CONOCOPHILLIPS 10-K

Item 8. Financial Statements and Supplementary Data ConocoPhillips Index to Financial Statements Page Reports of Management 71 Reports of Independent Registered Public Accounting Firm (PCAOB ID # 42 ) 72 Financial Statements Consolidated Income Statement for the years ended December 31, 2024 , 2023 and 2022 77 Consolidated Statement of Comprehensive Income for the years ended December 31, 2024 , 2023 and 2022 78 Consolidated Balance Sheet at December 31, 2024 and 2023 79 Consolidated Statement of Cash Flows for the years ended December 31, 2024 , 2023 and 2022 80 Consolidated Statement of Changes in Equity for the years ended December 31, 2024 , 2023 and 2022 81 Notes to Consolidated Financial Statements Note 1 —Accounting Policies 82 Note 2 —Inventories 86 Note 3 —Acquisitions and Dispositions 86 Note 4 —Investments, Loans and Long-Term Receivables 91 Note 5 —Investment in Cenovus Energy 93 Note 6 —Suspended Wells and Exploration Expenses 93 Note 7 —Asset Retirement Obligations and Accrued Environmental Costs 95 Note 8 —Debt 96 Note 9 —Guarantees 100 Note 10 —Contingencies and Commitments 101 Note 11 —Derivatives and Financial Instruments 104 Note 12 —Fair Value Measurement 108 Note 13 —Equity 110 Note 14 —Non-Mineral Leases 111 Note 15 —Employee Benefit Plans 114 Note 16 —Income Taxes 125 Note 17 —Accumulated Other Comprehensive Income (Loss) 128 Note 18 —Cash Flow Information 128 Note 19 —Other Financial Information 129 Note 20 —Related Party Transactions 130 Note 21 —Sales and Other Operating Revenues 130 Note 22 —Earnings Per Share 132 Note 23 —Segment Disclosures and Related Information 132 Note 24 —New Accounting Standards 136 Supplementary Information Oil and Gas Operations 137 ConocoPhillips 2024 10-K 70 Table of Contents Reports of Management Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the company’s financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the company includes amounts that are based on estimates and judgments management believes are reasonable under the circumstances. The company’s financial statements have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed by the Audit and Finance Committee of the Board of Directors and ratified by stockholders. Management has made available to Ernst & Young LLP all of the company’s financial records and related data, as well as the minutes of stockholders’ and directors’ meetings. Assessment of Internal Control Over Financial Reporting Management is also responsible for establishing and maintaining adequate internal control over financial reporting. ConocoPhillips’ internal control system was designed to provide reasonable assurance to the company’s management and directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2024. 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). Our assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of Marathon Oil Corporation, acquired in 2024, which is included in our consolidated financial statements and represented approximately 22% of our total assets as of December 31, 2024, approximately 1% of our revenues and other income and less than 1% of our net income for the year ended December 31, 2024. Based on our assessment, we believe the company’s internal control over financial reporting was effective as of December 31, 2024. Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2024, and their report is included herein. /s/ Ryan M. Lance /s/ William L. Bullock, Jr. Ryan M. Lance William L. Bullock, Jr. Chairman and Chief Executive Officer Executive Vice President and Chief Financial Officer 71 ConocoPhillips 2024 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, 2024 and 2023, 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, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, 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, 2024, 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 18, 2025 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 Matters The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the Audit and Finance Committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. ConocoPhillips 2024 10-K 72 Table of Contents Depreciation, depletion and amortization of proved oil and gas properties, plants and equipment Description of the Matter At December 31, 2024, the net book value of the Company’s proved oil and gas properties, plants and equipment (PP&E) was $77 billion, and depreciation, depletion and amortization (DD&A) expense was $9.4 billion for the year then ended. As described in Note 1, under the successful efforts method of accounting, DD&A of PP&E on producing hydrocarbon properties and steam-assisted gravity drainage facilities and certain pipeline and liquified natural gas assets (those which are expected to have a declining utilization pattern) are determined by the unit-of-production method. The unit-of-production method uses proved oil and gas reserves, as estimated by the Company’s internal reservoir engineers. Proved oil and gas reserves estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan, historical extraction recovery and processing yield factors, installed plant operating capacity and approved operating limits. Significant judgment is required by the Company’s internal reservoir engineers in evaluating the data used to estimate proved oil and gas reserves. Estimating proved oil and gas reserves also requires the selection of inputs, including historical production, oil and gas price assumptions and future operating costs assumptions, among others. Auditing the Company’s DD&A calculation is complex because of the use of the work of the internal reservoir engineers and the evaluation of management’s determination of the inputs described above used by the internal reservoir engineers in estimating proved oil and gas reserves. How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s internal controls over its processes to calculate DD&A, including management’s controls over the completeness and accuracy of significant data provided to the internal reservoir engineers for use in estimating proved oil and gas reserves. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company’s internal reservoir engineers primarily responsible for overseeing the preparation of the proved oil and gas reserves estimates. In addition, in assessing whether we can use the work of the internal reservoir engineers, we evaluated the completeness and accuracy of the 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, including comparing the proved oil and gas reserves amounts used in the calculation to the Company’s reserve report. 73 ConocoPhillips 2024 10-K Table of Contents Valuation and recognition of proved and unproved oil and gas properties acquired in a business combination Description of the Matter During 2024, the Company closed its acquisition of Marathon Oil Corporation resulting in the recognition of a provisional fair value of proved and unproved oil and gas properties within net properties, plants and equipment of $13.2 billion and $10.8 billion, respectively. As described in Note 3, the transaction was accounted for as a business combination using the acquisition method, which requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. As also described in Note 3, the Company has not finalized its allocation of fair value to unproved properties. Oil and gas properties were valued by specialists using a discounted cash flow approach based on market participant assumptions. Significant inputs to the valuation of proved and unproved oil and gas properties include estimates of future commodity prices and production, future operating costs and discount rates using a market-based weighted average cost of capital. Auditing the Company's accounting for its provisional valuation of proved and unproved oil and gas properties within the Lower 48 segment is complex and judgmental due to the significant estimation required by management of reserves associated with the acquired assets and the sensitivity of significant assumptions used in determining the fair value. In evaluating the reasonableness of management’s estimates and assumptions used, the audit testing procedures performed required a high degree of auditor judgment and additional effort, including involving internal valuation specialists. 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 process to estimate the provisional fair value of the acquired proved and unproved oil and gas properties, including management’s review of the significant assumptions used as inputs to the fair value calculations and recording of the provisional valuation. To test the provisional fair value of the acquired proved and unproved oil and gas properties, our audit procedures included, among others, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data supporting the significant assumptions. For example, we compared certain significant assumptions to current industry and third-party data and historical results for reasonableness. We also performed sensitivity analyses of significant assumptions, to evaluate the extent of their impact to the provisional fair value calculation. In addition, we involved internal valuation specialists to assist with certain significant assumptions included in the provisional fair value estimate. Furthermore, we evaluated the professional qualifications and objectivity of the Company’s internal reservoir engineers primarily responsible for overseeing the oil and gas reserves estimates and the valuation specialists used by the Company to prepare the provisional fair value of the acquired proved and unproved oil and gas properties. 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 used by the internal reservoir engineers in estimating oil and gas reserves by agreeing them to source documentation, as applicable, and we identified and evaluated corroborative and contrary evidence. As noted above, the Company has not finalized its allocation of fair value to unproved properties /s/ Ernst & Young LLP We have served as the Company's auditor since 1949. Houston, Texas February 18, 2025 ConocoPhillips 2024 10-K 74 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, 2024, 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, 2024, based on the COSO criteria. As indicated under the heading “Assessment of Internal Control Over Financial Reporting” in the accompanying “Reports of Management”, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Marathon Oil Corporation, which is included in the 2024 consolidated financial statements of the Company and constituted approximately 22% of consolidated total assets as of December 31, 2024, approximately 1% of revenues and other income and less than 1% of net income for the year ended December 31, 2024. Our audit of internal control over financial reporting of ConocoPhillips also did not include an evaluation of the internal control over financial reporting of Marathon Oil Corporation. 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, 2024 and 2023, 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, 2024, and the related notes and our report dated February 18, 2025 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. 75 ConocoPhillips 2024 10-K Table of Contents 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 18, 2025 ConocoPhillips 2024 10-K 76 Financial Statements Table of Contents Consolidated Income Statement ConocoPhillips Years Ended December 31 Millions of Dollars 2024 2023 2022 Revenues and Other Income Sales and other operating revenues $ 54,745 56,141 78,494 Equity in earnings of affiliates 1,705 1,720 2,081 Gain (loss) on dispositions 51 228 1,077 Other income 452 485 504 Total Revenues and Other Income 56,953 58,574 82,156 Costs and Expenses Purchased commodities 20,012 21,975 33,971 Production and operating expenses 8,751 7,693 7,006 Selling, general and administrative expenses 1,158 705 623 Exploration expenses 355 398 564 Depreciation, depletion and amortization 9,599 8,270 7,504 Impairments 80 14 ( 12 ) Taxes other than income taxes 2,087 2,074 3,364 Accretion on discounted liabilities 325 283 250 Interest and debt expense 783 780 805 Foreign currency transaction (gain) loss ( 50 ) 92 ( 100 ) Other expenses 181 2 ( 47 ) Total Costs and Expenses 43,281 42,286 53,928 Income (loss) before income taxes 13,672 16,288 28,228 Income tax provision (benefit) 4,427 5,331 9,548 Net Income (Loss) $ 9,245 10,957 18,680 Net Income (Loss) Per Share of Common Stock (dollars) Basic $ 7.82 9.08 14.62 Diluted 7.81 9.06 14.57 Average Common Shares Outstanding (in thousands) Basic 1,178,920 1,202,757 1,274,028 Diluted 1,180,871 1,205,675 1,278,163 See Notes to Consolidated Financial Statements. 77 ConocoPhillips 2024 10-K Financial Statements Table of Contents Consolidated Statement of Comprehensive Income ConocoPhillips Years Ended December 31 Millions of Dollars 2024 2023 2022 Net Income (Loss) $ 9,245 10,957 18,680 Other comprehensive income (loss) Defined benefit plans Prior service credit (cost) arising during the period ( 57 ) — ( 10 ) Reclassification adjustment for amortization of prior service cost (credit) included in net income (loss) ( 38 ) ( 38 ) ( 39 ) Net change ( 95 ) ( 38 ) ( 49 ) Net actuarial gain (loss) arising during the period 81 37 ( 623 ) Reclassification adjustment for amortization of net actuarial losses (gains) included in net income (loss) 65 82 72 Net change 146 119 ( 551 ) Nonsponsored plans* 1 ( 3 ) 5 Income taxes on defined benefit plans ( 49 ) ( 23 ) 178 Defined benefit plans, net of tax 3 55 ( 417 ) Unrealized holding gain (loss) on securities 3 20 ( 13 ) Reclassification adjustment for (gain) loss included in net income ( 2 ) ( 4 ) ( 1 ) Income taxes on unrealized holding gain (loss) on securities — ( 3 ) 3 Unrealized holding gain (loss) on securities, net of tax 1 13 ( 11 ) Foreign currency translation adjustments ( 760 ) 195 ( 623 ) Income taxes on foreign currency translation adjustments — 2 1 Foreign currency translation adjustments, net of tax ( 760 ) 197 ( 622 ) Unrealized gain (loss) on hedging activities ( 56 ) 78 — Income taxes on unrealized gain (loss) on hedging activities 12 ( 16 ) — Unrealized gain (loss) on hedging activities, net of tax ( 44 ) 62 — Other Comprehensive Income (Loss), Net of Tax ( 800 ) 327 ( 1,050 ) Comprehensive Income (Loss) $ 8,445 11,284 17,630 * Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates. See Notes to Consolidated Financial Statements. ConocoPhillips 2024 10-K 78 Financial Statements Table of Contents Consolidated Balance Sheet ConocoPhillips At December 31 Millions of Dollars 2024 2023 Assets Cash and cash equivalents $ 5,607 5,635 Short-term investments 507 971 Accounts and notes receivable (net of allowance of $ 7 and $ 3 , respectively) 6,621 5,461 Accounts and notes receivable—related parties 74 13 Inventories 1,809 1,398 Prepaid expenses and other current assets 1,029 852 Total Current Assets 15,647 14,330 Investments and long-term receivables 9,869 9,130 Net properties, plants and equipment (net of accumulated DD&A of $ 81,072 and $ 74,361 , respectively) 94,356 70,044 Other assets 2,908 2,420 Total Assets $ 122,780 95,924 Liabilities Accounts payable $ 5,987 5,083 Accounts payable—related parties 57 34 Short-term debt 1,035 1,074 Accrued income and other taxes 2,460 1,811 Employee benefit obligations 1,087 774 Other accruals 1,498 1,229 Total Current Liabilities 12,124 10,005 Long-term debt 23,289 17,863 Asset retirement obligations and accrued environmental costs 8,089 7,220 Deferred income taxes 11,426 8,813 Employee benefit obligations 1,022 1,009 Other liabilities and deferred credits 2,034 1,735 Total Liabilities 57,984 46,645 Equity Common stock ( 2,500,000,000 shares authorized at $ 0.01 par value) Issued (2024— 2,250,672,734 shares; 2023— 2,103,772,516 shares) Par value 23 21 Capital in excess of par 77,529 61,303 Treasury stock (at cost: 2024— 974,806,010 shares; 2023— 925,670,961 shares) ( 71,152 ) ( 65,640 ) Accumulated other comprehensive income (loss) ( 6,473 ) ( 5,673 ) Retained earnings 64,869 59,268 Total Equity 64,796 49,279 Total Liabilities and Equity $ 122,780 95,924 See Notes to Consolidated Financial Statements. 79 ConocoPhillips 2024 10-K Financial Statements Table of Contents Consolidated Statement of Cash Flows ConocoPhillips Years Ended December 31 Millions of Dollars 2024 2023 2022 Cash Flows From Operating Activities Net income (loss) $ 9,245 10,957 18,680 Adjustments to reconcile net income (loss) to net cash provided by operating activities Depreciation, depletion and amortization 9,599 8,270 7,504 Impairments 80 14 ( 12 ) Dry hole costs and leasehold impairments 46 162 340 Accretion on discounted liabilities 325 283 250 Deferred taxes 367 1,145 2,086 Distributions more (less) than income from equity affiliates 564 964 942 (Gain) loss on dispositions ( 51 ) ( 228 ) ( 1,077 ) (Gain) loss on investment in Cenovus Energy — — ( 251 ) Other 130 ( 220 ) 86 Working capital adjustments Decrease (increase) in accounts and notes receivable ( 262 ) 1,333 ( 963 ) Decrease (increase) in inventories ( 68 ) ( 103 ) ( 38 ) Decrease (increase) in prepaid expenses and other current assets 79 337 ( 173 ) Increase (decrease) in accounts payable ( 543 ) ( 1,118 ) 901 Increase (decrease) in taxes and other accruals 613 ( 1,831 ) 39 Net Cash Provided by Operating Activities 20,124 19,965 28,314 Cash Flows From Investing Activities Capital expenditures and investments ( 12,118 ) ( 11,248 ) ( 10,159 ) Working capital changes associated with investing activities 302 30 520 Acquisition of businesses, net of cash acquired ( 24 ) ( 2,724 ) ( 60 ) Proceeds from asset dispositions 261 632 3,471 Net sales (purchases) of investments 415 1,373 ( 2,629 ) Collection of advances/loans—related parties — — 114 Other 14 ( 63 ) 2 Net Cash Used in Investing Activities ( 11,150 ) ( 12,000 ) ( 8,741 ) Cash Flows From Financing Activities Issuance of debt 5,591 3,787 2,897 Repayment of debt ( 4,981 ) ( 1,379 ) ( 6,267 ) Issuance of company common stock ( 78 ) ( 52 ) 362 Repurchase of company common stock ( 5,463 ) ( 5,400 ) ( 9,270 ) Dividends paid ( 3,646 ) ( 5,583 ) ( 5,726 ) Other ( 258 ) ( 34 ) ( 49 ) Net Cash Used in Financing Activities ( 8,835 ) ( 8,661 ) ( 18,053 ) Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash ( 133 ) ( 99 ) ( 224 ) Net Change in Cash, Cash Equivalents and Restricted Cash 6 ( 795 ) 1,296 Cash, cash equivalents and restricted cash at beginning of period 5,899 6,694 5,398 Cash, Cash Equivalents and Restricted Cash at End of Period $ 5,905 5,899 6,694 Restricted cash of $ 298 million and $ 264 million is included in the “ Other assets ” line of our Consolidated Balance Sheet as of December 31, 2024 and December 31, 2023, respectively. See Notes to Consolidated Financial Statements. ConocoPhillips 2024 10-K 80 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, 2021 $ 21 60,581 ( 50,920 ) ( 4,950 ) 40,674 45,406 Net income (loss) 18,680 18,680 Other comprehensive income (loss) ( 1,050 ) ( 1,050 ) Dividends declared Ordinary ($ 1.89 per share of common stock) ( 2,419 ) ( 2,419 ) Variable return of cash ($ 3.10 per share of common stock) ( 3,908 ) ( 3,908 ) Repurchase of company common stock ( 9,270 ) ( 9,270 ) Distributed under benefit plans 561 561 Other 1 2 3 Balances at December 31, 2022 $ 21 61,142 ( 60,189 ) ( 6,000 ) 53,029 48,003 Net income (loss) 10,957 10,957 Other comprehensive income (loss) 327 327 Dividends declared Ordinary ($ 2.11 per share of common stock) ( 2,550 ) ( 2,550 ) Variable return of cash ($ 1.80 per share of common stock) ( 2,170 ) ( 2,170 ) Repurchase of company common stock ( 5,400 ) ( 5,400 ) Excise tax on share repurchases ( 50 ) ( 50 ) Distributed under benefit plans 161 161 Other ( 1 ) 2 1 Balances at December 31, 2023 $ 21 61,303 ( 65,640 ) ( 5,673 ) 59,268 49,279 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 See Notes to Consolidated Financial Statements. 81 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents Notes to Consolidated Financial Statements Note 1—Accounting Policies • Consolidation Principles and Investments —Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries and, if applicable, variable interest entities where we are the primary beneficiary. The equity method is used to account for investments in affiliates in which we have the ability to exert significant influence over the affiliates’ operating and financial policies. When we do not have the ability to exert significant influence, the investment is measured at fair value except when the investment does not have a readily determinable fair value. For those exceptions, it will be measured at cost minus impairment, plus or minus observable price changes in orderly transactions for an identical or similar investment of the same issuer. Undivided interests in oil and gas joint ventures, pipelines, natural gas plants and terminals are consolidated on a proportionate basis. Other securities and investments are generally carried at cost. We manage our operations through six operating segments, defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International. See Note 23 . • 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 2024 10-K 82 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 6 . Development Costs —Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Depletion and Amortization —Leasehold costs of producing properties are depleted using the unit-of-production method based on estimated proved 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. 83 ConocoPhillips 2024 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 and certain pipeline and LNG assets (those which are expected to have a declining utilization pattern), are determined by the unit-of-production method. Depreciation and amortization of all other PP&E are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units). • Impairment of Properties, Plants and Equipment —Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If there is an indication the carrying amount of an asset may not be recovered, a recoverability test is performed using management’s assumptions for prices, volumes and future development plans. If the sum of the undiscounted cash flows before income-taxes is less than the carrying value of the asset group, the carrying value is written down to estimated fair value and reported as an impairment in the period in which the determination is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for E&P assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates and prices believed to be consistent with those used by principal market participants, or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, commodity prices, operating costs and capital decisions, considering all available evidence at the date of review. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. Additionally, when probable and possible reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the impairment calculation. Long-lived assets committed by management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell, with fair value determined using a binding negotiated price, if available, or present value of expected future cash flows as previously described. • Maintenance and Repairs —Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. • Property Dispositions —When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in the “Gain (loss) on dispositions” line of our consolidated income statement. When partial units of depreciable property are sold or retired which do not significantly alter the DD&A rate, the asset cost and accumulated depreciation are eliminated such that no gain or loss is recorded. • Asset Retirement Obligations and Environmental Costs —The fair value of legal obligations to retire and remove long-lived assets are recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). Fair value is estimated using a present value approach, incorporating assumptions about estimated amounts and timing of settlements and impacts of the use of technologies. See Note 7 . 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 2024 10-K 84 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 (EPS) is calculated using the two-class method. Under the two-class method, all earnings (distributed and undistributed) are allocated to common stock (including fully vested stock and unit awards that have not yet been issued as common stock) and participating securities. ConocoPhillips grants 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 15 . 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 exelrcise 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 22 . 85 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents Note 2—Inventories Inventories at December 31 were: Millions of Dollars 2024 2023 Crude oil and natural gas $ 907 676 Materials and supplies 902 722 Total inventories $ 1,809 1,398 Inventories valued on the LIFO basis $ 578 401 The estimated excess of current replacement cost over LIFO cost of inventories was approximately $ 113 million and $ 91 million at December 31, 2024 and 2023, 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. 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. 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 (Millions) $ 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. Fair value measurements were made for acquired assets and liabilities, and adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as we identify new information about facts and circumstances that existed as of the acquisition date to consider. At December 31, 2024, remaining items to finalize include allocation of fair value to unproved properties. The impact of finalizing the fair value allocation is not expected to have a material impact to our consolidated financial statements. ConocoPhillips 2024 10-K 86 Notes to Consolidated Financial Statements Table of Contents 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 969 Inventories 360 Investments and long-term receivables 550 Net properties, plants and equipment 24,178 Other assets 201 Total assets acquired $ 26,643 Liabilities Assumed Accounts payable $ 1,180 Accrued income and other taxes 200 Employee benefit obligations 187 Long-term debt 4,719 Asset retirement obligations 781 Deferred income taxes 2,486 Other liabilities 583 Total liabilities assumed $ 10,136 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 recognized approximately $ 545 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 $ 328 million of employee severance expense. See Note 15 . 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. Assets Held For Sale In December 2024, we entered into an agreement to sell our interests in certain noncore assets in the Lower 48 segment for $ 235 million, before customary adjustments. These assets have a net carrying value of approximately $ 235 million, which consists primarily of $ 251 million of PP&E and $ 16 million of liabilities, primarily noncurrent AROs. These assets met held for sale criteria in the fourth quarter of 2024, and as of December 31, 2024, we reclassified the PP&E to “Prepaid expenses and other current assets” and the noncurrent liabilities to “Other accruals” on our consolidated balance sheet. This transaction is anticipated to close in the first quarter of 2025. 87 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents Planned Dispositions In January 2025, we entered into an agreement to sell our interests in certain noncore assets in the Lower 48 segment for approximately $ 400 million, before customary adjustments. This transaction is expected to close in the first half of 2025. 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 The contingent consideration arrangement requires additional consideration to be paid to TotalEnergies EP Canada Ltd. up to $ 0.4 billion CAD over a five-year term. The contingent payments represent $ 2 million for every dollar that WCS pricing exceeds $ 52 per barrel during the month, subject to certain production targets being achieved. The undiscounted amounts we could pay under this arrangement was up to $ 0.3 billion USD at closing. The fair value of the contingent consideration on the acquisition date was $ 320 million and estimated by applying the income approach. For the year ended December 31, 2024, we have made payments of $ 158 million USD under this arrangement, reflected in the "Other" line within the Financing Activities section of our Consolidated Statement of Cash Flows. See Note 12 . 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 2024 10-K 88 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, 2023, and 2022, 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 Millions of Dollars Year Ended December 31, 2022 As reported Pro forma Surmont Pro forma Combined Total Revenues and Other Income $ 82,156 3,582 85,738 Net Income (Loss) 18,680 720 19,400 Earnings per share: Basic net income (loss) $ 14.62 15.18 Diluted net income (loss) 14.57 15.13 The unaudited supplemental pro forma financial information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the transaction 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. 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. 89 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents Port Arthur Liquefaction Holdings, LLC (PALNG) During 2023, we acquired a 30 percent interest in PALNG, a joint venture for the development of a large-scale LNG facility for the first phase of the Port Arthur LNG project ("Phase 1"). Sempra PALNG Holdings, LLC owns the remaining 70 percent interest in the joint venture. PALNG is reported as an equity method investment in our Corporate and Other segment. See Note 4. Contingent Payments We recorded contingent payments related to the previous dispositions of our working interests in the Foster Creek Christina Lake Partnership and western Canada gas assets, and our San Juan assets. Contingent payments were recorded as (gain) loss on disposition on our consolidated income statement and reflected within our Canada and Lower 48 segments. In our Canada segment, the contingent payment, calculated and paid quarterly, was $ 6 million CAD for every $1 CAD by which the WCS quarterly average crude oil price exceeded $ 52 CAD per barrel. In our Lower 48 segment, the contingent payment, paid annually, was calculated monthly at $ 7 million per month when the U.S. Henry Hub natural gas price was at or above $ 3.20 per MMBTU. The term of contingent payments in our Canada segment ended in the second quarter of 2022 and the term of contingent payments in our Lower 48 segment ended at the end of 2023. Contingent payments recorded in the years 2023 and 2022 were $ 7 million and $ 451 million, respectively. 2022 Acquisition of Additional Shareholding Interest in Australia Pacific LNG (APLNG) In February 2022, we completed the acquisition of an additional 10 percent interest in APLNG from Origin Energy for approximately $ 1.4 billion, after customary adjustments, in an all-cash transaction resulting from the exercise of our preemption right. This increased our ownership in APLNG to 47.5 percent, with Origin Energy and Sinopec owning 27.5 percent and 25.0 percent, respectively. APLNG is reported as an equity investment in our Asia Pacific segment. QatarEnergy LNG NFE(4) (NFE4) During 2022, we were awarded a 25 percent interest in NFE4, a new joint venture with QatarEnergy to participate in the North Field East (NFE) LNG project. NFE4 has a 12.5 percent interest in the NFE project and is reported as an equity method investment in our Europe, Middle East and North Africa segment. See Note 4 . Asset Acquisition In September 2022, we completed the acquisition of an additional working interest in certain Eagle Ford acreage in the Lower 48 segment for cash consideration of $ 236 million after customary adjustments. This agreement was accounted for as an asset acquisition, with the consideration allocated primarily to PP&E. Assets Sold During 2022, we sold our interests in certain noncore assets in our Lower 48 segment for net proceeds of $ 680 million, with no gain or loss recognized on sale. At the time of disposition, our interest in these assets had a net carrying value of $ 680 million, consisting of $ 825 million of assets, primarily related to $ 818 million of PP&E, and $ 145 million of liabilities, primarily related to AROs. In March 2022, we completed the divestiture of our subsidiaries that held our Indonesia assets and operations, and based on an effective date of January 1, 2021, we received net proceeds of $ 731 million after customary adjustments and recognized a $ 534 million before-tax and $ 462 million after-tax gain related to this transaction. Together, the subsidiaries sold indirectly held our 54 percent interest in the Indonesia Corridor Block PSC and 35 percent shareholding in the Transasia Pipeline Company. At the time of the disposition, the net carrying value was approximately $ 0.2 billion, excluding $ 0.2 billion of cash and restricted cash. The net book value consisted primarily of $ 0.3 billion of PP&E and $ 0.1 billion of ARO. The before-tax earnings associated with the subsidiaries sold, excluding the gain on disposition noted above, was $ 138 million for the year ended December 31, 2022. Results of operations for the Indonesia interests sold were reported in our Asia Pacific segment. ConocoPhillips 2024 10-K 90 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 2024 2023 Equity investments $ 8,611 7,905 Long-term receivables 113 143 Long-term investments in debt securities 1,055 989 Other investments 90 93 $ 9,869 9,130 Equity Investments Affiliated companies in which we had a significant equity investment at December 31, 2024, 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 . • N3— 30 percent owned joint venture with an affiliate 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. • 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 (NFE) LNG project. See Note 3 . • 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 2024 2023 2022 Revenues $ 15,286 15,314 18,356 Income (loss) before income taxes 6,446 6,301 8,234 Net income (loss) 4,389 4,214 5,507 Summarized 100 percent balance sheet information for equity method investments in affiliated companies, combined, was as follows: Millions of Dollars 2024 2023 Current assets $ 4,608 3,827 Noncurrent assets 41,417 39,299 Current liabilities 3,829 3,462 Noncurrent liabilities 16,947 16,665 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, 2024, retained earnings included $ 96 million related to the undistributed earnings of affiliated companies. Dividends received from affiliates were $ 2,283 million, $ 2,684 million and $ 3,045 million in 2024, 2023 and 2022, respectively. 91 ConocoPhillips 2024 10-K 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, 2024, a balance of $ 4.0 billion was outstanding on the facilities. See Note 9 . At December 31, 2024, the carrying value of our equity method investment in APLNG was approximately $ 5.0 billion. PALNG PALNG is a joint venture for the development of a large-scale LNG facility. At December 31, 2024, the carrying value of our equity method investment in PALNG was approximately $ 1.5 billion. See Note 3 . N3 N3 is a joint venture that owns an integrated large-scale LNG project located in Qatar. We have terminal and pipeline use agreements with Golden Pass LNG Terminal and affiliated Golden Pass Pipeline near Sabine Pass, Texas, intended to provide us with terminal and pipeline capacity for the receipt, storage and regasification of LNG purchased from N3. Currently, the LNG from N3 is being sold to markets outside of the U.S. NFE4 NFE4 is a joint venture participating in the NFE LNG project. NFE4 has a 12.5 percent interest in the NFE project. See Note 3 . During the second quarter of 2024, we were notified that an affiliate of QatarEnergy transferred a 5 percent joint venture interest in NFE4 to an affiliate of China National Petroleum Corporation. As a result, 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, 2024, 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 9 . 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, 2024, the carrying value of our equity method investments in Qatar was approximately $ 1.4 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, 2024, there were no outstanding loans to affiliated companies. ConocoPhillips 2024 10-K 92 Notes to Consolidated Financial Statements Table of Contents Note 5—Investment in Cenovus Energy In 2022, we sold our remaining 91 million shares of Cenovus Energy (CVE), recognizing proceeds of $ 1.4 billion and a net gain of $ 251 million. All gains and losses were recognized within "Other income" on our consolidated income statement. Proceeds related to the sale of our CVE shares were included within "Cash Flows From Investing Activities" on our consolidated statement of cash flows. Note 6—Suspended Wells and Exploration Expenses The following table reflects the net changes in suspended exploratory well costs during 2024, 2023 and 2022: Millions of Dollars 2024 2023 2022 Beginning balance $ 184 527 660 Additions pending the determination of proved reserves 32 — 5 Reclassifications to proved properties ( 2 ) ( 285 ) ( 7 ) Charged to dry hole expense ( 18 ) ( 58 ) ( 131 ) Ending balance $ 196 184 527 The following table provides an aging of suspended well balances at December 31: Millions of Dollars 2024 2023 2022 Exploratory well costs capitalized for a period of one year or less $ 33 — 15 Exploratory well costs capitalized for a period greater than one year 163 184 512 Ending balance $ 196 184 527 Number of projects with exploratory well costs capitalized for a period greater than one year 13 14 17 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, 2024: Millions of Dollars Suspended Since Total 2021-2023 2018-2020 2017 and Prior WL4-00—Malaysia (1) 36 12 24 — West Willow—Alaska (2) 30 — 30 — PL891—Norway (2) 28 — 28 — Narwhal Trend—Alaska (1) 25 — 25 — Montney—Canada (2) 14 7 7 — Other of $10 million or less each (1)(2) 30 — — 30 Total $ 163 19 114 30 (1) Appraisal drilling complete; costs being incurred to assess development. (2) Additional appraisal wells planned. 93 ConocoPhillips 2024 10-K 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. 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. 2022 In the fourth quarter, we recorded a before-tax expense of $ 129 million for impairment of certain aged, suspended wells associated with Surmont in our Canada segment. In our Europe, Middle East and North Africa segment, we recorded a before-tax expense of $ 102 million for dry hole costs associated with four operated exploration and appraisal wells and one partner-operated well that were drilled in Norway in 2022. ConocoPhillips 2024 10-K 94 Notes to Consolidated Financial Statements Table of Contents Note 7—Asset Retirement Obligations and Accrued Environmental Costs Asset retirement obligations and accrued environmental costs at December 31 were: Millions of Dollars 2024 2023 Asset retirement obligations $ 8,215 7,227 Accrued environmental costs 206 184 Total asset retirement obligations and accrued environmental costs 8,421 7,411 Asset retirement obligations and accrued environmental costs due within one year* ( 332 ) ( 191 ) Long-term asset retirement obligations and accrued environmental costs $ 8,089 7,220 *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 2024 and 2023, our overall ARO changed as follows: Millions of Dollars 2024 2023 Balance at January 1 $ 7,227 6,380 Accretion of discount 319 278 New obligations, including acquisitions 926 257 Changes in estimates of existing obligations 140 484 Spending on existing obligations ( 182 ) ( 119 ) Property dispositions ( 6 ) ( 27 ) Foreign currency translation ( 209 ) ( 26 ) Balance at December 31 $ 8,215 7,227 Accrued Environmental Costs Total accrued environmental costs at December 31, 2024 and 2023, were $ 206 million and $ 184 million, respectively. We had accrued environmental costs of $ 139 million and $ 112 million at December 31, 2024 and 2023, respectively, related to remediation activities in the U.S. and Canada. We had also accrued in Corporate and Other $ 56 million and $ 55 million of environmental costs associated with sites no longer in operation at December 31, 2024 and 2023, respectively. In addition, December 31, 2024 and 2023, included a $ 11 million and $ 17 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 $ 112 million at December 31, 2024. The total expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are $ 158 million. 95 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents Note 8—Debt Long-term debt at December 31 was: Millions of Dollars 2024 2023 2.125 % Notes due 2024 — 461 3.35 % Notes due 2024 — 265 2.4 % Notes due 2025 366 366 8.2 % Debentures due 2025 134 134 3.35 % Notes due 2025 199 199 6.875 % Debentures due 2026 67 67 7.8 % Debentures due 2027 120 203 4.4 % Notes due 2027 424 — 3.75 % Notes due 2027 196 196 4.3 % Notes due 2028 223 223 7.375 % Debentures due 2029 66 92 7.0 % Debentures due 2029 95 112 5.3 % Notes due 2029 86 — 6.95 % Notes due 2029 705 1,195 4.7 % Notes due 2030 1,350 — 8.125 % Notes due 2030 207 390 2.4 % Notes due 2031 227 227 7.2 % Notes due 2031 447 447 7.25 % Notes due 2031 268 400 7.4 % Notes due 2031 232 382 4.85 % Notes due 2032 650 — 6.8 % Notes due 2032 180 — 5.9 % Notes due 2032 505 505 5.05 % Notes due 2033 1,000 1,000 5.70 % Notes due 2034 103 — 4.15 % Notes due 2034 246 246 5.00 % Notes due 2035 1,250 — 5.95 % Notes due 2036 326 326 5.951 % Notes serially maturing 2022 through 2037 573 603 6.6 % Notes due 2037 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 5.20 % Notes due 2045 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 5.500 % Notes due 2055 1,300 — 4.025 % Notes due 2062 1,770 1,770 5.70 % Notes due 2063 700 700 5.65 % Notes due 2065 650 — ConocoPhillips 2024 10-K 96 Notes to Consolidated Financial Statements Table of Contents Marine Terminal Revenue Refunding Bonds due 2031 at 1.78 % – 4.80 % during 2024 and 1.65 % – 4.70 % during 2023 265 265 Industrial Development Bonds due 2035 at 1.78 % – 4.22 % during 2024 and 1.85 % – 4.70 % during 2023 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 — Other 16 21 Debt at face value 24,085 18,413 Finance leases 940 1,129 Net unamortized premiums, discounts and debt issuance costs ( 701 ) ( 605 ) Total debt 24,324 18,937 Short-term debt ( 1,035 ) ( 1,074 ) Long-term debt $ 23,289 17,863 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 2025 through 2029 are: $ 735 million, $ 704 million, $ 778 million, $ 664 million and $ 997 million, respectively. 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 In November 2024, we completed the acquisition of Marathon Oil. 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 97 ConocoPhillips 2024 10-K 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. ConocoPhillips 2024 10-K 98 Notes to Consolidated Financial Statements Table of Contents 2023 In December 2023, the company retired $ 78 million principal amount of our 7.65 percent Notes at maturity. In the third quarter of 2023, we issued $ 2.7 billion in new Notes through our universal shelf registration statement and prospectus supplement. The net proceeds were used to fund the acquisition of the remaining 50 percent working interest in Surmont which closed in October 2023. See Note 3 . The following Notes were issued: • 5.05 % Notes due 2033 with principal of $ 1.0 billion • 5.55 % Notes due 2054 with principal of $ 1.0 billion • 5.70 % Notes due 2063 with principal of $ 0.7 billion In the second quarter of 2023, as described further below, we initiated and completed two concurrent transactions as part of our debt refinancing strategy. We issued $ 1.1 billion in new Notes through our universal shelf registration statement and prospectus supplement and used the proceeds to repurchase $ 1.1 billion of existing debt. Debt Issuance On May 23, 2023, we issued 5.3 % Notes due 2053 with principal of $ 1.1 billion. Repurchase Tender Offers On May 25, 2023, we repurchased a total of $ 1,133 million aggregate principal amount of debt as listed below. We paid $ 33 million below face value to repurchase these debt instruments and recognized a gain on debt extinguishment of $ 27 million, which is included in the "Other expenses" line on our consolidated income statement. • 2.125 % Notes due 2024 with principal of $ 900 million (partial repurchase of $ 439 million) • 3.350 % Notes due 2024 with principal of $ 426 million (partial repurchase of $ 160 million) • 2.400 % Notes due 2025 with principal of $ 900 million (partial repurchase of $ 534 million) Revolving Credit Facility and Credit Rating Information We have a revolving credit facility totaling $ 5.5 billion with an expiration date of February 2027. Our revolving credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $ 500 million, or as support for our commercial paper program. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $ 200 million or more by ConocoPhillips, or any of its consolidated subsidiaries. The amount of the facility is not subject to redetermination prior to its expiration date. Credit facility borrowings may bear interest at a margin above the Secured Overnight Financing Rate (SOFR). The facility agreement calls for commitment fees on available, but unused, amounts. The facility agreement also contains early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors. The revolving credit facility supports our ability to issue up to $ 5.5 billion of commercial paper. Commercial paper is generally limited to maturities of 90 days and is included in short-term debt on our consolidated balance sheet. With no commercial paper outstanding and no direct borrowings or letters of credit, we had access to $ 5.5 billion in available borrowing capacity under our revolving credit facility at December 31, 2024 and December 31, 2023. For information on Finance Leases, see Note 14 . 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. 99 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents At both December 31, 2024 and 2023, 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. Note 9—Guarantees At December 31, 2024, 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, 2024, we had outstanding multiple guarantees in connection with our 47.5 percent ownership interest in APLNG. The following is a description of the guarantees with values calculated utilizing December 2024 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 six 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, 2024, 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 $ 610 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 12 to 21 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $ 480 million and would become payable if APLNG does not perform. At December 31, 2024, the carrying value of these guarantees was approximately $ 34 million. QatarEnergy LNG Limited Guarantee We have guaranteed our portion of certain fiscal and other joint venture obligations as a shareholder in NFE4 and NFS3. This guarantee has an approximate 30 -year term with no maximum limit. At December 31, 2024, the carrying value of this guarantee 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 three years remaining, and the maximum potential future payments related to these guarantees is approximately $ 116 million. At December 31, 2024, the carrying value of these guarantees was approximately $ 4 million. ConocoPhillips 2024 10-K 100 Notes to Consolidated Financial Statements Table of Contents Other Guarantees We have other guarantees with maximum future potential payment amounts totaling approximately $ 570 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, 2024, there was no carrying value associated with these guarantees. Indemnifications Over the years, we have entered into agreements to sell ownership interests in certain legal entities, joint ventures and assets that gave rise to qualifying indemnifications. These agreements include indemnifications for taxes and environmental liabilities. The carrying amount recorded for these indemnifications at December 31, 2024, was approximately $ 20 million. Those related to environmental issues have terms that are generally indefinite and the maximum amounts of future payments are generally unlimited. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. See Note 10 for additional information about environmental liabilities. Note 10—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 16 , 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. 101 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents 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 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 7 for a summary of our accrued environmental liabilities. 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, 2024, we had performance obligations secured by letters of credit of $ 278 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 PDVSA and three of its affiliates, including an award for approximately $ 2 billion plus interest, for the Hamaca and Petrozuata projects, and a $ 33 million award, for the Corocoro project, plus interest. As of December 31, 2024, the company has received approximately $ 787 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. ConocoPhillips 2024 10-K 102 Notes to Consolidated Financial Statements Table of Contents Beginning in 2017, governmental and other entities in several states/territories in the U.S. have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged climate change impacts. Additional lawsuits with similar allegations are expected to be filed. The 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. On October 17, 2022, the Fifth Circuit affirmed remand of the lead case to state court and the subsequent request for rehearing was denied. Accordingly, the federal district courts have issued remands to state court. Because Plaintiffs’ SLCRMA theories are unprecedented, there is uncertainty about these claims (both as to scope and damages) and we continue to evaluate our exposure in these lawsuits. In October 2020, the Bureau of Safety and Environmental Enforcement (BSEE) ordered the prior owners of Outer Continental Shelf (OCS) Lease P-0166, including ConocoPhillips, to decommission the lease facilities, including two offshore platforms located near Carpinteria, California. This order was sent after the current owner of OCS Lease P-0166 relinquished the lease and abandoned the lease platforms and facilities. BSEE’s order to ConocoPhillips is premised on its connection to Phillips Petroleum Company, a legacy company of ConocoPhillips, which held a historical 25 percent interest in this lease and operated these facilities but sold its interest over 30 years ago. ConocoPhillips continues to evaluate its exposure in this matter. In July 2021, a federal securities class action was filed against Concho, certain of Concho’s officers, and ConocoPhillips as Concho’s successor in the United States District Court for the Southern District of Texas. On October 21, 2021, the court issued an order appointing Utah Retirement Systems and the Construction Laborers Pension Trust for Southern California as lead plaintiffs (Lead Plaintiffs). On January 7, 2022, the Lead Plaintiffs filed their consolidated complaint alleging that Concho made materially false and misleading statements regarding its business and operations in violation of the federal securities laws and seeking unspecified damages, attorneys’ fees, costs, equitable/injunctive relief and such other relief that may be deemed appropriate. The defendants filed a motion to dismiss the consolidated complaint on March 8, 2022. On June 23, 2023, the court denied defendants’ motion as to most defendants including Concho/ConocoPhillips. We believe the allegations in the action are without merit and are vigorously defending this litigation. ConocoPhillips is involved in pending disputes with commercial counterparties relating to the propriety of its force majeure notices following Winter Storm Uri in 2021. We believe these claims are without merit and are vigorously defending them. Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements We have certain throughput agreements and take-or-pay agreements in support of financing arrangements. The agreements typically provide for natural gas or crude oil transportation and LNG purchase commitments. The fixed and determinable portion of the remaining estimated payments under these various agreements as of December 31, 2024 are: 2025—$ 6 million; 2026—$ 6 million; 2027—$ 6 million; 2028—$ 397 million; 2029—$ 558 million; and 2030 and after—$ 10.3 billion. Generally, variable components of these obligations include commodity futures prices and inflation rates. Purchases of LNG under these commitments are expected to be offset in the same or approximately same periods by cash received from the related sales transactions. Total payments under these agreements were $ 24 million in 2024, $ 26 million in 2023 and $ 26 million in 2022. 103 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents Note 11—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 2024 2023 Assets Prepaid expenses and other current assets $ 394 611 Other assets 94 113 Liabilities Other accruals 397 567 Other liabilities and deferred credits 83 80 The gains (losses) from commodity derivatives included in our consolidated income statement are presented in the following table: Millions of Dollars 2024 2023 2022 Sales and other operating revenues $ 133 86 ( 88 ) Other income ( 4 ) ( 6 ) ( 5 ) Purchased commodities ( 133 ) ( 90 ) ( 91 ) The table below summarizes our net exposures resulting from outstanding commodity derivative contracts: Open Position Long/(Short) 2024 2023 Commodity Natural gas and power (BCF equivalent) Fixed price ( 17 ) ( 12 ) Basis — ( 2 ) ConocoPhillips 2024 10-K 104 Notes to Consolidated Financial Statements Table of Contents 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. These swaps were designated and qualified for hedge accounting under ASC Topic 815, “Derivatives and Hedging,” as a cash flow hedge with changes in the fair value of the designated hedging instruments reported as a component of other comprehensive income and to be reclassified into earnings in the same periods that the hedged transactions will affect earnings. In 2024, PALNG de-designated a portion of the interest rate swaps as a cash flow hedge. Changes in the fair value of the de-designated hedging instruments are reported in the "Equity in earnings of affiliates" line on our consolidated income statement. For the years ended December 31, 2024, and 2023, we recognized an unrealized loss of $ 56 million and an unrealized gain of $ 78 million in other comprehensive income, respectively, related to the hedge accounted swaps. For the year ended December 31, 2024, we recognized $ 35 million in "Equity in earnings of affiliates" related to the de-designated swaps. Financial Instruments We invest in financial instruments with maturities based on our cash forecasts for the various accounts and currency pools we manage. The types of financial instruments in which we currently invest include: • Time deposits: Interest bearing deposits placed with financial institutions for a predetermined amount of time. • Demand deposits: Interest bearing deposits placed with financial institutions. Deposited funds can be withdrawn without notice. • Commercial paper: Unsecured promissory notes issued by a corporation, commercial bank or government agency purchased at a discount to mature at par. • U.S. government or government agency obligations: Securities issued by the U.S. government or U.S. government agencies. • Foreign government obligations: Securities issued by foreign governments. • Corporate bonds: Unsecured debt securities issued by corporations. • Asset-backed securities: Collateralized debt securities. The following investments are carried on our consolidated balance sheet at cost, plus accrued interest and the table reflects remaining maturities at December 31, 2024 and 2023: Millions of Dollars Carrying Amount Cash and Cash Equivalents Short-Term Investments 2024 2023 2024 2023 Cash $ 770 474 Demand Deposits 3,211 1,424 Time Deposits 1 to 90 days 1,364 3,713 1 511 91 to 180 days 5 22 Within one year 6 3 U.S. Government Obligations 1 to 90 days 260 24 — — $ 5,605 5,635 12 536 105 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents The following investments in debt securities classified as available for sale are carried at fair value on our consolidated balance sheet at December 31, 2024 and 2023: Millions of Dollars Carrying Amount Cash and Cash Equivalents Short-Term Investments Investments and Long-Term Receivables 2024 2023 2024 2023 2024 2023 Major Security Type Corporate Bonds $ — — 338 201 612 606 Commercial Paper 2 — 77 131 U.S. Government Obligations — — 43 89 218 189 U.S. Government Agency Obligations — 5 7 7 Foreign Government Obligations 4 7 12 4 Asset-backed Securities 33 2 205 183 $ 2 — 495 435 1,054 989 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 four years. The following table summarizes the amortized cost basis and fair value of investments in debt securities classified as available for sale at December 31: Millions of Dollars Amortized Cost Basis Fair Value 2024 2023 2024 2023 Major Security Type Corporate Bonds $ 947 806 950 807 Commercial Paper 79 131 79 131 U.S. Government Obligations 262 278 261 278 U.S. Government Agency Obligations 7 12 7 12 Foreign Government Obligations 16 11 16 11 Asset-backed Securities 237 184 238 185 $ 1,548 1,422 1,551 1,424 As of December 31, 2024, total unrealized gains for debt securities classified as available for sale with net gains were $ 5 million and total unrealized losses for debt securities classified as available for sale with net losses were $ 1 million. As of December 31, 2023, total unrealized gains for debt securities classified as available for sale with net unrealized gains were $ 5 million. No allowance for credit losses has been recorded on investments in debt securities which are in an unrealized loss position. For the years ended December 31, 2024 and 2023, proceeds from sales and redemptions of investments in debt securities classified as available for sale were $ 868 million and $ 983 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. ConocoPhillips 2024 10-K 106 Notes to Consolidated Financial Statements Table of Contents Credit Risk Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, short-term investments, long-term investments in debt securities, OTC derivative contracts and trade receivables. Our cash equivalents and short-term investments are placed in high-quality commercial paper, government money market funds, U.S. government and government agency obligations, time deposits with major international banks and financial institutions, high-quality corporate bonds, foreign government obligations and asset-backed securities. Our long-term investments in debt securities are placed in high-quality corporate bonds, asset-backed securities, U.S. government and government agency obligations, foreign government obligations, and time deposits with major international banks and financial institutions. The credit risk from our OTC derivative contracts, such as forwards, swaps and options, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because these trades are cleared primarily with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements. Our trade receivables result primarily from our petroleum operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less, and we continually monitor this exposure and the creditworthiness of the counterparties. We may require collateral to limit the exposure to loss, including letters of credit, prepayments and surety bonds, as well as master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due to us. Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of credit as collateral, such as transactions administered through the New York Mercantile Exchange. The aggregate fair value of all derivative instruments with such credit risk-related contingent features that were in a liability position at December 31, 2024 and December 31, 2023, was $ 70 million and $ 181 million, respectively. For these instruments, no collateral was posted at December 31, 2024 and December 31, 2023. If our credit rating had been downgraded below investment grade at December 31, 2024, we would have been required to post $ 49 million of additional collateral, either with cash or letters of credit. 107 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents Note 12—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 2024 or 2023. 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 to Total Energies EP Canada Ltd. in connection with the acquisition of the remaining 50 percent working interest in Surmont. Contingent consideration consists of payments up to approximately $ 0.4 billion CAD over a five-year term ending in the fourth quarter of 2028. The contingent payments represent $ 2.0 million for every dollar that the monthly WCS average pricing exceeds $ 52 per barrel. The terms include adjustments related to not achieving certain production targets. The fair value of the contingent consideration as of December 31, 2024 is calculated using the income approach and is largely based on the estimated commodity price outlook using a combination of external pricing service companies' and our internal price outlook (unobservable input) and a discount rate consistent with those used by principal market participants (observable input). Impact of other unobservable inputs on the fair value as of December 31, 2024 was not significant. The following table summarizes the fair value hierarchy for gross financial assets and liabilities (i.e., unadjusted where the right of setoff exists for commodity derivatives accounted for at fair value on a recurring basis): Millions of Dollars December 31, 2024 December 31, 2023 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Investments in debt securities $ 261 1,290 — 1,551 278 1,146 — 1,424 Commodity derivatives 201 252 35 488 308 301 115 724 Total assets $ 462 1,542 35 2,039 586 1,447 115 2,148 Liabilities Commodity derivatives $ 275 160 45 480 350 283 14 647 Contingent consideration — — 145 145 — — 312 312 Total liabilities $ 275 160 190 625 350 283 326 959 ConocoPhillips 2024 10-K 108 Notes to Consolidated Financial Statements Table of Contents 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, 2024 $ 145 Discounted cash flow Commodity price outlook* ($/BOE) $ 48.63 - $ 57.53 ($ 53.38 ) December 31, 2023 312 $ 45.48 - $ 63.04 ($ 57.45 ) *Commodity price outlook based on a combination of external pricing service companies' outlooks and our internal outlook. The following table summarizes those commodity derivative balances subject to the right of setoff as presented on our consolidated balance sheet. We have elected to offset the recognized fair value amounts for multiple derivative instruments executed with the same counterparty in our financial statements when a legal right of setoff exists. Millions of Dollars Amounts Subject to Right of Setoff Gross Amounts Recognized Amounts Not Subject to Right of Setoff Gross Amounts Gross Amounts Offset Net Amounts Presented Cash Collateral Net Amounts December 31, 2024 Assets $ 488 — 488 278 210 — 210 Liabilities 480 — 480 278 202 73 129 December 31, 2023 Assets $ 724 39 685 375 310 4 306 Liabilities 647 34 613 375 238 47 191 At December 31, 2024 and December 31, 2023, 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 11 . • 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. 109 ConocoPhillips 2024 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 2024 2023 2024 2023 Financial assets Commodity derivatives 210 345 210 345 Investments in debt securities 1,551 1,424 1,551 1,424 Financial liabilities Total debt, excluding finance leases 23,384 17,808 22,997 18,621 Commodity derivatives 129 225 129 225 Note 13—Equity Common Stock The changes in our shares of common stock, as categorized in the equity section of the balance sheet, were: Shares 2024 2023 2022 Issued Beginning of year 2,103,772,516 2,100,885,134 2,091,562,747 Acquisition of Marathon Oil 142,941,624 — — Distributed under benefit plans 3,958,594 2,887,382 9,322,387 End of year 2,250,672,734 2,103,772,516 2,100,885,134 Held in Treasury Beginning of year 925,670,961 877,029,062 789,319,875 Repurchase of common stock 49,135,049 48,641,899 87,709,187 End of year 974,806,010 925,670,961 877,029,062 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, 2024 or 2023. 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 433 million shares at a cost of $ 34.3 billion through the end of December 2024. In 2021, we began a paced monetization of our CVE common shares, the proceeds of which have been applied to share repurchases. In 2022, we sold our remaining 91 million CVE common shares. ConocoPhillips 2024 10-K 110 Notes to Consolidated Financial Statements Table of Contents Note 14—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 9 . There are no significant restrictions imposed on us by the lease agreements with regard to dividends, asset dispositions or borrowing ability. We determine if an arrangement is or contains a lease at contract inception. Certain contractual arrangements may contain both lease and non-lease components. Only the lease components of these contractual arrangements are subject to the provisions of ASC Topic 842, and any non-lease components are subject to other applicable accounting guidance; however, we have elected to adopt the optional practical expedient not to separate lease components apart from non-lease components for existing asset classes, 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 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. 111 ConocoPhillips 2024 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 2024 2023 Operating Leases Finance Leases Operating Leases Finance Leases Right-of-Use Assets Properties, plants and equipment Gross 1,983 2,010 Accumulated DD&A ( 1,336 ) ( 1,185 ) Net PP&E* 647 825 Other assets 1,017 691 Lease Liabilities Short-term debt** 292 291 Other accruals 329 193 Long-term debt*** 648 838 Other liabilities and deferred credits 695 504 Total lease liabilities $ 1,024 940 697 1,129 * Includes proportionately consolidated finance lease assets of $ 107 million at December 31, 2024 and $ 134 million at December 31, 2023. ** Includes proportionately consolidated finance lease liabilities of $ 181 million at December 31, 2024 and $ 175 million at December 31, 2023. *** Includes proportionately consolidated finance lease liabilities of $ 259 million at December 31, 2024 and $ 326 million at December 31, 2023. The following table summarizes our lease costs: Millions of Dollars 2024 2023 2022 Lease Cost* Operating lease cost $ 325 229 212 Finance lease cost Amortization of right-of-use assets 173 180 189 Interest on lease liabilities 29 35 32 Short-term lease cost** 49 40 94 Total lease cost*** $ 576 484 527 * 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 2024 2023 Weighted-average term (years) Operating leases 4.41 5.83 Finance leases 4.86 5.73 Weighted-average discount rate (percent) Operating leases 4.62 4.13 Finance leases 3.40 3.39 ConocoPhillips 2024 10-K 112 Notes to Consolidated Financial Statements Table of Contents The following table summarizes other lease information: Millions of Dollars 2024 2023 2022 Other Information* Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 248 173 148 Operating cash flows from finance leases 29 33 30 Financing cash flows from finance leases 172 169 166 Right-of-use assets obtained in exchange for operating lease liabilities $ 628 355 114 Right-of-use assets obtained in exchange for finance lease liabilities — 9 256 *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, 2024: Millions of Dollars Operating Leases Finance Leases Maturity of Lease Liabilities 2025 $ 382 354 2026 292 200 2027 160 159 2028 96 177 2029 55 88 Remaining years 121 84 Total 1,106 1,062 Less: portion representing imputed interest ( 82 ) ( 122 ) Total lease liabilities $ 1,024 $ 940 113 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents Note 15—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 2024 2023 2024 2023 U.S. Int’l. U.S. Int’l. Change in Benefit Obligation Benefit obligation at January 1 $ 1,525 2,866 1,478 2,776 107 102 Service cost 49 38 51 38 1 1 Interest cost 76 114 77 113 5 5 Plan participant contributions — — — — 12 14 Plan amendments — 57 — — — — Business combinations 237 42 Actuarial (gain) loss ( 4 ) ( 202 ) 40 11 5 22 Benefits paid ( 98 ) ( 134 ) ( 121 ) ( 124 ) ( 27 ) ( 37 ) Curtailment 8 — — — — — Recognition of termination benefits 13 — — — — — Foreign currency exchange rate change — ( 148 ) — 52 — — Benefit obligation at December 31* $ 1,806 2,591 1,525 2,866 145 107 *Accumulated benefit obligation portion of above at December 31: $ 1,703 2,392 1,414 2,642 Change in Fair Value of Plan Assets Fair value of plan assets at January 1 $ 1,306 3,085 1,179 2,879 — — Actual return on plan assets 66 18 129 199 — — Company contributions 83 88 119 58 15 23 Plan participant contributions — — — — 12 14 Business combinations 199 Benefits paid ( 98 ) ( 134 ) ( 121 ) ( 124 ) ( 27 ) ( 37 ) Foreign currency exchange rate change — ( 150 ) — 73 — — Fair value of plan assets at December 31 $ 1,556 2,907 1,306 3,085 — — Funded Status $ ( 250 ) 316 ( 219 ) 219 ( 145 ) ( 107 ) ConocoPhillips 2024 10-K 114 Notes to Consolidated Financial Statements Table of Contents Millions of Dollars Pension Benefits Other Benefits 2024 2023 2024 2023 U.S. Int’l. U.S. Int’l. Amounts Recognized in the Consolidated Balance Sheet at December 31 Noncurrent assets $ 1 553 — 491 — — Current liabilities ( 28 ) ( 10 ) ( 16 ) ( 9 ) ( 26 ) ( 24 ) Noncurrent liabilities ( 223 ) ( 227 ) ( 203 ) ( 263 ) ( 119 ) ( 83 ) Total recognized $ ( 250 ) 316 ( 219 ) 219 ( 145 ) ( 107 ) Weighted-Average Assumptions Used to Determine Benefit Obligations at December 31 Discount rate 5.70 % 4.90 5.35 4.10 5.60 5.30 Rate of compensation increase 5.00 4.05 5.00 3.65 Interest crediting rate for applicable benefits 4.30 4.20 Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Discount rate 5.35 % 4.10 5.65 4.20 5.35 5.65 Expected return on plan assets 5.30 5.40 5.30 5.20 Rate of compensation increase 5.00 3.65 5.00 3.65 Interest crediting rate for applicable benefits 4.20 3.55 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 2024, the actuarial gains related to the benefit obligations for international plans were primarily related to an increase in the discount rates. During 2023, the actuarial losses related to the benefit obligations for U.S. and international plans were primarily related to a decrease in the discount rates. 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 2024 2023 U.S. Int’l. U.S. Int’l. Pension Plans with Projected Benefit Obligation in Excess of Plan Assets Projected benefit obligation $ 450 242 1,525 279 Fair value of plan assets 199 6 1,306 6 Pension Plans with Accumulated Benefit Obligation in Excess of Plan Assets Accumulated benefit obligation $ 425 210 165 243 Fair value of plan assets 199 6 — 6 115 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents Included in accumulated other comprehensive income (loss) at December 31 were the following before-tax amounts that had not been recognized in net periodic benefit cost: Millions of Dollars Pension Benefits Other Benefits 2024 2023 2024 2023 U.S. Int’l. U.S. Int’l. Unrecognized net actuarial loss (gain) $ 112 445 123 585 2 3 Unrecognized prior service cost (credit) — 58 — 1 ( 21 ) ( 60 ) Millions of Dollars Pension Benefits Other Benefits 2024 2023 2024 2023 U.S. Int’l. U.S. Int’l. Sources of Change in Other Comprehensive Income (Loss) Net gain (loss) arising during the period $ 3 83 30 29 ( 5 ) ( 22 ) Amortization of actuarial loss included in income (loss)* 8 57 18 67 — ( 3 ) Net change during the period $ 11 140 48 96 ( 5 ) ( 25 ) Prior service credit (cost) arising during the period $ — ( 57 ) — — — — Amortization of prior service (credit) included in income (loss) — — — — ( 38 ) ( 38 ) Net change during the period $ — ( 57 ) — — ( 38 ) ( 38 ) *Includes settlement (gains) losses recognized in 2024 and 2023. The components of net periodic benefit cost of all defined benefit plans are presented in the following table: Millions of Dollars Pension Benefits Other Benefits 2024 2023 2022 2024 2023 2022 U.S. Int’l. U.S. Int’l. U.S. Int’l. Components of Net Periodic Benefit Cost Service cost $ 49 38 51 38 58 47 1 1 1 Interest cost 76 114 77 113 62 77 5 5 4 Expected return on plan assets ( 66 ) ( 163 ) ( 58 ) ( 148 ) ( 50 ) ( 124 ) — — — Amortization of prior service credit — — — — — ( 1 ) ( 38 ) ( 38 ) ( 38 ) Recognized net actuarial loss (gain) 8 58 12 67 24 11 — ( 3 ) — Settlements loss (gain) — ( 1 ) 6 — 37 — — — — Curtailment loss (gain) 8 — — — — — — — — Net periodic benefit cost $ 75 46 88 70 131 10 ( 32 ) ( 35 ) ( 33 ) 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. ConocoPhillips 2024 10-K 116 Notes to Consolidated Financial Statements Table of Contents We recognized pension settlement losses of $ 6 million in 2023 and $ 37 million in 2022 as lump-sum benefit payments from certain U.S. and international pension plans exceeded the sum of service and interest costs for those plans and led to recognition of settlement losses. In determining net pension and other postretirement benefit costs, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. For net actuarial gains and losses, we amortize 10 percent of the unamortized balance each year. We have multiple non-pension postretirement benefit plans for health and life insurance. The health care plans are contributory and subject to various cost sharing features, most with participant and company contributions adjusted annually; the life insurance plans are noncontributory. The measurement of the U.S. pre-65 retiree medical accumulated postretirement benefit obligation assumes a health care cost trend rate of 6.5 percent in 2025 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 4.6 percent in 2025 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 26 percent in equity securities, 69 percent in debt securities, 4 percent in real estate and 1 percent in other. 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, 2024 and 2023. • Fair values of equity securities and government debt securities categorized in Level 1 are primarily based on quoted market prices in active markets for identical assets and liabilities. • Fair values of corporate debt securities, agency and mortgage-backed securities and government debt securities categorized in Level 2 are estimated using recently executed transactions and quoted market prices for similar assets and liabilities in active markets and for identical assets and liabilities in markets that are not active. If there have been no market transactions in a particular fixed income security, its fair value is calculated by pricing models that benchmark the security against other securities with actual market prices. When observable quoted market prices are not available, fair value is based on pricing models that use something other than actual market prices (e.g., observable inputs such as benchmark yields, reported trades and issuer spreads for similar securities), and these securities are categorized in Level 3 of the fair value hierarchy. • Fair values of investments in common/collective trusts are determined by the issuer of each fund based on the fair value of the underlying assets. • Fair values of mutual funds are based on quoted market prices, which represent the net asset value of shares held. • Time deposits are valued at cost, which approximates fair value. • Cash is valued at cost, which approximates fair value. Fair values of international cash equivalents categorized in Level 2 are valued using observable yield curves, discounting and interest rates. U.S. cash balances held in the form of short-term fund units that are redeemable at the measurement date are categorized as Level 2. • Fair values of exchange-traded derivatives classified in Level 1 are based on quoted market prices. For other derivatives classified in Level 2, the values are generally calculated from pricing models with market input parameters from third-party sources. • Fair values of insurance contracts are valued at the present value of the future benefit payments owed by the insurance company to the plans’ participants. • Fair values of real estate investments are valued using real estate valuation techniques and other methods that include reference to third-party sources and sales comparables where available. 117 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents • A portion of U.S. pension plan assets is held as a participating interest in an insurance annuity contract, which is calculated as the market value of investments held under this contract, less the accumulated benefit obligation covered by the contract. The participating interest is classified as Level 3 in the fair value hierarchy as the fair value is determined via a combination of quoted market prices, recently executed transactions, and an actuarial present value computation for contract obligations. At December 31, 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. At December 31, 2023, the participating interest in the annuity contract was valued at $ 46 million and consisted of $ 130 million in debt securities, less $ 84 million for the accumulated benefit obligation covered by the contract. The participating interest is not available for meeting general pension benefit obligations in the near term. No future company contributions are required and no new benefits are being accrued under this insurance annuity contract. The fair values of our pension plan assets at December 31, by asset class were as follows: Millions of Dollars U.S. International Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total 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. ConocoPhillips 2024 10-K 118 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 2023 Equity securities U.S. $ 6 — — 6 — — — — International 35 — — 35 — — — — Mutual funds 15 — — 15 244 276 — 520 Debt securities Corporate — 1 — 1 — — — — Mutual funds — — — — 421 — — 421 Cash and cash equivalents — — — — 25 — — 25 Derivatives Real estate — — — — — — 126 126 Total in fair value hierarchy $ 56 1 — 57 690 276 126 1,092 Investments measured at net asset value* Equity securities Common/collective trusts 300 198 Debt securities Common/collective trusts 868 1,791 Cash and cash equivalents 6 — Real estate 28 — Total** $ 56 1 — 1,259 690 276 126 3,081 *In accordance with FASB ASC Topic 715, “Compensation—Retirement Benefits,” certain investments that are to be measured at fair value using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Change in Fair Value of Plan Assets. **Excludes the participating interest in the insurance annuity contract with a net asset of $ 46 million and net receivables related to security transactions of $ 5 million. Level 3 activity was not material for all periods. Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code of 1986, as amended. Contributions to foreign plans are dependent upon local laws and tax regulations. In 2025, we expect to contribute approximately $ 190 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $ 55 million to our international qualified and nonqualified pension and postretirement benefit plans. 119 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents The following benefit payments, which are exclusive of amounts to be paid from the insurance annuity contract and which reflect expected future service, as appropriate, are expected to be paid: Millions of Dollars Pension Benefits Other Benefits U.S. Int’l. 2025 $ 386 120 21 2026 224 124 19 2027 213 126 17 2028 199 128 16 2029 195 132 15 2030–2034 769 710 63 The following table summarizes our severance accrual activity: Millions of Dollars 2024 2023 2022 Balance at January 1 $ 12 31 78 Accruals 328 1 1 Benefit payments ( 9 ) ( 20 ) ( 48 ) Balance at December 31 $ 331 12 31 In 2024, accruals included severance costs associated with contractual termination benefits applicable to officers and employees of Marathon Oil as of the acquisition date. Of the remaining balance at December 31, 2024, $ 323 million is classified as short-term. See Note 3. 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 $ 152 million in 2024, $ 151 million in 2023 and $ 140 million in 2022. 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 $ 25 million in 2024, $ 23 million in 2023 and $ 24 million in 2022. Share-Based Compensation Plans The 2023 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (Omnibus Plan) was approved by shareholders in May 2023, replacing similar prior plans and providing that no new awards shall be granted under the prior plans. Over its 10-year life, the Omnibus Plan allows the issuance of up to 36 million shares of our common stock for compensation to our employees and directors, but the available shares (i) are reduced by awards granted under the prior plan between the board adoption date (February 15, 2023) and the shareholder approval date (May 16, 2023) and (ii) are increased by any shares of common stock represented by awards granted under the Omnibus Plan or the prior plans that are forfeited, expire or are cancelled without delivery of shares of common stock or which result in the forfeiture of shares of common stock back to the company, excluding shares surrendered in payment of the exercise of a stock option or stock appreciation right, shares not issued in connection with the stock settlement of a stock appreciation right, or shares reacquired by the company using cash proceeds from the exercise of a stock option. The Human Resources and Compensation Committee of our Board of Directors is authorized to determine the types, terms, conditions and limitations of awards granted. Awards may be granted in the form of, but not limited to, stock options, RSUs and performance share units (PSU) to employees and non-employee directors who contribute to the company’s continued success and profitability. ConocoPhillips 2024 10-K 120 Notes to Consolidated Financial Statements Table of Contents Total share-based compensation expense is measured using the grant date fair value for our equity-classified awards and the settlement date fair value for our liability-classified awards. We recognize share-based compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the award) or, for awards that provide for retirement-based vesting, the period beginning at the start of the service period and ending upon the 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 2024 2023 2022 Compensation cost $ 268 334 377 Tax benefit 67 84 95 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, 2024: Millions of Dollars Options Weighted-Average Exercise Price Aggregate Intrinsic Value Outstanding at December 31, 2023 3,264,675 $ 52.55 $ 209 Exercised ( 1,213,600 ) 68.42 63 Expired or cancelled — — Outstanding at December 31, 2024 2,051,075 $ 43.16 $ 113 Vested at December 31, 2024 2,051,075 $ 43.16 $ 113 Exercisable at December 31, 2024 2,051,075 $ 43.16 $ 113 The weighted-average remaining contractual term of outstanding options, vested options and exercisable options at December 31, 2024, were all 1.47 years. The aggregate intrinsic value of options exercised was $ 58 million in 2023 and $ 308 million in 2022. During 2024, we received $ 83 million in cash and realized a tax benefit of $ 13 million from the exercise of options. At December 31, 2024, all outstanding stock options were fully vested and there was no remaining compensation cost to be recorded. 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. 121 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents 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 stock RSU activity for the year ended December 31, 2024: Stock Units Weighted-Average Grant Date Fair Value Millions of Dollars Total Fair Value Outstanding at December 31, 2023 7,093,690 $ 76.78 Granted 3,161,899 109.79 Forfeited ( 113,163 ) 104.34 Issued ( 3,670,653 ) 54.79 $ 410 Outstanding at December 31, 2024 6,471,773 $ 104.89 Not Vested at December 31, 2024 4,508,368 $ 105.31 At December 31, 2024, the remaining unrecognized compensation cost from the unvested stock-settled RSUs was $ 212 million, which will be recognized over a weighted-average period of 1.63 years, the longest period being 3 years. The weighted-average grant date fair value of stock-settled RSUs granted during 2023 and 2022 was $ 110.91 and 90.57 , respectively. The total fair value of stock-settled RSUs issued during 2023 and 2022 was $ 284 million and $ 193 million, respectively. Cash-Settled Cash-settled executive RSUs granted in 2018 and 2019 replaced the stock option program. These RSUs, subject to elections to defer, were settled in cash equal to the fair market value of a share of ConocoPhillips common stock per unit on the settlement date and are classified as liabilities on the balance sheet. Executive RSUs awarded to retirement eligible employees may vest earlier; however, those units were not settled until after the earlier of separation from the company or the end of the regularly scheduled vesting period. Compensation expense was initially measured using the average fair market value of ConocoPhillips common stock and was subsequently adjusted, based on changes in the ConocoPhillips stock price through the end of each subsequent reporting period, through the settlement date. Recipients received an accrued reinvested dividend equivalent that was charged to compensation expense. The accrued reinvested dividend was paid at the time of settlement, subject to the terms and conditions of the award. There was no cash-settled stock unit activity and no remaining unrecognized compensation cost to be recorded for the unvested cash-settled units for the year ended December 31, 2024 and December 31, 2023. The total fair value of cash-settled executive RSUs issued during 2022 was $ 21 million. 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. ConocoPhillips 2024 10-K 122 Notes to Consolidated Financial Statements Table of Contents Stock-Settled Stock-settled PSUs are settled by issuing one share of ConocoPhillips common stock per unit. For performance periods beginning before 2009, PSUs do not vest until the employee becomes eligible for retirement by reaching age 55 with five years of service, and restrictions do not lapse until the employee separates from the company. With respect to awards for performance periods beginning in 2009 through 2012, PSUs do not vest until the earlier of the date the employee becomes eligible for retirement by reaching age 55 with five years of service or five years after the grant date of the award, and restrictions do not lapse until the earlier of the employee’s separation from the company or five years after the grant date (although recipients can elect to defer the lapsing of restrictions until separation). We recognize compensation expense for these awards beginning on the grant date and ending on the date the PSUs are scheduled to vest. Because these awards are authorized three years prior to the effective grant date, for employees eligible for retirement by or shortly after the grant date, we recognize compensation expense over the period beginning on the date of authorization and ending on the date of grant. Until issued as stock, recipients of the stock-settled PSUs issued prior to 2013 receive a cash payment of a dividend equivalent that is charged to retained earnings. Beginning in 2013, stock-settled PSUs authorized for future grants will vest 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, 2024: Weighted-Average Grant Date Fair Value Millions of Dollars Stock Units Total Fair Value Outstanding at December 31, 2023 962,818 $ 50.79 Granted 10,722 110.39 Forfeited — — Issued ( 199,037 ) 54.17 $ 23 Outstanding at December 31, 2024 774,503 $ 50.75 At December 31, 2024, 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 2023 and 2022 was $ 112.50 and $ 91.58 , respectively. The total fair value of stock-settled PSUs issued during 2023 and 2022 was $ 29 million and $ 21 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 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. 123 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents The following summarizes our cash-settled Performance Share Program activity for the year ended December 31, 2024: Weighted-Average Grant Date Fair Value Millions of Dollars Stock Units Total Fair Value Outstanding at December 31, 2023 100,870 $ 116.68 Granted 1,535,539 110.39 Settled ( 1,546,826 ) 110.41 $ 171 Outstanding at December 31, 2024 89,583 $ 98.20 At December 31, 2024, all outstanding cash-settled performance awards were fully vested and there was no remaining compensation cost to be recorded. The weighted-average grant date fair value of cash-settled PSUs granted during 2023 and 2022 was $ 112.50 and $ 91.58 , respectively. The total fair value of cash-settled performance share awards settled during 2023 and 2022 was $ 111 million and $ 88 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, 2024: Weighted-Average Grant Date Fair Value Millions of Dollars Stock Units Total Fair Value Outstanding at December 31, 2023 894,268 $ 54.76 Granted 39,750 111.91 Cancelled — — Issued ( 304,337 ) 50.91 $ 35 Outstanding at December 31, 2024 629,681 $ 60.22 At December 31, 2024, all outstanding restricted stock and RSUs were fully vested and there was no remaining compensation cost to be recorded. The weighted-average grant date fair value of awards granted during 2023 and 2022 was $ 115.88 and $ 96.20 , respectively. The total fair value of awards issued during 2023 and 2022 was $ 46 million and $ 40 million, respectively. ConocoPhillips 2024 10-K 124 Notes to Consolidated Financial Statements Table of Contents Note 16—Income Taxes Components of income tax provision (benefit) were: Millions of Dollars 2024 2023 2022 Income Taxes Federal Current $ 629 1,054 1,263 Deferred 247 825 1,629 Foreign Current 3,249 2,931 5,813 Deferred 71 254 387 State and local Current 182 202 386 Deferred 49 65 70 Total tax provision (benefit) $ 4,427 5,331 9,548 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 2024 2023 Deferred Tax Liabilities PP&E and intangibles $ 15,609 11,992 Inventory 91 46 Other 155 216 Total deferred tax liabilities 15,855 12,254 Deferred Tax Assets Benefit plan accruals 432 413 Asset retirement obligations and accrued environmental costs 2,799 2,608 Investments in joint ventures 2,269 2,133 Other financial accruals and deferrals 497 448 Loss and credit carryforwards 4,910 5,629 Other 187 121 Total deferred tax assets 11,094 11,352 Less: valuation allowance ( 6,435 ) ( 7,656 ) Total deferred tax assets net of valuation allowance 4,659 3,696 Net deferred tax liabilities $ 11,196 8,558 At December 31, 2024, noncurrent assets and liabilities included deferred taxes of $ 230 million and $ 11,426 million, respectively. At December 31, 2023, noncurrent assets and liabilities included deferred taxes of $ 255 million and $ 8,813 million, respectively. Our deferred tax liability increased during 2024 by $ 2.5 billion due to the acquisition of Marathon Oil. 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 . At December 31, 2023, the loss and credit carryforward deferred tax assets were primarily related to U.S. foreign tax credit carryforwards of $ 4.7 billion and various jurisdictions net operating loss and credit carryforwards of $ 0.9 billion. 125 ConocoPhillips 2024 10-K 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 2024, 2023 and 2022: Millions of Dollars 2024 2023 2022 Balance at January 1 $ 7,656 8,049 8,342 Charged to expense (benefit) ( 409 ) ( 2 ) 5 Other* ( 812 ) ( 391 ) ( 298 ) Balance at December 31 $ 6,435 7,656 8,049 *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, 2024, 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 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. During 2022, the valuation allowance movement charged to earnings primarily related to the impact of 2022 changes to Norway’s Petroleum Tax System which is partly offset by the U.S. tax impact of the disposition of our CVE common shares. Other movements are primarily related to valuation allowances on expiring tax attributes. Based on our historical taxable income, expectations for the future and available tax-planning strategies, management expects deferred tax assets, net of valuation allowances, will primarily be realized as offsets to reversing deferred tax liabilities. 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 . During the second quarter of 2022, Norway enacted changes to the Petroleum Tax System. As a result of the enactment, a valuation allowance of $ 58 million was recorded during the second quarter to reflect changes to our ability to realize certain deferred tax assets under the new law. At December 31, 2024, unremitted income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures totaled approximately $ 5,226 million. Deferred income taxes have not been provided on this amount, as we do not plan to initiate any action that would require the payment of income taxes. The estimated amount of additional tax, primarily local withholding tax, that would be payable on this income if distributed is approximately $ 261 million. The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2024, 2023 and 2022: Millions of Dollars 2024 2023 2022 Balance at January 1 $ 387 710 1,345 Additions based on tax positions related to the current year 3 5 6 Additions for tax positions of prior years 127 1 6 Reductions for tax positions of prior years — ( 9 ) ( 62 ) Settlements ( 121 ) ( 96 ) ( 510 ) Lapse of statute ( 19 ) ( 224 ) ( 75 ) Balance at December 31 $ 377 387 710 Included in the balance of unrecognized tax benefits for 2024, 2023 and 2022 were $ 368 million, $ 378 million and $ 701 million, respectively, which, if recognized, would impact our effective tax rate. ConocoPhillips 2024 10-K 126 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. The balance of the unrecognized tax benefits decreased in 2022 due to the closing of the 2017 audit of our federal income tax return. As a result, we recognized federal and state tax benefits totaling $ 515 million relating to the recovery of outside tax basis previously offset by a full reserve. At December 31, 2024, 2023 and 2022, accrued liabilities for interest and penalties totaled $ 26 million, $ 45 million and $ 35 million, respectively, net of accrued income taxes. Interest and penalties resulted in an increase to earnings of $ 19 million in 2024, a reduction to earnings of $ 10 million in 2023 and an increase to earnings of $ 12 million in 2022. We file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions. Audits in major jurisdictions are generally complete as follows: Canada (2016), Norway (2023) and U.S. (2019). Issues in dispute for audited years and audits for subsequent years are ongoing and in various stages of completion in the many jurisdictions in which we operate around the world. Consequently, the balance in unrecognized tax benefits can be expected to fluctuate from period to period. Within the next twelve months, we may have audit periods close that could significantly impact our total unrecognized tax benefits. It is reasonably possible such changes could be significant when compared with our total unrecognized tax benefits, but the amount of change is not estimable. The amounts of U.S. and foreign income (loss) before income taxes, with a reconciliation of tax at the federal statutory rate to the provision for income taxes, were: Millions of Dollars Percent of Pre-Tax Income (Loss) 2024 2023 2022 2024 2023 2022 Income (loss) before income taxes United States $ 6,731 9,472 16,739 49.2 % 58.2 59.3 Foreign 6,941 6,816 11,489 50.8 41.8 40.7 $ 13,672 16,288 28,228 100.0 % 100.0 100.0 Federal statutory income tax $ 2,871 3,421 5,928 21.0 % 21.0 21.0 Non-U.S. effective tax rates 1,822 2,063 3,866 13.3 12.7 13.7 Recovery of outside basis ( 5 ) ( 4 ) ( 30 ) — — ( 0.1 ) Adjustment to tax reserves ( 57 ) ( 317 ) ( 551 ) ( 0.4 ) ( 1.9 ) ( 2.0 ) Adjustment to valuation allowance ( 409 ) ( 2 ) 5 ( 3.0 ) — — State income tax 187 214 405 1.4 1.3 1.4 Other 18 ( 44 ) ( 75 ) 0.1 ( 0.3 ) ( 0.2 ) Total $ 4,427 5,331 9,548 32.4 % 32.7 33.8 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. Our effective tax rate for 2022 was driven by our jurisdictional tax rates for this profit mix with net favorable impacts from routine tax credits and valuation allowance adjustments. The adjustment to tax reserves primarily relates to the closing of the audit of our 2017 U.S. federal tax return and the recognition of the U.S. federal and state tax benefits described above. 127 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022, which among other things, implemented a 15 percent minimum tax on book income of certain large corporations, a one percent excise tax on net stock repurchased and several tax incentives to promote lower carbon energy. These law changes did not have a material impact to our consolidated financial statements. Note 17—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, 2021 $ ( 31 ) — ( 4,919 ) — ( 4,950 ) Other comprehensive income (loss) ( 417 ) ( 11 ) ( 622 ) — ( 1,050 ) December 31, 2022 ( 448 ) ( 11 ) ( 5,541 ) — ( 6,000 ) Other comprehensive income (loss) 55 13 197 62 327 December 31, 2023 ( 393 ) 2 ( 5,344 ) 62 ( 5,673 ) Other comprehensive income (loss) 3 1 ( 760 ) ( 44 ) ( 800 ) December 31, 2024 $ ( 390 ) 3 ( 6,104 ) 18 ( 6,473 ) The following table summarizes reclassifications out of accumulated other comprehensive income (loss) during the years ended December 31: Millions of Dollars 2024 2023 Defined Benefit Plans* $ 19 33 *Included in the computation of net periodic benefit cost and are presented net of tax expense of: $ 8 11 See Note 15. Note 18—Cash Flow Information Millions of Dollars 2024 2023 2022 Noncash Investing and Financing Activities Increase (decrease) in PP&E related to an increase (decrease) in asset retirement obligations, excluding acquisitions $ 268 727 825 Fair value of contingent consideration on acquisition — 320 Cash Payments Interest $ 806 701 873 Income taxes 3,621 5,406 7,368 Net Sales (Purchases) of Investments Short-term investments purchased $ ( 2,606 ) ( 1,463 ) ( 5,046 ) Short-term investments sold 3,567 3,574 3,102 Long-term Investments purchased ( 747 ) ( 867 ) ( 775 ) Long-term Investments sold 201 129 90 $ 415 1,373 ( 2,629 ) For additional information on cash and non-cash changes to our consolidated balance sheet, see Note 3 and Note 12 for our acquisition of Marathon Oil and acquisition of the remaining working interest in Surmont. ConocoPhillips 2024 10-K 128 Notes to Consolidated Financial Statements Table of Contents Note 19—Other Financial Information Millions of Dollars 2024 2023 2022 Interest and Debt Expense Incurred Debt $ 941 824 791 Other 90 109 72 1,031 933 863 Capitalized ( 248 ) ( 153 ) ( 58 ) Expensed $ 783 780 805 Other Income Interest income $ 402 412 195 Gain (loss) on investment in Cenovus Energy* — — 251 Other, net 50 73 58 $ 452 485 504 *See Note 5 . Research and Development Expenditures— expensed $ 81 81 71 Shipping and Handling Costs $ 1,958 1,695 1,595 Foreign Currency Transaction (Gains) Losses— after-tax Alaska $ — — — Lower 48 — — — Canada ( 35 ) 11 ( 20 ) Europe, Middle East and North Africa ( 37 ) ( 39 ) ( 110 ) Asia Pacific ( 1 ) 12 30 Other International — — ( 1 ) Corporate and Other 36 86 21 $ ( 37 ) 70 ( 80 ) Millions of Dollars 2024 2023 Properties, Plants and Equipment Proved properties $ 155,364 134,394 Unproved properties 15,490 5,206 Other 4,574 4,805 Gross properties, plants and equipment 175,428 144,405 Less: Accumulated depreciation, depletion and amortization ( 81,072 ) ( 74,361 ) Net properties, plants and equipment $ 94,356 70,044 129 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents Note 20—Related Party Transactions Our related parties primarily include equity method investments and certain trusts for the benefit of employees. For disclosures on trusts for the benefit of employees, see Note 15 . Significant transactions with our equity affiliates were: Millions of Dollars 2024 2023 2022 Operating revenues and other income $ 88 90 88 Purchases — — 1 Operating expenses and selling, general and administrative expenses 246 282 189 Net interest (income)/loss* — — ( 1 ) *We paid interest to, or received interest from, various affiliates. See Note 4 for additional information on loans to affiliated companies. Note 21—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 2024 2023 2022 Revenue from contracts with customers $ 49,418 48,522 61,049 Revenue from contracts outside the scope of ASC Topic 606 Physical contracts meeting the definition of a derivative 5,483 8,203 17,150 Financial derivative contracts ( 156 ) ( 584 ) 295 Consolidated sales and other operating revenues $ 54,745 56,141 78,494 Revenues from contracts outside the scope of ASC Topic 606 relate primarily to physical gas contracts at market prices, which qualify as derivatives accounted for under ASC Topic 815, “Derivatives and Hedging,” and for which we have not elected NPNS. There is no significant difference in contractual terms or the policy for recognition of revenue from these contracts and those within the scope of ASC Topic 606. The following disaggregation of revenues is provided in conjunction with Note 23 —Segment Disclosures and Related Information : Millions of Dollars 2024 2023 2022 Revenue from Contracts Outside the Scope of ASC Topic 606 by Segment Lower 48 $ 4,174 6,607 13,919 Canada 522 1,248 2,717 Europe, Middle East and North Africa 787 348 514 Physical contracts meeting the definition of a derivative $ 5,483 8,203 17,150 Millions of Dollars 2024 2023 2022 Revenue from Contracts Outside the Scope of ASC Topic 606 by Product Crude oil $ 376 143 495 Natural gas 3,753 6,622 15,368 Other 1,354 1,438 1,287 Physical contracts meeting the definition of a derivative $ 5,483 8,203 17,150 ConocoPhillips 2024 10-K 130 Notes to Consolidated Financial Statements Table of Contents 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 and Contract Liabilities Receivables from Contracts with Customers At December 31, 2024, the “Accounts and notes receivable” line on our consolidated balance sheet included trade receivables of $ 5,398 million compared with $ 4,414 million at December 31, 2023, 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. Contract Liabilities from Contracts with Customers We have entered into certain agreements under which we license our proprietary technology, including the Optimized Cascade® process technology, to customers to maximize the efficiency of LNG plants. These agreements typically provide for milestone payments to be made during and after the construction phases of the LNG plant. The payments are not directly related to our performance obligations under the contract and are recorded as deferred revenue to be recognized when the customer is able to benefit from their right to use the applicable licensed technology. Revenue recognized during the year ended December 31, 2024 was immaterial . We expect to recognize the outstanding contract liabilities of $ 45 million as of December 31, 2024, as revenue during the years 2026, 2028 and 2029. 131 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents Note 22—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, 2024, 2023, and 2022. 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 2024 2023 2022 Basic earnings per share Net Income (Loss) $ 9,245 10,957 18,680 Less: Dividends and undistributed earnings allocated to participating securities 27 35 60 Net Income (Loss) available to common shareholders $ 9,218 10,922 18,620 Average common shares outstanding (in Millions) 1,179 1,203 1,274 Net Income (Loss) Per Share of Common Stock $ 7.82 9.08 14.62 Diluted earnings per share Net Income (Loss) available to common shareholders $ 9,218 10,922 18,620 Average common shares outstanding (in Millions) 1,179 1,203 1,274 Add: Dilutive impact of options and unvested non-participating RSU/PSUs 2 3 4 Average diluted shares outstanding (in Millions) 1,181 1,206 1,278 Net Income (Loss) Per Share of Common Stock $ 7.81 9.06 14.57 Note 23—Segment Disclosures and Related Information We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide basis. We manage our operations through six operating segments, which are primarily defined by geographic region: Alaska; Lower 48 (L48); Canada; Europe, Middle East and North Africa (EMENA); Asia Pacific (AP); and Other International (OI). 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. 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. ConocoPhillips 2024 10-K 132 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 OI Corporate Consolidated Total Segment sales and other operating revenues Sales and other operating revenues $ 6,553 37,028 5,636 5,788 1,847 — 54 56,906 Intersegment eliminations — ( 2 ) ( 2,122 ) — — — ( 37 ) ( 2,161 ) Consolidated sales and other operating revenues* 6,553 37,026 3,514 5,788 1,847 — 17 54,745 Significant segment expenses** Production and operating expenses 1,951 4,751 902 671 384 — 92 8,751 DD&A 1,299 6,442 639 761 425 — 33 9,599 Income tax provision (benefit) 480 1,462 228 2,854 211 ( 1 ) ( 807 ) 4,427 Total 3,730 12,655 1,769 4,286 1,020 ( 1 ) ( 682 ) 22,777 Other segment items Equity in earnings of affiliates 1 ( 5 ) — ( 586 ) ( 1,089 ) — ( 26 ) ( 1,705 ) Interest income — — — — ( 8 ) — ( 394 ) ( 402 ) Interest and debt expense — — — — — — 783 783 Other*** 1,496 19,201 1,033 899 200 2 1,216 24,047 Total 1,497 19,196 1,033 313 ( 897 ) 2 1,579 22,723 Net income (loss) $ 1,326 5,175 712 1,189 1,724 ( 1 ) ( 880 ) 9,245 *In 2024, sales by our Lower 48 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. **The significant segment expense categories and amounts in the table above align with segment-level information that is regularly provided to the CODM. ***Other segment items not required to be separately disclosed for each reportable segment include: Gain (loss) on disposition: L48, Canada, EMENA and OI Other income; Selling, general and administrative expenses and Exploration expenses: Alaska, L48, Canada, EMENA, AP, OI and Corporate Purchased commodities: Alaska, L48, Canada, EMENA and AP Impairments: Alaska, L48, Canada and EMENA Taxes other than income taxes and Accretion on discounted liabilities: Alaska, L48, Canada, EMENA, AP and Corporate 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 OI Corporate Consolidated Total Investment in and advances to affiliates $ 3 123 — 1,948 4,977 8 1,551 8,610 Total Assets 18,030 66,977 9,513 9,770 8,390 8 10,092 122,780 Capital expenditures and investments 3,194 6,510 551 1,021 370 — 472 12,118 133 ConocoPhillips 2024 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 OI Corporate Consolidated Total Segment sales and other operating revenues Sales and other operating revenues $ 7,098 38,244 4,873 5,854 1,913 — 63 58,045 Intersegment eliminations — ( 7 ) ( 1,867 ) — — — ( 30 ) ( 1,904 ) Consolidated sales and other operating revenues* 7,098 38,237 3,006 5,854 1,913 — 33 56,141 Significant segment expenses** Production and operating expenses 1,829 4,199 619 593 391 1 61 7,693 DD&A 1,061 5,722 420 587 455 — 25 8,270 Income tax provision (benefit) 642 1,763 26 3,065 42 — ( 207 ) 5,331 Total 3,532 11,684 1,065 4,245 888 1 ( 121 ) 21,294 Other segment items Equity in earnings of affiliates ( 1 ) 9 — ( 580 ) ( 1,151 ) — 3 ( 1,720 ) Interest income — — — ( 1 ) ( 8 ) — ( 403 ) ( 412 ) Interest and debt expense — — — — — — 780 780 Other*** 1,789 20,083 1,539 1,001 223 12 595 25,242 Total 1,788 20,092 1,539 420 ( 936 ) 12 975 23,890 Net income (loss) $ 1,778 6,461 402 1,189 1,961 ( 13 ) ( 821 ) 10,957 *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. **The significant segment expense categories and amounts in the table above align with segment-level information that is regularly provided to the CODM. ***Other segment items not required to be separately disclosed for each reportable segment include: Gain (loss) on dispositions: Alaska, L48, AP, OI and Corporate Other income; Purchased commodities; Selling, general and administrative expenses and Exploration expenses: Alaska, L48, Canada, EMENA, AP, OI and Corporate Impairments: L48, Canada and Corporate Taxes other than income taxes and Accretion on discounted liabilities: Alaska, L48, Canada, EMENA, AP 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 OI Corporate Consolidated Total Investment in and advances to affiliates $ 32 118 — 1,191 5,419 — 1,145 7,905 Total Assets 16,174 42,415 10,277 8,396 8,903 — 9,759 95,924 Capital expenditures and investments 1,705 6,487 456 1,111 354 — 1,135 11,248 ConocoPhillips 2024 10-K 134 Notes to Consolidated Financial Statements Table of Contents 2022 Segment level net income (loss) Year Ended December 31, 2022 Millions of Dollars Alaska L48 Canada EMENA AP OI Corporate Consolidated Total Segment sales and other operating revenues Sales and other operating revenues $ 7,905 52,921 6,159 11,271 2,606 — 122 80,984 Intersegment eliminations — ( 18 ) ( 2,445 ) ( 1 ) — — ( 26 ) ( 2,490 ) Consolidated sales and other operating revenues* 7,905 52,903 3,714 11,270 2,606 — 96 78,494 Significant segment expenses** Production and operating expenses 1,703 3,627 591 590 365 — 130 7,006 DD&A 939 4,865 402 736 518 — 44 7,504 Income tax provision (benefit) 885 3,088 206 5,445 480 53 ( 609 ) 9,548 Total 3,527 11,580 1,199 6,771 1,363 53 ( 435 ) 24,058 Other segment items Equity in earnings of affiliates ( 4 ) 14 — ( 780 ) ( 1,310 ) ( 1 ) — ( 2,081 ) Interest income — — — ( 1 ) ( 9 ) — ( 185 ) ( 195 ) Interest and debt expense — — — — — — 805 805 Other*** 2,030 30,294 1,801 3,036 ( 174 ) ( 1 ) 241 37,227 Total 2,026 30,308 1,801 2,255 ( 1,493 ) ( 2 ) 861 35,756 Net income (loss) $ 2,352 11,015 714 2,244 2,736 ( 51 ) ( 330 ) 18,680 *In 2022, no single customer amounted to 10% of our total consolidated sales and other operating revenues. **The significant segment expense categories and amounts in the table above align with segment-level information that is regularly provided to the CODM. ***Other segment items not required to be separately disclosed for each reportable segment include: Gain (loss) on dispositions: Alaska, L48, Canada, AP, OI and Corporate Other income: Alaska, L48, EMENA, AP, OI and Corporate Purchased commodities: Alaska, L48, Canada, EMENA and AP Selling, general and administrative expenses: Alaska, L48, Canada, EMENA, AP, OI and Corporate Exploration expenses, Impairments, Taxes other than income taxes and Accretion on discounted liabilities: Alaska, L48, Canada, EMENA, AP and Corporate Foreign currency transaction (gain) loss: Canada, EMENA, AP, OI and Corporate Other expenses: Alaska, L48, Canada, EMENA and Corporate Other segment disclosures Year Ended December 31, 2022 Millions of Dollars Alaska L48 Canada EMENA AP OI Corporate Consolidated Total Investment in and advances to affiliates $ 55 235 — 1,049 6,154 — — 7,493 Total Assets 15,126 42,950 6,971 8,263 9,511 — 11,008 93,829 Capital expenditures and investments 1,091 5,630 530 998 1,880 — 30 10,159 135 ConocoPhillips 2024 10-K Notes to Consolidated Financial Statements Table of Contents Sales and Other Operating Revenues by Product Millions of Dollars 2024 2023 2022 Crude oil $ 39,010 37,833 41,492 Natural gas 6,444 10,725 26,941 Natural gas liquids 2,889 2,609 3,650 Other* 6,402 4,974 6,411 Consolidated sales and other operating revenues by product $ 54,745 56,141 78,494 *Includes bitumen and power. Geographic Information Millions of Dollars Sales and Other Operating Revenues* Long-Lived Assets** 2024 2023 2022 2024 2023 2022 U.S. $ 43,480 45,101 60,899 79,141 53,955 51,200 Australia — — — 4,987 5,426 6,158 Canada 3,405 3,006 3,714 8,773 9,666 6,269 China 939 952 1,135 1,651 1,635 1,538 Equatorial Guinea 66 — — 1,593 — — Indonesia*** — — 159 — — — Libya 1,703 1,730 1,582 733 703 714 Malaysia 908 961 1,312 856 939 1,107 Norway 2,405 2,408 3,415 3,850 4,489 4,369 Singapore 37 — — — — — U.K. 1,796 1,978 6,273 2 2 1 Other foreign countries 6 5 5 1,380 1,134 1,003 Worldwide consolidated $ 54,745 56,141 78,494 102,966 77,949 72,359 *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. *** Assets divested in 2022. See Note 3 . Note 24—New Accounting Standards In December 2023, the FASB issued ASU No. 2023-09, “Improvements to Income Tax Disclosures” which enhances the disclosure requirements within Topic 740 “Income Taxes.” The enhancements will impact our financial statement disclosures only and will be applied prospectively with retrospective application permitted. The ASU is effective for annual periods beginning after December 15, 2024, and early adoption is permitted. We are currently evaluating the impact of the adoption of this ASU. 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. ConocoPhillips 2024 10-K 136 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, 2024, approximately three percent of our total proved reserves were under PSCs, located in our Asia Pacific/Middle East and Africa geographic reporting areas, and seven 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. 137 ConocoPhillips 2024 10-K 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 2024, our processes and controls used to assess over 85 percent of proved reserves as of December 31, 2024, 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, 2024 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. ConocoPhillips 2024 10-K 138 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 2021 1,035 1,452 2,487 10 161 122 184 2,964 63 3,027 Revisions (31) 24 (7) — 31 19 (3) 40 — 40 Improved recovery — — — — — 3 — 3 — 3 Purchases — 6 6 — — — 42 48 — 48 Extensions and discoveries 15 250 265 — 8 — — 273 35 308 Production (64) (193) (257) (2) (25) (22) (13) (319) (5) (324) Sales — (31) (31) — — (3) — (34) — (34) End of 2022 955 1,508 2,463 8 175 119 210 2,975 93 3,068 Revisions (57) 126 69 1 (1) 8 10 87 1 88 Improved recovery — — — — — — — — — — Purchases — 2 2 — — — — 2 — 2 Extensions and discoveries 219 54 273 15 3 19 — 310 — 310 Production (64) (202) (266) (3) (23) (22) (17) (331) (5) (336) Sales — (11) (11) — — — — (11) — (11) End of 2023 1,053 1,477 2,530 21 154 124 203 3,032 89 3,121 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 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 2021 912 916 1,828 4 122 98 171 2,223 63 2,286 End of 2022 867 828 1,695 5 124 102 191 2,117 58 2,175 End of 2023 790 793 1,583 7 109 91 181 1,971 54 2,025 End of 2024 767 1,122 1,889 11 101 88 208 2,297 49 2,346 Undeveloped End of 2021 123 536 659 6 39 24 13 741 — 741 End of 2022 88 680 768 3 51 17 19 858 35 893 End of 2023 263 684 947 14 45 33 22 1,061 35 1,096 End of 2024 266 719 985 18 23 29 54 1,109 59 1,168 *All Equity Affiliate reserves are located in our Asia Pacific/Middle East Region. 139 ConocoPhillips 2024 10-K Supplementary Data Table of Contents Notable changes in proved crude oil reserves in the three years ended December 31, 2024, included: • Revisions : 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. In 2022, upward revisions in Lower 48 were due to additional development drilling in the unconventional plays of 81 million barrels and higher prices of 33 million barrels, partially offset by increasing operating costs of 72 million barrels and technical revisions of 18 million barrels. Upward revisions in Europe were primarily due to technical revisions of 23 million barrels and 8 million barrels due to higher prices. Upward revisions of 19 million barrels in our consolidated operations in Asia Pacific/Middle East were primarily due to technical revisions. • 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. In 2022, crude oil reserve purchases were primarily in Africa, as a result of the acquisition of additional interest in the Libya Waha Concession. • Extensions and discoveries : 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. In 2022, extensions and discoveries in Lower 48 were primarily within unconventional plays in the Permian Basin. Extensions and discoveries in our equity affiliates were in the Middle East. ConocoPhillips 2024 10-K 140 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 2021 82 546 628 5 11 — 644 33 677 Revisions 1 208 209 1 3 — 213 — 213 Improved recovery — — — — — — — — — Purchases — 3 3 — — — 3 — 3 Extensions and discoveries — 80 80 — 1 — 81 20 101 Production (5) (81) (86) (1) (2) — (89) (3) (92) Sales — (7) (7) — — — (7) — (7) End of 2022 78 749 827 5 13 — 845 50 895 Revisions (1) 119 118 — 2 — 120 1 121 Improved recovery — — — — — — — — — Purchases — 1 1 — — — 1 — 1 Extensions and discoveries — 20 20 6 — — 26 — 26 Production (5) (90) (95) (1) (2) — (98) (3) (101) Sales — (2) (2) — — — (2) — (2) End of 2023 72 797 869 10 13 — — 892 48 940 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 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 2021 82 334 416 3 9 — 428 33 461 End of 2022 78 409 487 3 10 — 500 31 531 End of 2023 72 426 498 4 9 — 511 28 539 End of 2024 71 653 724 6 7 — 13 750 25 775 Undeveloped End of 2021 — 212 212 2 2 — 216 — 216 End of 2022 — 340 340 2 3 — 345 19 364 End of 2023 — 371 371 6 4 — 381 20 401 End of 2024 — 388 388 6 2 — 1 397 37 434 *All Equity Affiliate reserves are located in our Asia Pacific/Middle East Region. 141 ConocoPhillips 2024 10-K Supplementary Data Table of Contents Notable changes in proved NGL reserves in the three years ended December 31, 2024, included: • Revisions : 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. In 2022, upward revisions in Lower 48 were due to additional development drilling in the unconventional plays of 88 million barrels, technical revisions of 75 million barrels, continued conversion of acquired Concho Permian two-stream contracts to a three-stream (crude oil, natural gas and NGLs) basis adding 70 million barrels, and higher prices of 13 million barrels. This was partially offset by increasing operating costs of 38 million barrels. • 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 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. In 2022, extensions and discoveries in Lower 48 were primarily within unconventional plays in the Permian Basin. Extensions and discoveries in our equity affiliates were in the Middle East. ConocoPhillips 2024 10-K 142 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 2021 2,625 4,658 7,283 105 768 764 217 9,137 3,697 12,834 Revisions (35) 361 326 8 108 (2) (14) 426 898 1,324 Improved recovery — — — — — — — — — — Purchases — 23 23 — — — 48 71 479 550 Extensions and discoveries — 505 505 4 103 — — 612 1,118 1,730 Production (88) (543) (631) (23) (117) (51) (10) (832) (439) (1,271) Sales — (262) (262) — — (385) — (647) — (647) End of 2022 2,502 4,742 7,244 94 862 326 241 8,767 5,753 14,520 Revisions (243) 521 278 27 73 6 (57) 327 (90) 237 Improved recovery — — — — — — — — — — Purchases — 4 4 — — — — 4 — 4 Extensions and discoveries — 121 121 144 1 4 — 270 58 328 Production (84) (570) (654) (25) (113) (24) (12) (828) (446) (1,274) Sales — (97) (97) — — — — (97) — (97) End of 2023 2,175 4,721 6,896 240 823 312 172 8,443 5,275 13,718 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 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 2021 2,579 3,100 5,679 52 679 688 217 7,315 3,204 10,519 End of 2022 2,474 2,628 5,102 64 641 322 241 6,370 3,974 10,344 End of 2023 2,156 2,525 4,681 92 591 305 172 5,841 3,558 9,399 End of 2024 2,186 3,670 5,856 147 642 289 457 7,391 3,189 10,580 Undeveloped End of 2021 46 1,558 1,604 53 89 76 — 1,822 493 2,315 End of 2022 28 2,114 2,142 30 221 4 — 2,397 1,779 4,176 End of 2023 19 2,196 2,215 148 232 7 — 2,602 1,717 4,319 End of 2024 60 2,066 2,126 132 104 7 11 2,380 2,681 5,061 *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 2,285 BCF, 2,263 BCF and 2,416 BCF, as of December 31, 2024, 2023 and 2022, 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. 143 ConocoPhillips 2024 10-K Supplementary Data Table of Contents Notable changes in proved natural gas reserves in the three years ended December 31, 2024, included: • Revisions : 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. In 2022, upward revisions in Lower 48 were due to additional development drilling in the unconventional plays of 544 BCF, higher prices of 109 BCF, and technical revisions of 41 BCF. These were partially offset by decreases of 233 BCF due to increasing operating costs, and 100 BCF due to the continued conversion of acquired Concho Permian two-stream contracts to a three-stream (crude oil, natural gas and natural gas liquids) basis. Upward revisions in Canada were driven by higher prices of 26 BCF, partially offset by technical revisions of 18 BCF. In Europe, technical revisions contributed 96 BCF, and higher prices 12 BCF of upward revisions. Downward revisions in Africa were primarily due to technical revisions. In our equity affiliates in Asia Pacific/Middle East, upward revisions were due to higher prices of 423 BCF, changing dynamics and improved prices in the regional LNG spot market of 331 BCF, and technical revisions of 204 BCF, partially offset by downward revisions due to increasing operating costs of 60 BCF. • 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. In 2022, purchases in Africa were a result of the acquisition of additional interest in the Libya Waha Concession. In our equity affiliates, purchases were due to the acquisition of additional affiliate interest in Asia Pacific. • Extensions and discoveries : 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. In 2022, extensions and discoveries in Lower 48 were primarily within unconventional plays in the Permian Basin. In Europe, extensions and discoveries were due to additional planned development. Extensions and discoveries in our equity affiliates were primarily in the Middle East. • Sales : In 2023, Lower 48 sales represent the disposition of noncore assets. In 2022, Lower 48 sales represent the disposition of noncore assets. Sales in our consolidated operations in Asia Pacific/Middle East represent the disposition of our Indonesia assets. ConocoPhillips 2024 10-K 144 Supplementary Data Table of Contents Years Ended December 31 Bitumen Millions of Barrels Canada Total* Developed and Undeveloped End of 2021 257 257 Revisions (17) (17) Improved recovery — — Purchases — — Extensions and discoveries — — Production (24) (24) Sales — — End of 2022 216 216 Revisions 15 15 Improved recovery — — Purchases 209 209 Extensions and discoveries — — Production (30) (30) Sales — — End of 2023 410 410 Revisions 118 118 Improved recovery — — Purchases — — Extensions and discoveries — — Production (45) (45) Sales — — End of 2024 483 483 Years Ended December 31 Bitumen Millions of Barrels Canada Total* Developed End of 2021 150 150 End of 2022 127 127 End of 2023 293 293 End of 2024 230 230 Undeveloped End of 2021 107 107 End of 2022 89 89 End of 2023 117 117 End of 2024 253 253 *There are no Bitumen reserves associated with our Equity Affiliates. Notable changes in proved bitumen reserves in the three years ended December 31, 2024, included: • Revisions : 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. In 2022, the impact of variable royalties on price resulted in downward revisions of 30 million barrels, partially offset by upward revisions primarily due to changes in development timing for specific pad locations from the Surmont development program. • Purchases: In 2023, purchases in Canada were a result of the acquisition of the remaining 50 percent working interest in Surmont. 145 ConocoPhillips 2024 10-K 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 2021 1,555 2,775 4,330 290 299 249 220 5,388 713 6,101 Revisions (35) 292 257 (15) 52 19 (5) 308 149 457 Improved recovery — — — — — 3 — 3 — 3 Purchases — 13 13 — — — 50 63 80 143 Extensions and discoveries 15 414 429 1 26 — — 456 241 697 Production (85) (364) (449) (31) (46) (31) (15) (572) (81) (653) Sales — (82) (82) — — (67) — (149) — (149) End of 2022 1,450 3,048 4,498 245 331 173 250 5,497 1,102 6,599 Revisions (98) 332 234 20 12 9 1 276 (14) 262 Improved recovery — — — — — — — — — — Purchases — 4 4 209 — — — 213 — 213 Extensions and discoveries 219 94 313 45 3 20 — 381 10 391 Production (83) (387) (470) (38) (43) (26) (19) (596) (82) (678) Sales — (29) (29) — — — — (29) — (29) End of 2023 1,488 3,062 4,550 481 303 176 232 5,742 1,016 6,758 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 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 2021 1,424 1,767 3,191 166 244 212 207 4,020 631 4,651 End of 2022 1,357 1,676 3,033 147 240 155 231 3,806 751 4,557 End of 2023 1,222 1,639 2,861 320 216 142 210 3,749 675 4,424 End of 2024 1,202 2,387 3,589 272 215 136 297 4,509 606 5,115 Undeveloped End of 2021 131 1,008 1,139 124 55 37 13 1,368 82 1,450 End of 2022 93 1,372 1,465 98 91 18 19 1,691 351 2,042 End of 2023 266 1,423 1,689 161 87 34 22 1,993 341 2,334 End of 2024 276 1,451 1,727 299 43 30 57 2,156 541 2,697 *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. ConocoPhillips 2024 10-K 146 Supplementary Data Table of Contents Proved Undeveloped Reserves The following table shows changes in total proved undeveloped reserves for 2024: Proved Undeveloped Reserves Millions of Barrels of Oil Equivalent End of 2023 2,334 Revisions 535 Improved recovery — Purchases 57 Extensions and discoveries 281 Sales (1) Transfers to Proved Developed (509) End of 2024 2,697 Revisions of 535 MMBOE were predominately driven by progression of development plans in the Lower 48 unconventional plays, Canada Oil Sands and Libya, partially offset by 31MMBOE due to product price changes across the portfolio. Purchases of 57 were primarily due to our acquisition of Marathon Oil in Lower 48 and Equatorial Guinea. Extensions and discoveries were largely driven by the continued development planned in equity affiliates in Asia Pacific/Middle East. The remaining extensions and discoveries were driven by the continued development planned in the other geographic regions, including Canada, Lower 48 unconventional plays, and Alaska. Transfers to proved developed reserves were driven by the ongoing development of our assets. Approximately 75 percent of the transfers were from the development of our Lower 48 unconventional plays. The remainder of transfers were from development across the other geographic regions. At both December 31, 2024 and 2023, our PUDs represented 35 percent of total proved reserves. Costs incurred for the year ended December 31, 2024, relating to the development of PUDs were $9.4 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 2024, approximately 88 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 in our equity affiliate in Australia. 147 ConocoPhillips 2024 10-K Supplementary Data Table of Contents Results of Operations The company’s results of operations from oil and gas activities for the years 2024, 2023 and 2022 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, 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. ConocoPhillips 2024 10-K 148 Supplementary Data Table of Contents 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. Year Ended December 31,2022 Millions of Dollars Alaska Lower 48 Total U.S. Canada Europe Asia Pacific/ Middle East Africa Other Areas Total Consolidated Operations Equity Affiliates* Consolidated operations Sales $ 7,210 24,309 31,519 1,622 6,594 2,602 1,339 — 43,676 1,000 Transfers 6 — 6 — — — — — 6 4,272 Transportation costs (647) — (647) — — — — — (647) — Other revenues (1) 115 114 338 1 536 184 10 1,183 41 Total revenues 6,568 24,424 30,992 1,960 6,595 3,138 1,523 10 44,218 5,313 Production costs excluding taxes 1,160 3,600 4,760 581 511 342 55 — 6,249 491 Taxes other than income taxes 1,265 1,687 2,952 21 36 243 2 — 3,254 1,536 Exploration expenses 34 189 223 149 122 49 19 2 564 — Depreciation, depletion and amortization 833 4,843 5,676 354 693 517 36 — 7,276 530 Impairments 2 (11) (9) (2) (1) — — — (12) — Other related expenses (19) 4 (15) (41) (178) 40 5 6 (183) (2) Accretion 78 55 133 11 62 25 — — 231 27 3,215 14,057 17,272 887 5,350 1,922 1,406 2 26,839 2,731 Income tax provision (benefit) 866 3,113 3,979 198 4,057 512 1,301 53 10,100 836 Results of operations $ 2,349 10,944 13,293 689 1,293 1,410 105 (51) 16,739 1,895 *All Equity Affiliate activity is located in our Asia Pacific/Middle East Region. 149 ConocoPhillips 2024 10-K Supplementary Data Table of Contents Statistics Net Production 2024 2023 2022 Thousands of Barrels Daily Crude Oil Consolidated operations Alaska 173 173 177 Lower 48 602 569 534 United States 775 742 711 Canada 17 9 6 Europe 69 64 71 Asia Pacific 59 60 61 Africa 49 48 36 Total consolidated operations 969 923 885 Equity affiliates—Asia Pacific/Middle East 13 13 13 Total company 982 936 898 Delaware Basin Area (Lower 48)* 301 274 258 Natural Gas Liquids Consolidated operations Alaska 15 16 17 Lower 48 279 256 221 United States 294 272 238 Canada 6 3 3 Europe 4 4 3 Total consolidated operations 304 279 244 Equity affiliates—Asia Pacific/Middle East 8 8 8 Total company 312 287 252 Delaware Basin Area (Lower 48)* 144 135 114 Bitumen Consolidated operations—Canada 122 81 66 Total company 122 81 66 Natural Gas Millions of Cubic Feet Daily Consolidated operations Alaska 39 38 34 Lower 48 1,625 1,457 1,402 United States 1,664 1,495 1,436 Canada 115 65 61 Europe 329 279 306 Asia Pacific 50 48 114 Africa 42 29 22 Total consolidated operations 2,200 1,916 1,939 Equity affiliates—Asia Pacific/Middle East 1,233 1,219 1,191 Total company 3,433 3,135 3,130 Delaware Basin Area (Lower 48)* 884 768 752 *At year-end 2024, 2023 and 2022, the Delaware Basin Area in Lower 48 contained more than 15 percent of our total proved reserves. ConocoPhillips 2024 10-K 150 Supplementary Data Table of Contents Average Sales Prices 2024 2023 2022 Crude Oil Per Barrel Consolidated operations Alaska* $ 71.32 74.46 92.58 Lower 48 74.17 76.19 94.46 United States 73.49 75.75 93.96 Canada 64.47 66.19 79.94 Europe 81.09 84.56 99.88 Asia Pacific 82.42 84.79 105.52 Africa 80.65 83.07 97.85 Total international 79.97 83.33 100.75 Total consolidated operations 74.76 77.19 95.27 Equity affiliates—Asia Pacific/Middle East 76.76 78.45 97.31 Total operations 74.78 77.21 95.30 Natural Gas Liquids Per Barrel Consolidated operations Lower 48 $ 22.02 21.73 35.36 United States 22.02 21.73 35.36 Canada 29.59 26.13 37.70 Europe 45.50 41.13 54.52 Total international 33.60 34.56 46.16 Total consolidated operations 22.43 22.12 35.67 Equity affiliates—Asia Pacific/Middle East 51.53 47.09 61.22 Total operations 23.19 22.82 36.50 Bitumen Per Barrel Consolidated operations—Canada $ 47.92 42.15 55.56 Natural Gas Per Thousand Cubic Feet Consolidated operations Alaska $ 3.90 4.47 3.64 Lower 48 0.87 2.12 5.92 United States 0.88 2.13 5.92 Canada** 0.54 1.80 3.62 Europe 11.11 13.33 35.33 Asia Pacific 3.74 3.95 5.84 Africa 7.32 6.49 6.59 Total international 7.87 10.01 23.54 Total consolidated operations 2.61 3.89 10.56 Equity affiliates—Asia Pacific/Middle East 8.22 8.46 9.39 Total operations 4.69 5.69 10.60 *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. 151 ConocoPhillips 2024 10-K Supplementary Data Table of Contents 2024 2023 2022 Average Production Costs Per Barrel of Oil Equivalent* Consolidated operations Alaska $ 18.73 17.45 15.89 Lower 48 11.13 10.72 9.97 United States 12.22 11.76 10.97 Canada 15.03 15.86 18.73 Europe 10.80 11.89 11.20 Asia Pacific 14.27 14.02 11.71 Africa 5.85 3.83 3.77 Total international 12.36 12.28 12.36 Total consolidated operations 12.26 11.87 11.27 Equity affiliates—Asia Pacific/Middle East 6.56 6.03 6.14 Average Production Costs Per Barrel—Bitumen Consolidated operations—Canada $ 15.19 14.42 17.62 Taxes Other Than Income Taxes Per Barrel of Oil Equivalent Consolidated operations Alaska $ 5.77 6.21 17.33 Lower 48 3.25 3.46 4.67 United States 3.62 3.88 6.80 Canada 0.52 0.68 0.68 Europe 0.77 0.83 0.79 Asia Pacific 4.40 4.63 8.32 Africa 0.20 0.16 0.14 Total international 1.18 1.44 2.51 Total consolidated operations 3.04 3.37 5.87 Equity affiliates—Asia Pacific/Middle East 14.28 14.77 19.22 Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent Consolidated operations Alaska $ 16.55 13.18 11.41 Lower 48 15.23 14.64 13.42 United States 15.42 14.42 13.08 Canada 9.90 9.85 11.41 Europe 14.71 12.67 15.19 Asia Pacific 17.29 18.29 17.71 Africa 3.27 2.58 2.47 Total international 11.68 11.36 13.28 Total consolidated operations 14.54 13.77 13.12 Equity affiliates—Asia Pacific/Middle East 5.85 4.77 6.63 *Includes bitumen. ConocoPhillips 2024 10-K 152 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, 2024, 2023 and 2022. 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 2024 2023 2022 2024 2023 2022 Exploratory Consolidated operations Alaska — — — — 2 — Lower 48 39 38 118 — 2 — United States 39 38 118 — 4 — Canada 7 6 6 — — — Europe — — — * * 2 Asia Pacific/Middle East * — — — — 1 Africa — — — 1 — 3 Other areas — — — — — — Total consolidated operations 46 44 124 1 4 6 Equity affiliates Asia Pacific/Middle East 2 3 * — * — Total equity affiliates 2 3 * — * — Development Consolidated operations Alaska 13 11 11 — — — Lower 48 507 494 388 — — — United States 520 505 399 — — — Canada 38 21 11 — — — Europe 8 4 3 — — — Asia Pacific/Middle East 23 20 22 — — — Africa 5 4 2 — — — Other areas — — — — — — Total consolidated operations 594 554 437 — — — Equity affiliates Asia Pacific/Middle East 54 45 28 — — — Total equity affiliates 54 45 28 — — — *Our total proportionate interest was less than one. 153 ConocoPhillips 2024 10-K Supplementary Data Table of Contents The table below represents the status of our wells drilling at December 31, 2024, 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, 2024. Wells at December 31, 2024 Productive In Progress Oil Gas Gross Net Gross Net Gross Net Consolidated operations Alaska 3 3 1,557 936 — — Lower 48 832 450 21,323 10,179 4,638 2,782 United States 835 453 22,880 11,115 4,638 2,782 Canada 62 62 213 213 174 174 Europe 14 2 497 84 65 4 Asia Pacific/Middle East 7 3 491 233 6 2 Africa 27 6 917 187 27 13 Other areas — — — — — — Total consolidated operations 945 526 24,998 11,832 4,910 2,975 Equity affiliates Asia Pacific/Middle East 422 65 — — 5,461 1,615 Total equity affiliates 422 65 — — 5,461 1,615 Acreage at December 31, 2024 Thousands of Acres Developed Undeveloped Gross Net Gross Net Consolidated operations Alaska 741 566 1,038 1,012 Lower 48 4,773 3,318 10,258 8,100 United States 5,514 3,884 11,296 9,112 Canada 309 286 3,396 2,006 Europe 451 60 610 188 Asia Pacific/Middle East 422 152 10,341 7,630 Africa 440 140 12,545 2,561 Other areas — — 156 125 Total consolidated operations 7,136 4,522 38,344 21,622 Equity affiliates Asia Pacific/Middle East 1,085 325 4,173 1,078 Total equity affiliates 1,085 325 4,173 1,078 ConocoPhillips 2024 10-K 154 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* 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 2022 Consolidated operations Unproved property acquisition $ — 255 255 — — — — — 255 — Proved property acquisition — 249 249 — — — 104 — 353 881 — 504 504 — — — 104 — 608 881 Exploration 61 1,278 1,339 99 121 59 3 2 1,623 25 Development 1,316 4,559 5,875 475 711 425 4 — 7,490 244 $ 1,377 6,341 7,718 574 832 484 111 2 9,721 1,150 *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* 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 2023 Consolidated operations Proved property $ 26,358 70,621 96,979 11,255 14,124 10,923 1,113 — 134,394 11,159 Unproved property 108 3,393 3,501 1,443 65 90 98 9 5,206 2,263 26,466 74,014 100,480 12,698 14,189 11,013 1,211 9 139,600 13,422 Accumulated depreciation, depletion and amortization 12,789 36,829 49,618 3,377 9,978 8,423 508 9 71,913 8,779 $ 13,677 37,185 50,862 9,321 4,211 2,590 703 — 67,687 4,643 *All Equity Affiliate activity is located in our Asia Pacific/Middle East Region. 155 ConocoPhillips 2024 10-K 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 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. **Certain amounts in Lower 48 have been revised to reflect additional Future cash inflows and Future production costs. Millions of Dollars Alaska Lower 48 Total U.S. Canada Europe Asia Pacific/ Middle East Africa Total Consolidated Operations Equity Affiliates* Total 2022 Future cash inflows $ 94,332 195,605 289,937 13,768 44,942 13,458 27,067 389,172 87,644 476,816 Less: Future production costs 47,979 63,987 111,966 5,722 7,559 5,582 1,085 131,914 51,912 183,826 Future development costs 8,501 21,379 29,880 960 4,378 1,159 531 36,908 2,685 39,593 Future income tax provisions 8,882 23,136 32,018 863 25,416 1,780 23,615 83,692 8,988 92,680 Future net cash flows 28,970 87,103 116,073 6,223 7,589 4,937 1,836 136,658 24,059 160,717 10 percent annual discount 13,733 31,191 44,924 1,936 1,827 1,505 746 50,938 10,787 61,725 Discounted future net cash flows $ 15,237 55,912 71,149 4,287 5,762 3,432 1,090 85,720 13,272 98,992 *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 $16,704. ConocoPhillips 2024 10-K 156 Supplementary Data Table of Contents Sources of Change in Discounted Future Net Cash Flows Millions of Dollars Consolidated Operations Equity Affiliates Total Company 2024 2023* 2022 2024 2023 2022 2024 2023* 2022 Discounted future net cash flows at the beginning of the year $ 57,241 $ 85,720 52,695 $ 9,819 13,272 5,000 $ 67,060 98,992 57,695 Changes during the year Revenues less production costs for the year (23,410) (23,706) (33,532) (2,536) (2,550) (3,245) (25,946) (26,256) (36,777) Net change in prices, and production costs (10,025) (51,887) 61,902 (941) (4,519) 8,184 (10,966) (56,406) 70,086 Extensions, discoveries and improved recovery, less estimated future costs (1,015) 1,751 7,882 507 118 1,472 (508) 1,869 9,354 Development costs for the year 10,197 9,129 6,687 402 326 272 10,599 9,455 6,959 Changes in estimated future development costs (3,512) (6,754) (4,088) (274) (150) 189 (3,786) (6,904) (3,899) Purchases of reserves in place, less estimated future costs 11,068 3,024 3,353 — — 1,282 11,068 3,024 4,635 Sales of reserves in place, less estimated future costs (113) (446) (3,847) — — — (113) (446) (3,847) Revisions of previous quantity estimates 14,175 9,047 13,080 23 492 2,193 14,198 9,539 15,273 Accretion of discount 8,137 12,414 7,021 1,199 1,635 616 9,336 14,049 7,637 Net change in income taxes (14) 18,949 (25,433) (65) 1,195 (2,691) (79) 20,144 (28,124) Total changes 5,488 (28,479) 33,025 (1,685) (3,453) 8,272 3,803 (31,932) 41,297 Discounted future net cash flows at year end $ 62,729 $ 57,241 85,720 $ 8,134 9,819 13,272 $ 70,863 67,060 98,992 *Certain amounts in Consolidated Operations have been revised to reflect adjustments to the discounted future net cash flows. • 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. 157 ConocoPhillips 2024 10-K Table of Contents Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None.