CONOCOPHILLIPS 10-K

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 69 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 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 ConocoPhillips 2025 10-K 70 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. 73 ConocoPhillips 2025 10-K 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. ConocoPhillips 2025 10-K 74 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. 77 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents • 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. ConocoPhillips 2025 10-K 78 Notes to Consolidated Financial Statements Table of Contents • 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 . 79 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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, s ee 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. ConocoPhillips 2025 10-K 80 Notes to Consolidated Financial Statements Table of Contents 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 . 81 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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, s e e 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. ConocoPhillips 2025 10-K 82 Notes to Consolidated Financial Statements Table of Contents 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. 83 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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. ConocoPhillips 2025 10-K 84 Notes to Consolidated Financial Statements Table of Contents 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. 85 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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. ConocoPhillips 2025 10-K 86 Notes to Consolidated Financial Statements Table of Contents 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. 87 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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. ConocoPhillips 2025 10-K 88 Notes to Consolidated Financial Statements Table of Contents 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 89 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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 2037 1 : $ 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 ConocoPhillips 2025 10-K 90 Notes to Consolidated Financial Statements Table of Contents 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. 91 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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. ConocoPhillips 2025 10-K 92 Notes to Consolidated Financial Statements Table of Contents 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 93 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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. ConocoPhillips 2025 10-K 94 Notes to Consolidated Financial Statements Table of Contents 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. 95 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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 ConocoPhillips 2025 10-K 96 Notes to Consolidated Financial Statements Table of Contents 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. 97 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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: ConocoPhillips 2025 10-K 98 Notes to Consolidated Financial Statements Table of Contents 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. 99 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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 ConocoPhillips 2025 10-K 100 Notes to Consolidated Financial Statements Table of Contents 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. 101 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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. ConocoPhillips 2025 10-K 102 Notes to Consolidated Financial Statements Table of Contents 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. 103 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents The following table summarizes the right-of-use assets and lease liabilities for both the operating and finance leases on our consolidated balance sheet as of December 31: Millions of Dollars 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 ConocoPhillips 2025 10-K 104 Notes to Consolidated Financial Statements Table of Contents 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. 105 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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 ) ConocoPhillips 2025 10-K 106 Notes to Consolidated Financial Statements Table of Contents 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. 107 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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: ConocoPhillips 2025 10-K 108 Notes to Consolidated Financial Statements Table of Contents 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 109 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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. ConocoPhillips 2025 10-K 110 Notes to Consolidated Financial Statements Table of Contents The fair values of our pension plan assets at December 31, by asset class were as follows: Millions of Dollars U.S. International Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total 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. 111 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents The fair values of our pension plan assets at December 31, by asset class were as follows: Millions of Dollars U.S. International Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total 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. ConocoPhillips 2025 10-K 112 Notes to Consolidated Financial Statements Table of Contents The following benefit payments, which are exclusive of amounts to be paid from the insurance annuity contract and which reflect expected future service, as appropriate, are expected to be paid: Millions of Dollars Pension Benefits Other Benefits U.S. Int’l. 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 113 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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. ConocoPhillips 2025 10-K 114 Notes to Consolidated Financial Statements Table of Contents 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. 115 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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 ConocoPhillips 2025 10-K 116 Notes to Consolidated Financial Statements Table of Contents 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. 117 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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 . ConocoPhillips 2025 10-K 118 Notes to Consolidated Financial Statements Table of Contents 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. 119 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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. ConocoPhillips 2025 10-K 120 Notes to Consolidated Financial Statements Table of Contents 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. 121 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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. ConocoPhillips 2025 10-K 122 Notes to Consolidated Financial Statements Table of Contents 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 286 246 282 123 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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 ConocoPhillips 2025 10-K 124 Notes to Consolidated Financial Statements Table of Contents 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. 125 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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 ConocoPhillips 2025 10-K 126 Notes to Consolidated Financial Statements Table of Contents 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 12,118 127 ConocoPhillips 2025 10-K Notes to Consolidated Financial Statements Table of Contents 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. ConocoPhillips 2025 10-K 136 Supplementary Data Table of Contents 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. 137 ConocoPhillips 2025 10-K Supplementary Data Table of Contents 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. ConocoPhillips 2025 10-K 138 Supplementary Data Table of Contents 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. 139 ConocoPhillips 2025 10-K Supplementary Data Table of Contents 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. ConocoPhillips 2025 10-K 140 Supplementary Data Table of Contents 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. 141 ConocoPhillips 2025 10-K Supplementary Data Table of Contents 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. ConocoPhillips 2025 10-K 142 Supplementary Data Table of Contents 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. 143 ConocoPhillips 2025 10-K Supplementary Data Table of Contents 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. ConocoPhillips 2025 10-K 144 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. 145 ConocoPhillips 2025 10-K 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. ConocoPhillips 2025 10-K 146 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 1,039 147 ConocoPhillips 2025 10-K 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. ConocoPhillips 2025 10-K 148 Supplementary Data Table of Contents Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities In accordance with SEC and FASB requirements, amounts were computed using 12-month average prices (adjusted only for existing contractual terms) and end-of-year costs, appropriate statutory tax rates and a prescribed 10 percent discount factor. Twelve-month average prices are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. For all years, continuation of year-end economic conditions was assumed. The calculations were based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, were not considered. The calculations also require assumptions as to the timing of future production of proved reserves and the timing and amount of future development costs, including dismantlement, and future production costs, including taxes other than income taxes. While due care was taken in its preparation, we do not represent that this data is the fair value of our oil and gas properties, or a fair estimate of the present value of cash flows to be obtained from their development and production. Discounted Future Net Cash Flows Millions of Dollars Alaska Lower 48 Total U.S. Canada Europe Asia Pacific/ Middle East Africa Total 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. 149 ConocoPhillips 2025 10-K 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. ConocoPhillips 2025 10-K 150 Table of Contents Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None.