451			—			—			451
Private equity funds									3			3
Cash and cash equivalents			—			—			—			—						25			—			—			25
Insurance contracts									4			4
Real estate			—			—			3			3						—			—			136			136
Total in fair value hierarchy			$	60		1			10			71						921			77			136			1,134
Investments measured at net asset value*
Equity securities
Common/collective trusts												479															194
Debt securities
Common/collective trusts												938															1,575
Cash and cash equivalents												3															—
Real estate												22															—
Total**			$	60		1			10			1,513						921			77			136			2,903

*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 $42 million and net receivables related to security transactions of $5 million.

Level 3 activity was not material for all periods presented.

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 2026, we expect to contribute approximately $160 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $60 million to our international qualified and nonqualified pension and postretirement benefit plans.

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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.
2026			$	511		135						17
2027			279			139						17
2028			164			142						16
2029			161			146						14
2030			151			151						13
2031–2035			628			799						52

Restructuring Costs

During 2025, we announced certain restructuring initiatives and reduced our overall employee workforce, resulting in associated severance expense of $286 million, with $214 million reported as “Production and operating expenses” and $72 million reported as “Selling, general and administrative expenses” on the consolidated income statement. Approximately $43 million was in Alaska, $87 million in Lower 48, $29 million in Canada, $48 million in Europe, Middle East and North Africa, $7 million in Asia Pacific and $72 million in Corporate and Other.

In 2024, accruals included severance costs associated with contractual termination benefits applicable to officers and employees of Marathon Oil as of the acquisition date. See Note 3.

The following table summarizes our severance accrual activity:

			Millions of Dollars
			2025			2024			2023
Balance at January 1			$	331		12			31
Accruals*			365			328			1
Benefit payments			(320)			(9)			(20)
Foreign currency translation adjustment			2			—			—
Balance at December 31****			$	378		331			12

*Partner recoveries of $73 million are accrued as receivables as of December 31, 2025. The expenses in our consolidated income statement are presented net of this amount.

**Of the remaining balance at December 31, 2025, $300 million is classified as short-term.

Defined Contribution Plans

Most U.S. employees are eligible to participate in a defined contribution plan. Company contributions can vary based on employee compensation and contribution elections, whether the employee is accruing benefits in a defined benefit plan and company discretion. Company contributions charged to expense for U.S. defined contribution plans were $160 million in 2025, $152 million in 2024 and $151 million in 2023.

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 $27 million in 2025, $25 million in 2024 and $23 million in 2023.

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

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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, RSUs and performance share units (PSU) to employees and non-employee directors who contribute to the company’s continued success and profitability.

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 date when an employee first becomes eligible for retirement vesting under award terms. Other than certain retention awards, our share-based compensation programs generally provide accelerated vesting in whole or in part (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
			2025			2024			2023
Compensation cost			$	336		268			334
Tax benefit			79			67			84

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 on the first, second and third anniversaries of 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.

The following summarizes our stock option activity for the year ended December 31, 2025:

															Millions of Dollars
			Options						Weighted-Average Exercise Price						Aggregate Intrinsic Value
Outstanding at December 31, 2024			2,051,075						$	43.16					$	113
Exercised			(1,086,350)						38.71						60
Outstanding at December 31, 2025			964,725						$	48.17					$	44
Vested at December 31, 2025			964,725						$	48.17					$	44
Exercisable at December 31, 2025			964,725						$	48.17					$	44

The weighted-average remaining contractual term of outstanding options, vested options and exercisable options at December 31, 2025, were all 1.03 years. The aggregate intrinsic value of options exercised was $63 million in 2024 and $58 million in 2023.

During 2025, we received $15 million in cash and $27 million in cashless exercises and realized a tax benefit of $13 million from the exercise of options. At December 31, 2025, all outstanding stock options were fully vested with no remaining compensation cost to be recorded.

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Stock Unit Programs—RSUs 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 on the first, second and third anniversaries of the grant date. RSUs are also granted ad hoc to attract or retain key personnel, or assumed as a result of an acquisition, and the terms and conditions under which these RSUs vest vary by award.

Stock-Settled

Upon vesting, these RSUs 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 may vest earlier; however, those units are not settled through the issuance of common stock until after 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 RSU activity for the year ended December 31, 2025:

			Stock Units						Weighted-Average Grant Date Fair Value						Millions of Dollars
									Total Fair Value
Outstanding at December 31, 2024			6,471,773						$	104.89
Granted			2,998,555						99.26
Forfeited			(274,989)						103.37
Issued			(2,938,338)						98.14						$	285
Outstanding at December 31, 2025			6,257,001						$	105.43
Not Vested at December 31, 2025			4,300,663						$	105.25

At December 31, 2025, the remaining unrecognized compensation cost from the unvested stock-settled RSUs was $188 million, which will be recognized over a weighted-average period of 1.71 years, the longest period being 3.42 years. The weighted-average grant date fair value of stock-settled RSUs granted during 2024 and 2023 was $109.79 and $110.91, respectively. The total fair value of stock-settled RSUs issued during 2024 and 2023 was $410 million and $284 million, respectively.

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Performance Share Program—Under the Omnibus Plan, we also annually grant restricted 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.

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 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 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, 2025:

									Weighted-Average Grant Date Fair Value						Millions of Dollars
			Stock Units									Total Fair Value
Outstanding at December 31, 2024			774,503						$	50.75
Granted			4,737						100.90
Issued			(193,286)						52.05						$	18
Outstanding at December 31, 2025			585,954						$	50.73

At December 31, 2025, 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 2024 and 2023 was $110.39 and $112.50, respectively. The total fair value of stock-settled PSUs issued during 2024 and 2023 was $23 million and $29 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 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

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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.

The following summarizes our cash-settled Performance Share Program activity for the year ended December 31, 2025:

									Weighted-Average Grant Date Fair Value						Millions of Dollars
			Stock Units									Total Fair Value
Outstanding at December 31, 2024			89,583						$	98.20
Granted			647,382						100.90
Settled			(659,340)						100.14						$	66
Outstanding at December 31, 2025			77,625						$	94.00

At December 31, 2025, all outstanding cash-settled performance awards were fully vested with no remaining compensation cost to be recorded. The weighted-average grant date fair value of cash-settled PSUs granted during 2024 and 2023 was $110.39 and $112.50, respectively. The total fair value of cash-settled performance share awards settled during 2024 and 2023 was $171 million and $111 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 RSUs 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 assumed 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, 2025:

									Weighted-Average Grant Date Fair Value						Millions of Dollars
			Stock Units									Total Fair Value
Outstanding at December 31, 2024			629,681						$	60.22
Granted			43,292						98.68
Issued			(110,284)						52.23						$	12
Outstanding at December 31, 2025			562,689						$	64.75

At December 31, 2025, all outstanding restricted stock and RSUs were fully vested with no remaining compensation cost to be recorded. The weighted-average grant date fair value of awards granted during 2024 and 2023 was $111.91 and $115.88, respectively. The total fair value of awards issued during 2024 and 2023 was $35 million and $46 million, respectively.

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Note 15—Income Taxes

Components of income tax provision (benefit) were:

			Millions of Dollars
			2025						2024						2023
Income Taxes
Federal
Current			$	655					629						1,054
Deferred			537						247						825
Foreign
Current			3,287						3,249						2,931
Deferred			33						71						254
State and local
Current			177						182						202
Deferred			(21)						49						65
Total tax provision (benefit)			$	4,668					4,427						5,331

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
			2025			2024
Deferred Tax Liabilities
PP&E and intangibles			$	16,244		15,609
Inventory			15			91
Other			160			155
Total deferred tax liabilities			16,419			15,855
Deferred Tax Assets
Benefit plan accruals			330			432
Asset retirement obligations and accrued environmental costs			2,985			2,799
Investments in joint ventures			2,356			2,269
Other financial accruals and deferrals			507			497
Loss and credit carryforwards			4,048			4,910
Other			103			187
Total deferred tax assets			10,329			11,094
Less: valuation allowance			(5,926)			(6,435)
Total deferred tax assets net of valuation allowance			4,403			4,659
Net deferred tax liabilities			$	12,016		11,196

At December 31, 2025, noncurrent assets and liabilities included deferred taxes of $221 million and $12,237 million, respectively. At December 31, 2024, noncurrent assets and liabilities included deferred taxes of $230 million and $11,426 million, respectively.

At December 31, 2025, the loss and credit carryforward deferred tax assets were primarily related to U.S. foreign tax credit carryforwards of $2.9 billion and various jurisdictions net operating loss and credit carryforwards of $1.1 billion.

At December 31, 2024, the loss and credit carryforward deferred tax assets were primarily related to U.S. foreign tax credit carryforwards of $3.3 billion and various jurisdictions net operating loss and credit carryforwards of $1.6 billion. In 2024, $1.2 billion of U.S. foreign tax credits expired. This reduction was partly offset by an increase of $700 million in our U.S. net operating loss, foreign tax credit carryforwards, and other credit carryforwards due to our acquisition of Marathon Oil. See Note 3.

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The following table shows a reconciliation of the beginning and ending deferred tax asset valuation allowance for 2025, 2024 and 2023:

			Millions of Dollars
			2025			2024			2023
Balance at January 1			$	6,435		7,656			8,049
Charged to expense (benefit)			(59)			(409)			(2)
Other*			(450)			(812)			(391)
Balance at December 31			$	5,926		6,435			7,656

*Represents changes due to 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, 2025, 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 2025, the valuation allowance movement charged to earnings primarily relates to the utilization of previously unrecognized capital loss carryforwards due to our agreement to the sale of our interest in the Ursa and Europa Fields, and the Ursa Pipeline Company LLC. During 2024, the valuation allowance movement charged to earnings primarily relates to the ability to utilize a portion of ConocoPhillips foreign tax credit carryforwards due to the acquisition of Marathon Oil. 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. See Note 3.

As a result of the acquisition of Marathon Oil, we utilized foreign tax credits previously offset by a valuation allowance. During the fourth quarter of 2024, a tax benefit of $394 million was recorded as a result of the acquisition and the subsequent utilization of the foreign tax credits. See Note 3.

At December 31, 2025, we had unremitted income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures. 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 $314 million.

The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2025, 2024 and 2023:

			Millions of Dollars
			2025			2024			2023
Balance at January 1			$	377		387			710
Additions based on tax positions related to the current year			—			3			5
Additions for tax positions of prior years			13			127			1
Reductions for tax positions of prior years			—			—			(9)
Settlements			(3)			(121)			(96)
Lapse of statute			(13)			(19)			(224)
Balance at December 31			$	374		377			387

Included in the balance of unrecognized tax benefits for 2025, 2024 and 2023 were $365 million, $368 million and $378 million, respectively, which, if recognized, would impact our effective tax rate.

The balance of the unrecognized tax benefits decreased in 2025 due to the lapsing of the statute of limitations on certain of our foreign subsidiaries, partially offset by additions on tax positions related to prior years on certain of our foreign subsidiaries.

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The balance of the unrecognized tax benefits decreased in 2024 due to the resolution of certain items with U.S. and Norwegian taxing authorities. The balance of our unrecognized tax benefits increased in 2024 primarily due to U.S. tax credits acquired through our acquisition of Marathon Oil. See Note 3.

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.

At December 31, 2025, 2024 and 2023, accrued liabilities for interest and penalties totaled $47 million, $26 million and $45 million, respectively, net of accrued income taxes. Interest and penalties resulted in a reduction to earnings of $21 million in 2025, an increase to earnings of $19 million in 2024 and a reduction to earnings of $10 million in 2023.

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 (2018), Norway (2024) and U.S. (2021). 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.

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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, under newly adopted ASU 2023-09 "Improvements to Income Tax Disclosures", which we adopted for the year ended 2025 on a retrospective basis were:

			Millions of Dollars												Percent of Pre-Tax Income (Loss)
			2025			2024			2023						2025			2024			2023
Income (loss) before income taxes
United States			$	6,176		6,731			9,472						48.8		%	49.2			58.2
Foreign			6,480			6,941			6,816						51.2			50.8			41.8
			$	12,656		13,672			16,288						100.0		%	100.0			100.0
U.S. federal statutory tax rate			$	2,658		2,871			3,421						21.0		%	21.0			21.0
State income taxes, net of federal Income tax effect*			127			187			214						1.0			1.4			1.3
Foreign tax effects
Norway
Statutory tax rate difference between Norway and U.S.			1,020			1,205			1,298						8.1			8.8			8.0
Other			(48)			(97)			(96)						(0.4)			(0.7)			(0.5)
Libya															—			—			—
Additional foreign income tax			1,087			1,027			1,072						8.6			7.5			6.6
Other			(25)			(17)			(11)						(0.2)			(0.1)			(0.1)
Australia															—			—			—
Equity in earnings, net of tax			(160)			(230)			(242)						(1.3)			(1.7)			(1.5)
Other			(6)			(3)			(12)						—			—			(0.1)
Other foreign jurisdictions			102			(126)			51						0.8			(0.9)			0.3
Effect of cross-border tax laws			44			59			21						0.4			0.4			0.1
Tax Credits			(21)			—			—						(0.2)			—			—
Valuation allowances			(60)			(409)			(25)						(0.5)			(3.0)			(0.2)
Nontaxable or nondeductible items			(24)			18			(44)						(0.2)			0.1			(0.3)
Changes in unrecognized tax benefits			(11)			(54)			(312)						(0.1)			(0.4)			(1.9)
Other Adjustments			(15)			(4)			(4)						(0.1)			—			—
Total			$	4,668		4,427			5,331						36.9		%	32.4			32.7

*For 2025, state taxes in Alaska contributed to the majority (greater than 50 percent) of the tax effect in this category. For 2024, state taxes in Alaska contributed to the majority (greater than 50 percent) of the tax effect in this category. For 2023, state taxes in Alaska and California contributed to the majority (greater than 50 percent) of the tax effect in this category.

Our effective tax rate for 2025 was driven by our jurisdictional tax rates for this profit mix with a favorable impact from the utilization of previously unrecognized capital loss carryforwards.

Our effective tax rate for 2024 was driven by our jurisdictional tax rates for this profit mix with a favorable impact from the acquisition of Marathon Oil, enabling the utilization of foreign tax credits previously offset by a valuation allowance. See Note 3.

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.

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Note 16—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, 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)
Other comprehensive income (loss)			3			1			(760)			(44)			(800)
December 31, 2024			(390)			3			(6,104)			18			(6,473)
Other comprehensive income (loss)			55			5			502			—			562
December 31, 2025			$	(335)		8			(5,602)			18			(5,911)

Note 17—Cash Flow Information

			Millions of Dollars
			2025			2024			2023
Noncash Investing and Financing Activities
Increase (decrease) in PP&E related to an increase (decrease) in asset retirement obligations, excluding acquisitions			$	12		268			727
Fair value of contingent consideration on acquisition			—			—			320
Cash Payments
Interest			757			806			701
Income Taxes
Federal taxes			1,077			296			757
Foreign taxes
Norway			1,758			1,580			2,758
Libya			1,461			1,280			1,317
Other foreign			374			304			349
State taxes			152			161			225
Total income taxes			$	4,822		3,621			5,406
Net Sales (Purchases) of Investments
Short-term investments purchased			$	(1,249)		(2,606)			(1,463)
Short-term investments sold			1,751			3,567			3,574
Long-term Investments purchased			(861)			(747)			(867)
Long-term Investments sold			304			201			129
Total sales (purchases) of investments			$	(55)		415			1,373

The following items are included in the "Cash flows from operating activities" section of our consolidated cash flows.

In 2025, we made a total of $116 million in contributions to our U.S. qualified pension plan.

For additional information on cash and non-cash changes to our consolidated balance sheet, see Note 3 and Note 11 for our acquisition of Marathon Oil and acquisition of the remaining working interest in Surmont.

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Note 18—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
			2025			2024			2023
Revenue from contracts with customers			$	51,824		49,418			48,522
Revenue from contracts outside the scope of ASC Topic 606
Physical contracts meeting the definition of a derivative			7,201			5,483			8,203
Financial derivative contracts			(81)			(156)			(584)
Consolidated sales and other operating revenues			$	58,944		54,745			56,141

Revenues from contracts outside the scope of ASC Topic 606, “Revenue from Contracts with Customers,” 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. Further disaggregation of revenues is provided in Note 22 - Segment Disclosures and Related Information.

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 as of the end of the reporting period.

Receivables from Contracts with Customers

At December 31, 2025, the “Accounts and notes receivable” line on our consolidated balance sheet included trade receivables of $4,416 million compared with $5,398 million at December 31, 2024, 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 natural 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 natural gas sold under contracts for which NPNS has not been elected compared with trade receivables where NPNS has been elected.

Note 19—Related Party Transactions

The following tables summarize the related party balances and activities which are primarily with equity affiliates:

			Millions of Dollars
			December 31 2025			December 31 2024
Balance Sheet
Accounts and notes receivable			$	79		74
Accounts payable			64			57

			Millions of Dollars
			2025			2024			2023
Income Statement
Operating revenues and other income			$	73		88			90
Purchased commodities			1			—			—
Operating expenses and selling, general and administrative expenses			286			246			282

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Note 20—Other Financial Information

			Millions of Dollars
			2025			2024			2023
Interest and Debt Expense
Incurred
Debt			$	1,176		941			824
Other			63			90			109
			1,239			1,031			933
Capitalized			(384)			(248)			(153)
Expensed			$	855		783			780
Other Income
Interest income			$	311		402			412
Other, net			227			50			73
Total			$	538		452			485
**Research and Development Expenditures—**expensed			$	78		81			81
Shipping and Handling Costs			$	2,438		1,958			1,695
**Foreign Currency Transaction (Gains) Losses—**after-tax
Alaska			$	—		—			—
Lower 48			—			—			—
Canada			20			(35)			11
Europe, Middle East and North Africa			30			(37)			(39)
Asia Pacific			(33)			(1)			12
Segments Total			17			(73)			(16)
Corporate and Other			(17)			36			86
Total			$	—		(37)			70

			Millions of Dollars
			2025			2024
Properties, Plants and Equipment
Proved properties			$	167,969		155,364
Unproved properties			10,822			15,490
Other			4,844			4,574
Gross properties, plants and equipment			183,635			175,428
Less: Accumulated depreciation, depletion and amortization			(90,396)			(81,072)
Net properties, plants and equipment			$	93,239		94,356

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Note 21—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, 2025, 2024, and 2023. 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			2025			2024			2023
Basic earnings per share
Net income (loss)			$	7,988		9,245			10,957
Less: Dividends and undistributed earnings
allocated to participating securities			27			27			35
Net income (loss) available to common shareholders			$	7,961		9,218			10,922
Weighted-average common shares outstanding (in millions)			1,252			1,179			1,203
Net income (loss) per share of common stock			$	6.36		7.82			9.08
Diluted earnings per share
Net income (loss) available to common shareholders			$	7,961		9,218			10,922
Weighted-average common shares outstanding (in millions)			1,252			1,179			1,203
Add: Dilutive impact of options and unvested
non-participating RSU/PSUs			1			2			3
Weighted-average diluted shares outstanding (in millions)			1,253			1,181			1,206
Net income (loss) per share of common stock			$	6.35		7.81			9.06

Note 22—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 five operating segments, which are primarily defined by geographic region: Alaska; Lower 48 (L48); Canada; Europe, Middle East and North Africa (EMENA); and Asia Pacific (AP).

Corporate and Other (Corporate) 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.

Effective in the fourth quarter of 2025, we determined that our former Other International operating segment, which consisted of activities associated with prior operations in other countries, was no longer an operating segment. Residual results are aggregated into Corporate. Our historical operating segment reporting has been recast to reflect this change.

Our chief operating decision maker (CODM) is our Chairman of the Board of Directors and Chief Executive Officer, who evaluates performance and allocates resources among our operating segments based on each segment's net income (loss). This is done through the annual budget and forecasting process.

Segment accounting policies are the same as those in Note 1. Intersegment sales are at prices that approximate market. The significant segment expense categories and amounts in the tables below align with segment-level information that is regularly provided to the CODM.

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2025 Segment level net income (loss)

Year Ended December 31, 2025			Millions of Dollars
			Alaska			L48			Canada			EMENA			AP			Segments Total			Corporate			Consolidated Total
Segment sales and other operating revenues
Sales and other operating revenues			$	5,638		41,404			5,600			6,485			1,770			60,897			63			60,960
Intersegment eliminations			—			(9)			(1,975)			(1)			—			(1,985)			(31)			(2,016)
Consolidated sales and other operating revenues#*			5,638			41,395			3,625			6,484			1,770			58,912			32			58,944
Significant segment expenses
Production and operating expenses			2,158			5,856			833			962			367			10,176			155			10,331
DD&A			1,399			8,121			556			912			460			11,448			52			11,500
Income tax provision (benefit)			271			1,380			236			2,820			238			4,945			(277)			4,668
Total			3,828			15,357			1,625			4,694			1,065			26,569			(70)			26,499
Other segment items
Equity in earnings of affiliates			(1)			(11)			—			(558)			(762)			(1,332)			(3)			(1,335)
Interest income			—			—			—			—			(8)			(8)			(303)			(311)
Interest and debt expense			—			—			—			—			—			—			855			855
Other**			1,081			20,785			1,259			1,124			308			24,557			691			25,248
Total			1,080			20,774			1,259			566			(462)			23,217			1,240			24,457
Net income (loss)			$	730		5,264			741			1,224			1,167			9,126			(1,138)			7,988
*#*Includes revenue from physical contracts meeting the definition of a derivative that are outside the scope of ASC Topic 606 for the L48, Canada and EMENA segments of $5.7 billion, $0.7 billion and $0.8 billion, respectively.
*In 2025, sales by our L48 segment to a certain pipeline company accounted for approximately $5.3 billion or approximately 10 percent of our total consolidated sales and other operating revenues.
**Other segment items not required to be separately disclosed for each reportable segment include:
Gain (loss) on disposition: L48, EMENA and Corporate
Other income: L48, Canada, EMENA, AP and Corporate
Purchased commodities: Alaska, L48, Canada, EMENA and AP
Selling, general and administrative expenses, Exploration expenses, Taxes other than income taxes and Accretion on discounted liabilities: Alaska, L48, Canada, EMENA, AP and Corporate
Impairments: Alaska, L48 and Canada
Foreign currency transaction (gain) loss: Canada, EMENA, AP and Corporate
Other expenses: Alaska, L48, Canada, EMENA and Corporate

Other segment disclosures

Year Ended December 31, 2025			Millions of Dollars
			Alaska			L48			Canada			EMENA			AP			Segments Total			Corporate			Consolidated Total
Equity investments			$	3		—			—			2,268			4,926			7,197			1,636			8,833
Total assets			20,224			61,933			9,978			10,554			8,273			110,962			10,977			121,939
Capital expenditures and investments			3,607			6,702			593			1,194			342			12,438			115			12,553

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2024 Segment level net income (loss)

Year Ended December 31, 2024			Millions of Dollars
			Alaska			L48			Canada			EMENA			AP			Segments Total			Corporate			Consolidated Total
Segment sales and other operating revenues
Sales and other operating revenues			$	6,553		37,028			5,636			5,788			1,847			56,852			54			56,906
Intersegment eliminations			—			(2)			(2,122)			—			—			(2,124)			(37)			(2,161)
Consolidated sales and other operating revenues#*			6,553			37,026			3,514			5,788			1,847			54,728			17			54,745
Significant segment expenses
Production and operating expenses			1,951			4,751			902			671			384			8,659			92			8,751
DD&A			1,299			6,442			639			761			425			9,566			33			9,599
Income tax provision (benefit)			480			1,462			228			2,854			211			5,235			(808)			4,427
Total			3,730			12,655			1,769			4,286			1,020			23,460			(683)			22,777
Other segment items
Equity in earnings of affiliates			1			(5)			—			(586)			(1,089)			(1,679)			(26)			(1,705)
Interest income			—			—			—			—			(8)			(8)			(394)			(402)
Interest and debt expense			—			—			—			—			—			—			783			783
Other**			1,496			19,201			1,033			899			200			22,829			1,218			24,047
Total			1,497			19,196			1,033			313			(897)			21,142			1,581			22,723
Net income (loss)			$	1,326		5,175			712			1,189			1,724			10,126			(881)			9,245
*#*Includes revenue from physical contracts meeting the definition of a derivative that are outside the scope of ASC Topic 606 for the L48, Canada and EMENA segments of $4.2 billion, $0.5 billion and $0.8 billion, respectively.
*In 2024, sales by our L48 segment to a certain pipeline company accounted for approximately $6.7 billion or approximately 12 percent of our total consolidated sales and other operating revenues.
**Other segment items not required to be separately disclosed for each reportable segment include:
Gain (loss) on dispositions: L48, Canada, EMENA and Corporate
Other income; Selling, general and administrative expenses; Exploration expenses; Taxes other than income taxes; and Accretion on discounted liabilities: Alaska, L48, Canada, EMENA, AP and Corporate
Purchased Commodities and Impairments: Alaska, L48, Canada and EMENA
Foreign currency transaction (gain) loss: Canada, EMENA and Corporate
Other expenses: Alaska, L48, EMENA and Corporate

Other segment disclosures

Year Ended December 31, 2024			Millions of Dollars
			Alaska			L48			Canada			EMENA			AP			Segments Total			Corporate			Consolidated Total
Equity investments			$	3		123			—			1,948			4,977			7,051			1,559			8,610
Total assets			18,030			66,977			9,513			9,770			8,390			112,680			10,100			122,780
Capital expenditures and investments			3,194			6,510			551			1,021			370			11,646			472			12,118

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2023 Segment level net income (loss)

Year Ended December 31, 2023			Millions of Dollars
			Alaska			L48			Canada			EMENA			AP			Segment Totals			Corporate			Consolidated Total
Segment sales and other operating revenues
Sales and other operating revenues			$	7,098		38,244			4,873			5,854			1,913			57,982			63			58,045
Intersegment eliminations			—			(7)			(1,867)			—			—			(1,874)			(30)			(1,904)
Consolidated sales and other operating revenues#*			7,098			38,237			3,006			5,854			1,913			56,108			33			56,141
Significant segment expenses
Production and operating expenses			1,829			4,199			619			593			391			7,631			62			7,693
DD&A			1,061			5,722			420			587			455			8,245			25			8,270
Income tax provision (benefit)			642			1,763			26			3,065			42			5,538			(207)			5,331
Total			3,532			11,684			1,065			4,245			888			21,414			(120)			21,294
Other segment items
Equity in earnings of affiliates			(1)			9			—			(580)			(1,151)			(1,723)			3			(1,720)
Interest income			—			—			—			(1)			(8)			(9)			(403)			(412)
Interest and debt expense			—			—			—			—			—			—			780			780
Other**			1,789			20,083			1,539			1,001			223			24,635			607			25,242
Total			1,788			20,092			1,539			420			(936)			22,903			987			23,890
Net income (loss)			$	1,778		6,461			402			1,189			1,961			11,791			(834)			10,957
*#*Includes revenue from physical contracts meeting the definition of a derivative that are outside the scope of ASC Topic 606 for the L48, Canada and EMENA segments of $6.6 billion, $1.3 billion and $0.3 billion, respectively.
*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.
**Other segment items not required to be separately disclosed for each reportable segment include:
Gain (loss) on dispositions: Alaska, L48, AP and Corporate
Other income; Selling, general and administrative expenses; Exploration expenses; Taxes other than income taxes; and Accretion on discounted liabilities: Alaska, L48, Canada, EMENA, AP and Corporate
Purchased commodities: Alaska, L48, Canada, EMENA and AP
Impairments: L48, Canada and Corporate
Foreign currency transaction (gain) loss: Canada, EMENA, AP and Corporate
Other expenses: Alaska, L48, EMENA and Corporate

Other segment disclosures

Year Ended December 31, 2023			Millions of Dollars
			Alaska			L48			Canada			EMENA			AP			Segment Totals			Corporate			Consolidated Total
Equity investments			$	32		118			—			1,191			5,419			6,760			1,145			7,905
Total assets			16,174			42,415			10,277			8,396			8,903			86,165			9,759			95,924
Capital expenditures and investments			1,705			6,487			456			1,111			354			10,113			1,135			11,248

ConocoPhillips 2025 10-K			128

Notes to Consolidated Financial Statements			Table of Contents

Sales and Other Operating Revenues by Product
Consolidated sales and other operating revenues
			Millions of Dollars
			2025			2024			2023
Crude oil			$	39,068		39,010			37,833
Natural gas			8,854			6,444			10,725
Natural gas liquids			3,705			2,889			2,609
Other*			7,317			6,402			4,974
Total			$	58,944		54,745			56,141

*Includes bitumen, power and LNG.

Revenue from physical contracts meeting the definition of a derivative outside the scope of ASC Topic 606
			Millions of Dollars
			2025			2024			2023
Crude oil			$	494		376			143
Natural gas			5,465			3,753			6,622
Power			1,242			1,354			1,438
Total			$	7,201		5,483			8,203

Geographic Information

			Millions of Dollars
			Sales and Other Operating Revenues*												Long-Lived Assets**
			2025			2024			2023						2025			2024			2023
U.S.			$	46,611		43,480			45,101						77,453			79,141			53,955
International			12,333			11,265			11,040						24,619			23,825			23,994
Worldwide consolidated			$	58,944		54,745			56,141						102,072			102,966			77,949

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

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

Note 23—New Accounting Standards

In November 2024, the FASB issued ASU No. 2024-03, “Disaggregation of Income Statement Expenses” to improve the disclosures about a public business entity’s expenses (including purchases of inventory, employee compensation, depreciation, depletion and amortization) in commonly presented expense captions. The ASU will impact our financial statement disclosures only and will be applied prospectively with retrospective application permitted. The ASU is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, and early adoption is permitted. We are currently evaluating the impact of the adoption of this ASU.

129			ConocoPhillips 2025 10-K

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, 2025, approximately three percent of our total proved reserves were under PSCs, located in our Asia Pacific/Middle East and Africa geographic reporting areas, and six 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.

ConocoPhillips 2025 10-K			130

Supplementary Data			Table of Contents

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 2025, our processes and controls used to assess over 90 percent of proved reserves as of December 31, 2025, 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, 2025 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 reservoir engineering. He is a member of the Society of Petroleum Engineers with over 20 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.

131			ConocoPhillips 2025 10-K

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 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
Revisions			5			185			190			5			(5)			15			52			257			—			257
Improved recovery			—			—			—			—			—			—			—			—			—			—
Purchases			23			364			387			—			—			—			25			412			—			412
Extensions and discoveries			14			29			43			9			—			—			—			52			24			76
Production			(62)			(211)			(273)			(6)			(25)			(22)			(18)			(344)			(5)			(349)
Sales			—			(3)			(3)			—			—			—			—			(3)			—			(3)
End of 2024			1,033			1,841			2,874			29			124			117			262			3,406			108			3,514
Revisions			(9)			237			228			(6)			1			14			18			255			—			255
Improved recovery			—			—			—			—			—			—			—			—			—			—
Purchases			—			—			—			—			—			—			—			—			—			—
Extensions and discoveries			46			64			110			4			—			—			—			114			—			114
Production			(63)			(269)			(332)			(6)			(23)			(21)			(25)			(407)			(5)			(412)
Sales			—			(47)			(47)			—			—			—			—			(47)			—			(47)
End of 2025			1,007			1,826			2,833			21			102			110			255			3,321			103			3,424

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 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
End of 2024			767			1,122			1,889			11			101			88			208			2,297			49			2,346
End of 2025			730			1,015			1,745			9			89			91			214			2,148			44			2,192
Undeveloped
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
End of 2024			266			719			985			18			23			29			54			1,109			59			1,168
End of 2025			277			811			1,088			12			13			19			41			1,173			59			1,232

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

ConocoPhillips 2025 10-K			132

Supplementary Data			Table of Contents

Notable changes in proved crude oil reserves in the three years ended December 31, 2025, included:

• Revisions: In 2025, upward revisions in Lower 48 were due to development drilling of 407 million barrels, technical revisions of 18 million barrels, and 13 million barrels due to lower operating costs, partially offset by downward revisions of 160 million barrels for changes in development plans and 41 million barrels due to lower prices. Upward revisions in Africa were in Libya, with development plan updates of 12 million barrels and technical revisions of 6 million barrels. Upward revisions of 14 million barrels in the consolidated operations in Asia Pacific/Middle East were split between China, where technical revisions contributed 4 million barrels and development plan updates 3 million barrels, and Malaysia, with upward technical revisions of 7 million barrels. In Alaska, downward revisions of 9 million barrels were due to lower prices of 21 million barrels, partially offset by 7 million barrels of upward technical revisions and 5 million barrels due to development plan updates. Downward revisions in Canada were due to technical revisions of 4 million barrels and changes in development plans of 2 million barrels.

In 2024, upward revisions in Lower 48 were due to development drilling of 298 million barrels and technical revisions of 28 million barrels, partially offset by downward revisions of 114 million barrels for changes in development plans, 23 million barrels due to lower prices and increasing operating costs of 4 million barrels. An upward revision of 52 million barrels in Africa was due to an increase in development plans in Libya. In the consolidated operations in Asia Pacific/Middle East, upward revisions of 15 million barrels were primarily due to the project sanction of Bohai Bay Phase 5 in China. Upward revisions of 5 million barrels in Canada 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 later than previously premised, resulting in upward revisions of 22 million barrels. Further upward revisions in Alaska include development plan changes of 8 million barrels. These were partially offset by downward revisions due to increasing operating costs of 15 million barrels and 10 million barrels due to technical revisions. Downward revisions in Europe were due to technical revisions of 3 million barrels and development plan changes of 2 million barrels.

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.

• Purchases: In 2024, our acquisition of Marathon Oil resulted in purchases for Lower 48, as well as for Africa, representing reserves in Equatorial Guinea. Purchases in Alaska represent the acquisition of additional interest in the Kuparuk River and Prudhoe Bay units.

• Extensions and discoveries: In 2025, Lower 48 extensions and discoveries were primarily within unconventional plays in the Permian Basin. Alaska extensions and discoveries were primarily in the Greater Kuparuk area, with 34 million barrels in the Coyote development and 8 million barrels in the Nuna project, as well as 4 million barrels from Western North Slope projects. Extensions and discoveries in Canada were in Montney.

In 2024, Lower 48 extensions and discoveries were primarily within unconventional plays in the Permian Basin. Alaska extensions and discoveries were primarily due to Nuna and other Western North Slope projects. Extensions and discoveries in Canada were in Montney. Extensions and discoveries in our equity affiliates were in the Middle East.

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.

• Sales: In 2025, Lower 48 sales represent noncore asset dispositions in the Anadarko Basin of 17 million barrels, offshore US assets of 14 million barrels, and other assets of 16 million barrels, primarily in the Permian Basin.

133			ConocoPhillips 2025 10-K

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			Africa			Total Consolidated Operations			Equity Affiliates*			Total
Developed and Undeveloped
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
Revisions			4			123			127			1			(2)			—			—			126			—			126
Improved recovery			—			—			—			—			—			—			—			—			—			—
Purchases			1			209			210			—			—			—			14			224			—			224
Extensions and discoveries			—			15			15			3			—			—			—			18			17			35
Production			(6)			(102)			(108)			(2)			(2)			—			—			(112)			(3)			(115)
Sales			—			(1)			(1)			—			—			—			—			(1)			—			(1)
End of 2024			71			1,041			1,112			12			9			—			14			1,147			62			1,209
Revisions			2			181			183			—			—			—			—			183			—			183
Improved recovery			—			—			—			—			—			—			—			—			—			—
Purchases			—			—			—			—			—			—			—			—			—			—
Extensions and discoveries			—			34			34			2			—			—			—			36			—			36
Production			(6)			(139)			(145)			(2)			(1)			—			(2)			(150)			(3)			(153)
Sales			—			(50)			(50)			—			—			—			—			(50)			—			(50)
End of 2025			67			1,067			1,134			12			8			—			12			1,166			59			1,225

Years Ended December 31			Natural Gas Liquids
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 2022			78			409			487			3			10			—						500			31			531
End of 2023			72			426			498			4			9			—						511			28			539
End of 2024			71			653			724			6			7			—			13			750			25			775
End of 2025			67			620			687			6			7			—			11			711			22			733
Undeveloped
End of 2022			—			340			340			2			3			—						345			19			364
End of 2023			—			371			371			6			4			—						381			20			401
End of 2024			—			388			388			6			2			—			1			397			37			434
End of 2025			—			447			447			6			1			—			1			455			37			492

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

ConocoPhillips 2025 10-K			134

Supplementary Data			Table of Contents

Notable changes in proved NGL reserves in the three years ended December 31, 2025, included:

• Revisions: In 2025, upward revisions in Lower 48 were due to additional development drilling of 224 million barrels, technical revisions of 49 million barrels, and 13 million barrels due to lower operating costs. This was partly offset by changes in development plan of 89 million barrels and lower prices of 16 million barrels.

In 2024, upward revisions in Lower 48 were due to additional development drilling of 164 million barrels and technical revisions of 52 million barrels. This was partially offset by development plan changes of 73 million barrels and lower prices impacting 20 million barrels.

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.

• Purchases: Purchases in 2024 were due to our acquisition of Marathon Oil, resulting in purchases for Lower 48 as well as in Africa, representing reserves in Equatorial Guinea.

• Extensions and discoveries: In 2025, Lower 48 extensions and discoveries were primarily within unconventional plays in the Permian Basin.

In 2024, Lower 48 extensions and discoveries were primarily within unconventional plays in the Permian Basin. Extensions and discoveries in our equity affiliates were in the Middle East.

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

• Sales: In 2025, Lower 48 sales represent noncore asset dispositions in the Anadarko Basin of 40 million barrels, offshore US assets of 2 million barrels, and other assets of 8 million barrels, primarily in the Permian Basin.

135			ConocoPhillips 2025 10-K

Supplementary Data			Table of Contents

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 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
Revisions			102			356			458			15			47			9			3			532			(26)			506
Improved recovery			—			—			—			—			—			—			—			—			—			—
Purchases			47			1,177			1,224			—			—			—			310			1,534			—			1,534
Extensions and discoveries			—			87			87			67			1			—			—			155			1,075			1,230
Production			(78)			(599)			(677)			(43)			(125)			(25)			(17)			(887)			(454)			(1,341)
Sales			—			(6)			(6)			—			—			—			—			(6)			—			(6)
End of 2024			2,246			5,736			7,982			279			746			296			468			9,771			5,870			15,641
Revisions			(76)			1,167			1,091			(29)			45			123			18			1,248			319			1,567
Improved recovery			—			—			—			—			—			—			—			—			—			—
Purchases			—			—			—			—			—			—			—			—			—			—
Extensions and discoveries			—			187			187			47			—			—			—			234			67			301
Production			(77)			(793)			(870)			(49)			(126)			(29)			(68)			(1,142)			(442)			(1,584)
Sales			—			(406)			(406)			—			—			—			—			(406)			—			(406)
End of 2025			2,093			5,891			7,984			248			665			390			418			9,705			5,814			15,519

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 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
End of 2024			2,186			3,670			5,856			147			642			289			457			7,391			3,189			10,580
End of 2025			1,994			3,379			5,373			123			584			385			413			6,878			3,148			10,026
Undeveloped
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
End of 2024			60			2,066			2,126			132			104			7			11			2,380			2,681			5,061
End of 2025			99			2,512			2,611			125			81			5			5			2,827			2,666			5,493

*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 2,211 BCF, 2,285 BCF and 2,263 BCF, as of December 31, 2025, 2024 and 2023, 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, 2025, included:

• Revisions: In 2025, upward revisions in Lower 48 were due to additional development drilling of 1,288 BCF, technical revisions of 335 BCF, and 108 BCF due to lower operating costs, partly offset by downward revisions of 487 BCF for changes in development plans, and 77 BCF due to lower prices. In the consolidated operations in Asia Pacific/Middle East, upward revisions in Malaysia were 120 BCF, where upward revisions of 113 BCF resulted from the extension of the Kebabangan Cluster (KBBC) PSC and additional agreements, and improved prices of 7 BCF. An additional 3 BCF of upward revisions in China were due to technical revisions. Upward technical revisions in Europe of 45 BCF were in Norway. Downward revisions in Alaska included 59 BCF due to price and 38 BCF to be consumed in operations, offset by development plan updates of 13 BCF and upward technical revisions of 8 BCF. Downward revisions in Canada were due to changes in development plans of 15 BCF and technical revisions of 14 BCF. Our equity affiliates in Australia had upward technical revisions of 319 BCF.

In 2024, upward revisions in Lower 48 were due to were due to additional development drilling of 841 BCF, technical revisions of 113 BCF, partly offset by downward revisions of 422 BCF for changes in development plans, 127 BCF due to lower prices and 49 BCF due to increasing operating costs. Upward revisions in Alaska of 68 BCF were due to updated total North Slope development phasing, as future production of gas is dependent on the Trans-Alaska Pipeline System minimum flow limit, which will be reached later than previously premised. Further upward revisions in Alaska included 28 BCF from revised development plans and 24 BCF to be consumed in operations. Offsetting downward revisions from technical revisions and costs were 18 BCF. In Europe, technical revisions contributed 64 BCF of upward revisions, offset by 17 BCF of development plan changes. In our equity affiliates, downward revisions were due to lower prices of 81 BCF, partially offset by positive technical revisions of 55 BCF.

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.

• Purchases: In 2024, our acquisition of Marathon Oil resulted in purchases for Lower 48, as well as for Africa, representing reserves in Equatorial Guinea. Purchases in Alaska represent the acquisition of additional interest in the Kuparuk River and Prudhoe Bay units.

• Extensions and discoveries: In 2025, 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 2024, 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 the Middle East and Australia.

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.

• Sales: In 2025, Lower 48 sales represent noncore asset dispositions in the Anadarko Basin of 344 BCF, offshore US assets of 15 BCF, and other assets of 47 BCF, primarily in the Permian Basin.

In 2023, 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 2022			216			216
Revisions			15			15
Improved recovery			—			—
Purchases			209			209
Extensions and discoveries			—			—
Production			(30)			(30)
Sales			—			—
End of 2023			410			410
Revisions			118			118
Improved recovery			—			—
Purchases			—			—
Extensions and discoveries			—			—
Production			(45)			(45)
Sales			—			—
End of 2024			483			483
Revisions			(32)			(32)
Improved recovery			—			—
Purchases			—			—
Extensions and discoveries			—			—
Production			(49)			(49)
Sales			—			—
End of 2025			402			402

Years Ended December 31			Bitumen
Millions of Barrels
			Canada			Total*
Developed
End of 2022			127			127
End of 2023			293			293
End of 2024			230			230
End of 2025			234			234
Undeveloped
End of 2022			89			89
End of 2023			117			117
End of 2024			253			253
End of 2025			168			168

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

Notable changes in proved bitumen reserves in the three years ended December 31, 2025, included:

• Revisions: In 2025, downward revisions of 67 million barrels due to changes in development timing were partially offset by upward technical revisions of 18 million barrels and an upward revision of 17 million barrels due to the impact of price on variable royalties.

In 2024, upward revisions of 125 million barrels due to changes in development timing was partially offset by downward revisions due to price of 7 million barrels.

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

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

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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 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
Revisions			25			367			392			127			3			16			52			590			(6)			584
Improved recovery			—			—			—			—			—			—			—			—			—			—
Purchases			32			768			800			—			—			—			91			891			—			891
Extensions and discoveries			14			59			73			23			—			—			—			96			220			316
Production			(81)			(413)			(494)			(60)			(48)			(26)			(21)			(649)			(83)			(732)
Sales			—			(5)			(5)			—			—			—			—			(5)			—			(5)
End of 2024			1,478			3,838			5,316			571			258			166			354			6,665			1,147			7,812
Revisions			(21)			613			592			(43)			8			35			21			613			54			667
Improved recovery			—			—			—			—			—			—			—			—			—			—
Purchases			—			—			—			—			—			—			—			—			—			—
Extensions and discoveries			46			129			175			14			—			—			—			189			11			200
Production			(81)			(540)			(621)			(66)			(45)			(26)			(38)			(796)			(81)			(877)
Sales			—			(165)			(165)			—			—			—			—			(165)			—			(165)
End of 2025			1,422			3,875			5,297			476			221			175			337			6,506			1,131			7,637

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 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
End of 2024			1,202			2,387			3,589			272			215			136			297			4,509			606			5,115
End of 2025			1,129			2,198			3,327			270			193			155			294			4,239			591			4,830
Undeveloped
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
End of 2024			276			1,451			1,727			299			43			30			57			2,156			541			2,697
End of 2025			293			1,677			1,970			206			28			20			43			2,267			540			2,807

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

Natural gas reserves are converted to 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 2025:

			Proved Undeveloped Reserves
			Millions of Barrels of Oil Equivalent
End of 2024			2,697
Revisions			554
Improved recovery			—
Purchases			—
Extensions and discoveries			159
Sales			(3)
Transfers to Proved Developed			(600)
End of 2025			2,807

Upward revisions of 554 MMBOE were predominately driven by progression of development plans of 635 MMBOE in the Lower 48 unconventional plays (including development plan updates in 2025 following the acquisition of Marathon Oil in late 2024), Alaska, and Libya, including 61 MMBOE due to extension of economic limit resulting from new development. This is partly offset by changes in development plans, primarily in Canada.

Extensions and discoveries were largely driven by the continued development planned in Lower 48. The remaining extensions and discoveries were driven by the continued development planned in the other geographic regions, including Alaska, Canada, and Australia.

Transfers to proved developed reserves were driven by the ongoing development of our assets. Approximately 76 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, 2025, our PUDs represented 37 percent of total proved reserves, compared with 35 percent at December 31, 2024. Costs incurred for the year ended December 31, 2025 relating to the development of PUDs were $10.3 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 2025, approximately 89 percent of total PUDs were under development or scheduled for development within five years of initial disclosure, including all of our Lower 48 PUDs. The PUDs to be developed beyond five years are in the Willow project in Alaska, a development that is currently underway with production anticipated in 2029 due to its large scale and remote location, as well as in major development areas which are currently producing and located in Canada and Australia.

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Results of Operations

The company’s results of operations from oil and gas activities for the years 2025, 2024 and 2023 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.

Results of Operations

Year Ended December 31, 2025			Millions of Dollars
Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Other Areas			Total Consolidated Operations			Equity Affiliates*
Consolidated operations
Sales			$	5,048		21,553			26,601			2,387			3,158			1,601			2,182			—			35,929			730
Transfers			5			—			5			—			—			—			—			—			5			2,716
Transportation costs			(787)			—			(787)			—			—			—			—			—			(787)			—
Other revenues			1			505			506			20			33			39			181			15			794			13
Total revenues			4,267			22,058			26,325			2,407			3,191			1,640			2,363			15			35,941			3,459
Production costs excluding taxes			1,485			5,856			7,341			832			613			358			296			1			9,441			540
Taxes other than income taxes			376			1,500			1,876			27			42			56			4			—			2,005			1,007
Exploration expenses			32			174			206			24			32			117			24			—			403			—
Depreciation, depletion and amortization			1,239			8,092			9,331			511			676			459			231			—			11,208			447
Impairments			1			26			27			(1)			—			—			—			—			26			—
Other related expenses			59			70			129			18			19			(40)			12			16			154			(4)
Accretion			108			123			231			18			72			31			—			—			352			27
			967			6,217			7,184			978			1,737			659			1,796			(2)			12,352			1,442
Income tax provision (benefit)			248			1,293			1,541			233			1,354			243			1,447			1			4,819			443
Results of operations			$	719		4,924			5,643			745			383			416			349			(3)			7,533			999
*All Equity Affiliate activity is located in our Asia Pacific/Middle East Region.

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Year Ended December 31,2024			Millions of Dollars
Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Other Areas			Total Consolidated Operations			Equity Affiliates*
Consolidated operations
Sales			$	5,574		19,028			24,602			2,567			3,469			1,847			1,488			—			33,973			917
Transfers			6			—			6			—			—			—			—			—			6			3,343
Transportation costs			(709)			—			(709)			—			—			—			—			—			(709)			—
Other revenues			—			108			108			(34)			(69)			3			117			13			138			18
Total revenues			4,871			19,136			24,007			2,533			3,400			1,850			1,605			13			33,408			4,278
Production costs excluding taxes			1,330			4,691			6,021			902			506			350			120			—			7,899			543
Taxes other than income taxes			410			1,372			1,782			31			36			108			4			—			1,961			1,181
Exploration expenses			74			85			159			80			68			40			8			1			356			—
Depreciation, depletion and amortization			1,175			6,422			7,597			594			689			424			67			—			9,371			484
Impairments			32			42			74			4			2			—			—			—			80			—
Other related expenses			(36)			49			13			(52)			(68)			—			5			14			(88)			(8)
Accretion			106			79			185			18			68			28			—			—			299			19
			1,780			6,396			8,176			956			2,099			900			1,401			(2)			13,530			2,059
Income tax provision (benefit)			461			1,407			1,868			224			1,539			222			1,306			(1)			5,158			623
Results of operations			$	1,319		4,989			6,308			732			560			678			95			(1)			8,372			1,436
*All Equity Affiliate activity is located in our Asia Pacific/Middle East Region.

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			Equity Affiliates*
Consolidated operations
Sales			$	5,918		18,976			24,894			1,517			3,449			1,914			1,447			—			33,221			822
Transfers			5			—			5			—			—			—			—			—			5			3,429
Transportation costs			(611)			—			(611)			—			—			—			—			—			(611)			—
Other revenues			(4)			142			138			(1)			3			(1)			181			3			323			14
Total revenues			5,308			19,118			24,426			1,516			3,452			1,913			1,628			3			32,938			4,265
Production costs excluding taxes			1,242			4,175			5,417			602			499			348			74			1			6,941			493
Taxes other than income taxes			442			1,347			1,789			26			35			115			3			—			1,968			1,208
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			390
Impairments			—			7			7			6			—			—			—			—			13			—
Other related expenses			71			42			113			60			(24)			17			3			12			181			(8)
Accretion			94			65			159			12			61			27			—			—			259			30
			2,449			7,627			10,076			387			2,276			908			1,494			(13)			15,128			2,152
Income tax provision (benefit)			640			1,667			2,307			5			1,704			66			1,375			—			5,457			658
Results of operations			$	1,809		5,960			7,769			382			572			842			119			(13)			9,671			1,494
*All Equity Affiliate activity is located in our Asia Pacific/Middle East Region.

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Statistics

Net Production			2025			2024			2023
			Thousands of Barrels Daily
Crude Oil
Consolidated operations
Alaska			177			173			173
Lower 48			749			602			569
United States			926			775			742
Canada			17			17			9
Europe			63			69			64
Asia Pacific			59			59			60
Africa			68			49			48
Total consolidated operations			1,133			969			923
Equity affiliates—Asia Pacific/Middle East			12			13			13
Total company			1,145			982			936
Delaware Basin Area (Lower 48)*			321			301			274
Natural Gas Liquids
Consolidated operations
Alaska			15			15			16
Lower 48			382			279			256
United States			397			294			272
Canada			6			6			3
Europe			3			4			4
Africa			5			—			—
Total consolidated operations			411			304			279
Equity affiliates—Asia Pacific/Middle East			8			8			8
Total company			419			312			287
Delaware Basin Area (Lower 48)*			171			144			135
Bitumen
Consolidated operations—Canada			133			122			81
Total company			133			122			81
Natural Gas			Millions of Cubic Feet Daily
Consolidated operations
Alaska			41			39			38
Lower 48			2,119			1,625			1,457
United States			2,160			1,664			1,495
Canada			125			115			65
Europe			330			329			279
Asia Pacific			63			50			48
Africa			181			42			29
Total consolidated operations			2,859			2,200			1,916
Equity affiliates—Asia Pacific/Middle East			1,206			1,233			1,219
Total company			4,065			3,433			3,135
Delaware Basin Area (Lower 48)*			1,011			884			768

*At year-end 2025, 2024 and 2023, the Delaware Basin Area in Lower 48 contained more than 15 percent of our total proved reserves.

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Average Sales Prices			2025			2024			2023
Crude Oil Per Barrel
Consolidated operations
Alaska*			$	60.59		71.32			74.46
Lower 48			63.18			74.17			76.19
United States			62.65			73.49			75.75
Canada			55.35			64.47			66.19
Europe			70.52			81.09			84.56
Asia Pacific			71.05			82.42			84.79
Africa			67.45			80.65			83.07
Total international			68.44			79.97			83.33
Total consolidated operations			63.70			74.76			77.19
Equity affiliates—Asia Pacific/Middle East			68.94			76.76			78.45
Total operations			63.75			74.78			77.21
Natural Gas Liquids Per Barrel
Consolidated operations
Lower 48			$	20.64		22.02			21.73
United States			20.64			22.02			21.73
Canada			22.54			29.59			26.13
Europe			41.39			45.50			41.13
Africa			1.00			—			—
Total international			19.23			33.60			34.56
Total consolidated operations			20.59			22.43			22.12
Equity affiliates—Asia Pacific/Middle East			46.20			51.53			47.09
Total operations			21.07			23.19			22.82
Bitumen Per Barrel
Consolidated operations—Canada			$	40.74		47.92			42.15
Natural Gas Per Thousand Cubic Feet
Consolidated operations
Alaska			$	3.81		3.90			4.47
Lower 48			1.74			0.87			2.12
United States			1.74			0.88			2.13
Canada**			1.02			0.54			1.80
Europe			12.08			11.11			13.33
Asia Pacific			3.59			3.74			3.95
Africa			8.58			7.32			6.49
Total international			8.44			7.87			10.01
Total consolidated operations			3.40			2.61			3.89
Equity affiliates—Asia Pacific/Middle East			6.83			8.22			8.46
Total operations			4.44			4.69			5.69

*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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Supplementary Data			Table of Contents

			2025			2024			2023
Average Production Costs Per Barrel of Oil Equivalent*
Consolidated operations
Alaska			$	20.44		18.73			17.45
Lower 48			10.81			11.13			10.72
United States			11.95			12.22			11.76
Canada			12.88			15.03			15.86
Europe			13.88			10.80			11.89
Asia Pacific			14.01			14.27			14.02
Africa			7.87			5.85			3.83
Total international			12.22			12.36			12.28
Total consolidated operations			12.01			12.26			11.87
Equity affiliates—Asia Pacific/Middle East			6.69			6.56			6.03
Average Production Costs Per Barrel—Bitumen
Consolidated operations—Canada			$	11.63		15.19			14.42
Taxes Other Than Income Taxes Per Barrel of Oil Equivalent
Consolidated operations
Alaska			$	5.18		5.77			6.21
Lower 48			2.77			3.25			3.46
United States			3.05			3.62			3.88
Canada			0.42			0.52			0.68
Europe			0.95			0.77			0.83
Asia Pacific			2.19			4.40			4.63
Africa			0.11			0.20			0.16
Total international			0.75			1.18			1.44
Total consolidated operations			2.55			3.04			3.37
Equity affiliates—Asia Pacific/Middle East			12.48			14.28			14.77
Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent
Consolidated operations
Alaska			$	17.06		16.55			13.18
Lower 48			14.94			15.23			14.64
United States			15.19			15.42			14.42
Canada			7.91			9.90			9.85
Europe			15.31			14.71			12.67
Asia Pacific			17.96			17.29			18.29
Africa			6.14			3.27			2.58
Total international			10.92			11.68			11.36
Total consolidated operations			14.26			14.54			13.77
Equity affiliates—Asia Pacific/Middle East			5.54			5.85			4.77

*Includes bitumen.

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Supplementary Data			Table of Contents

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, 2025, 2024 and 2023. 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
			2025			2024			2023						2025			2024			2023
Exploratory
Consolidated operations
Alaska			—			—			—						—			—			2
Lower 48			31			39			38						—			—			2
United States			31			39			38						—			—			4
Canada			4			7			6						—			—			—
Europe			—			—			—						*****			*			*
Asia Pacific/Middle East			*****			*			—						4			—			—
Africa			—			—			—						—			1			—
Total consolidated operations			35			46			44						4			1			4
Equity affiliates
Asia Pacific/Middle East			6			2			3						—			—			*
Total equity affiliates			6			2			3						—			—			*
Development
Consolidated operations
Alaska			14			13			11						—			—			—
Lower 48			657			507			494						—			—			—
United States			671			520			505						—			—			—
Canada			40			38			21						—			—			—
Europe			4			8			4						—			—			—
Asia Pacific/Middle East			24			23			20						—			—			—
Africa			11			5			4						*****			—			—
Total consolidated operations			750			594			554						—			—			—
Equity affiliates
Asia Pacific/Middle East			87			54			45						—			—			—
Total equity affiliates			87			54			45						—			—			—

*Our total proportionate interest was less than one.

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Supplementary Data			Table of Contents

The table below represents the status of our wells drilling at December 31, 2025, 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, 2025.

Wells at December 31, 2025

												Productive
			In Progress									Oil									Gas
			Gross			Net						Gross			Net						Gross			Net
Consolidated operations
Alaska			2			2						1,547			940						—			—
Lower 48			717			417						19,692			9,900						3,921			2,633
United States			719			419						21,239			10,840						3,921			2,633
Canada			59			59						227			227						178			178
Europe			10			3						513			83						70			4
Asia Pacific/Middle East			16			8						536			254						6			2
Africa			20			5						972			198						27			13
Total consolidated operations			824			494						23,487			11,602						4,202			2,830
Equity affiliates
Asia Pacific/Middle East			242			35						—			—						5,924			1,709
Total equity affiliates			242			35						—			—						5,924			1,709

Acreage at December 31, 2025

			Thousands of Acres
			Developed									Undeveloped
			Gross			Net						Gross			Net
Consolidated operations
Alaska			741			566						1,038			1,012
Lower 48			3,938			2,756						10,797			8,293
United States			4,679			3,322						11,835			9,305
Canada			316			293						3,387			1,998
Europe			451			58						347			155
Asia Pacific/Middle East			422			152						7,596			4,996
Africa			440			140						12,545			2,561
Total consolidated operations			6,308			3,965						35,710			19,015
Equity affiliates
Asia Pacific/Middle East			1,160			342						4,003			1,039
Total equity affiliates			1,160			342						4,003			1,039

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Supplementary Data			Table of Contents

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 Consolidated Operations			Equity Affiliates*
2025
Consolidated operations
Unproved property acquisition			$	—		215			215			—			—			—			—			—			215			—
Proved property acquisition			5			42			47			—			—			—			—			—			47			—
			5			257			262			—			—			—			—			—			262			—
Exploration			42			573			615			61			113			113			26			—			928			9
Development			3,549			6,102			9,651			574			428			282			239			—			11,174			439
			$	3,596		6,932			10,528			635			541			395			265			—			12,364			448
2024
Consolidated operations
Unproved property acquisition			$	—		10,985			10,985			—			—			—			—			—			10,985			—
Proved property acquisition			297			12,118			12,415			(46)			—			—			1,100			—			13,469			—
			297			23,103			23,400			(46)			—			—			1,100			—			24,454			—
Exploration			98			548			646			239			49			46			7			1			988			18
Development			2,808			6,301			9,109			390			598			354			91			—			10,542			323
			$	3,203		29,952			33,155			583			647			400			1,198			1			35,984			341
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			46
Development			1,884			6,266			8,150			367			843			383			38			—			9,781			416
			$	1,951		6,925			8,876			3,640			888			432			42			3			13,881			462
*All Equity Affiliate activity is located in our Asia Pacific/Middle East Region.

Capitalized Costs

At December 31			Millions of Dollars
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Other Areas			Total Consolidated Operations			Equity Affiliates*
2025
Consolidated operations
Proved property			$	32,822		93,970			126,792			12,060			15,047			11,561			2,509			—			167,969			12,121
Unproved property			117			9,102			9,219			1,299			129			76			99			—			10,822			2,135
			32,939			103,072			136,011			13,359			15,176			11,637			2,608			—			178,791			14,256
Accumulated depreciation, depletion and amortization			15,150			46,781			61,931			4,332			11,276			9,305			800			—			87,644			9,681
			$	17,789		56,291			74,080			9,027			3,900			2,332			1,808			—			91,147			4,575
2024
Consolidated operations
Proved property			$	29,435		88,461			117,896			10,904			12,986			11,274			2,304			—			155,364			11,691
Unproved property			107			13,883			13,990			1,256			41			96			97			10			15,490			2,133
			29,542			102,344			131,886			12,160			13,027			11,370			2,401			10			170,854			13,824
Accumulated depreciation, depletion and amortization			13,946			42,089			56,035			3,651			9,412			8,842			575			10			78,525			9,246
			$	15,596		60,255			75,851			8,509			3,615			2,528			1,826			—			92,329			4,578
*All Equity Affiliate activity is located in our Asia Pacific/Middle East Region.

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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 Consolidated Operations			Equity Affiliates*			Total
2025
Future cash inflows			$	66,071		148,328			214,399			18,409			14,974			8,965			22,224			278,971			44,287			323,258
Less:
Future production costs			36,032			69,324			105,356			7,854			5,290			3,726			2,466			124,692			27,353			152,045
Future development costs			13,540			21,994			35,534			1,628			3,697			1,359			576			42,794			3,175			45,969
Future income tax provisions			3,660			10,185			13,845			1,185			4,649			950			17,079			37,708			3,901			41,609
Future net cash flows			12,839			46,825			59,664			7,742			1,338			2,930			2,103			73,777			9,858			83,635
10 percent annual discount			5,400			14,372			19,772			2,607			(32)			914			570			23,831			3,842			27,673
Discounted future net cash flows			$	7,439		32,453			39,892			5,135			1,370			2,016			1,533			49,946			6,016			55,962
*All Equity Affiliate activity is located in our Asia Pacific/Middle East Region. Total Discounted future net cash flows for Asia Pacific/Middle East was $8,032.

			Millions of Dollars
			Alaska			Lower 48**			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Total Consolidated Operations			Equity Affiliates*			Total
2024
Future cash inflows			$	79,396		164,264			243,660			24,685			18,148			10,405			26,592			323,490			51,975			375,465
Less:
Future production costs			39,861			73,663			113,524			9,433			5,924			4,189			2,678			135,748			29,807			165,555
Future development costs			12,766			21,143			33,909			2,370			3,611			1,586			693			42,169			3,234			45,403
Future income tax provisions			5,664			13,098			18,762			1,886			6,680			1,131			20,750			49,209			5,630			54,839
Future net cash flows			21,105			56,360			77,465			10,996			1,933			3,499			2,471			96,364			13,304			109,668
10 percent annual discount			9,742			17,667			27,409			4,217			94			1,087			828			33,635			5,170			38,805
Discounted future net cash flows			$	11,363		38,693			50,056			6,779			1,839			2,412			1,643			62,729			8,134			70,863
*All Equity Affiliate activity is located in our Asia Pacific/Middle East Region. Total Discounted future net cash flows for Asia Pacific/Middle East was $10,546.

			Millions of Dollars
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Total Consolidated Operations			Equity Affiliates*			Total
2023
Future cash inflows			$	83,793		141,307			225,100			19,937			23,569			11,322			21,562			301,490			51,887			353,377
Less:
Future production costs			39,069			57,303			96,372			8,699			6,576			4,586			1,008			117,241			28,579			145,820
Future development costs			13,685			21,391			35,076			2,058			3,802			1,458			400			42,794			2,299			45,093
Future income tax provisions			7,386			12,451			19,837			880			10,140			1,316			18,687			50,860			5,647			56,507
Future net cash flows			23,653			50,162			73,815			8,300			3,051			3,962			1,467			90,595			15,362			105,957
10 percent annual discount			11,522			16,850			28,372			2,723			432			1,257			570			33,354			5,543			38,897
Discounted future net cash flows			$	12,131		33,312			45,443			5,577			2,619			2,705			897			57,241			9,819			67,060
*All Equity Affiliate activity is located in our Asia Pacific/Middle East Region. Total Discounted future net cash flows for Asia Pacific/Middle East was $12,524.

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Supplementary Data			Table of Contents

Sources of Change in Discounted Future Net Cash Flows

			Millions of Dollars
			Consolidated Operations												Equity Affiliates												Total Company
			2025			2024			2023						2025			2024			2023						2025			2024			2023
Discounted future net cash flows at the beginning of the year			$	62,729		$	57,241		85,720						$	8,134		9,819			13,272						$	70,863		67,060			98,992
Changes during the year
Revenues less production costs for the year			(23,701)			(23,410)			(23,706)						(1,899)			(2,536)			(2,550)						(25,600)			(25,946)			(26,256)
Net change in prices, and production costs			(16,493)			(10,025)			(51,887)						(3,081)			(941)			(4,519)						(19,574)			(10,966)			(56,406)
Extensions, discoveries and improved recovery, less estimated future costs			(1,959)			(1,015)			1,751						(95)			507			118						(2,054)			(508)			1,869
Development costs for the year			11,110			10,197			9,129						458			402			326						11,568			10,599			9,455
Changes in estimated future development costs			(5,229)			(3,512)			(6,754)						(94)			(274)			(150)						(5,323)			(3,786)			(6,904)
Purchases of reserves in place, less estimated future costs			—			11,068			3,024						—			—			—						—			11,068			3,024
Sales of reserves in place, less estimated future costs			(1,161)			(113)			(446)						—			—			—						(1,161)			(113)			(446)
Revisions of previous quantity estimates			9,242			14,175			9,047						491			23			492						9,733			14,198			9,539
Accretion of discount			8,553			8,137			12,414						1,049			1,199			1,635						9,602			9,336			14,049
Net change in income taxes			6,855			(14)			18,949						1,053			(65)			1,195						7,908			(79)			20,144
Total changes			(12,783)			5,488			(28,479)						(2,118)			(1,685)			(3,453)						(14,901)			3,803			(31,932)
Discounted future net cash flows at year end			$	49,946		$	62,729		57,241						$	6,016		8,134			9,819						$	55,962		70,863			67,060

• 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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