Conocophillips,
Fiscal Year 2024.

ConocoPhillips 2024 10-K 36 Management's Discussion and Analysis Commodity Prices Our earnings and operating cash flows generally correlate with crude oil and natural gas commodity prices. Commodity price levels are subject to factors external to the company and over which we have no control, including but not limited to global economic health, supply or demand disruptions or fears thereof caused by civil unrest, global pandemics, military conflicts, actions taken by OPEC Plus and other major oil producing countries, environmental laws, tax regulations, governmental policies and weather-related disruptions. The following graph depicts the average benchmark prices for WTI crude oil, Brent crude oil and U.S. Henry Hub natural gas since 2022: Brent crude oil prices decreased two percent from $82.62 per barrel in 2023 to $80.76 per barrel in 2024. Similarly, average WTI crude oil prices decreased two percent from $77.62 per barrel in 2023 to $75.72 per barrel in 2024. Prices were lower through 2024 due to slower global demand growth in 2024 relative to 2023 and higher supplies from non-OPEC Plus counties. U.S. Henry Hub natural gas prices decreased 17 percent from an average of $2.74 per MMBTU in 2023 to $2.27 per MMBTU in 2024. Natural gas prices decreased due to excess North American natural gas storage levels following a mild 2023-2024 winter. Lower 48 segment realized gas prices decreased to $0.18 in the third quarter of 2024 driven by lower regional prices related to pipeline capacity constraints. In the fourth quarter of 2024 prices increased as constraints were relieved and realizations ended the year at an average of $0.87. Our realized bitumen price increased 14 percent from an average of $42.15 per barrel in 2023 to $47.92 per barrel in 2024. The increase was driven by narrowing WCS differentials due to Trans Mountain Expansion project egress, tightening Russian sanctions impacting global heavy oil supply and improving heavy oil demand in Asia. We continue to optimize bitumen price realizations through optimizing diluent recovery unit operation, blending and transportation strategies. Our worldwide annual average realized price decreased six percent from $58.39 per BOE in 2023 to $54.83 per BOE in 2024 primarily due to lower crude and natural gas prices. 37

Business Combination-Valuation of Oil and Gas Properties For business combinations, management applies the principles of acquisition accounting under FASB ASC Topic 805 - "Business Combinations" and allocates the purchase price to assets acquired and liabilities assumed, based on their estimated fair values as of the acquisition date. Estimating the fair values involves making various assumptions, of which the most significant assumptions relate to the fair values assigned to proved and unproved oil and gas properties. For significant business combinations, management generally utilizes a discounted cash flow approach, based on market participant assumptions, and considers engaging third party valuation experts in preparing fair value estimates. Significant inputs incorporated within the valuation include future commodity price assumptions and production profiles of reserve estimates, future operating and development costs, inflation rates, and discount rates using a market-based weighted average cost of capital determined at the time of the acquisition. When estimating the fair value of unproved properties, additional risk-weighting adjustments are applied to probable and possible reserves. The assumptions and inputs incorporated within the fair value estimates are subject to considerable management judgement and are based on industry, market and economic conditions prevalent at the time of the acquisition. Although we based these estimates on assumptions believed to be reasonable, these estimates are inherently unpredictable and uncertain and actual results could differ. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate is recorded. Subsequent to the acquisition date, and not later than one year from the acquisition date, we record any material adjustments to the initial estimate based on new information obtained that would have existed as of the date of the acquisition. Any adjustment that arises from information obtained that did not exist as of the date of acquisition is recorded in the period the adjustment arises. See Note 3.

•Competition and consolidation in the oil and gas E&P industry, including competition for sources of supply, services, personnel and equipment. •Any limitations on our access to capital or increase in our cost of capital or insurance, including as a result of illiquidity, changes or uncertainty in domestic or international financial markets, foreign currency exchange rate fluctuations or investment sentiment. •Challenges or delays to our execution of, or successful implementation of the acquisition of Marathon Oil or any future asset dispositions or acquisitions we elect to pursue; potential disruption of our operations, including the diversion of management time and attention; our inability to realize anticipated cost savings or capital expenditure reductions; difficulties integrating acquired businesses and technologies; or other unanticipated changes. •Our inability to deploy the net proceeds from any asset dispositions that are pending or that we elect to undertake in the future in the manner and timeframe we anticipate, if at all.

Production Total average production increased 85 MBOED in 2024 compared with 2023, primarily due to new wells online from our development programs in Delaware Basin, Eagle Ford, Midland Basin and Bakken and the impact from assets acquired from Marathon Oil. See Note 3.

$(880)(821)(330) Net interest consists of interest and financing expense, net of interest income and capitalized interest. Corporate G&A expenses include compensation programs and staff costs. These expenses increased by $359 million in 2024 compared with 2023, primarily due to transaction expenses of $432 million associated with our acquisition of Marathon Oil, partially offset by lower compensation and benefits costs, including mark-to-market impacts of certain key employee compensation programs. See Note 15. Technology includes our investments in low-carbon technology opportunities as well as other new technologies or businesses and licensing revenues. Other new technologies or businesses and LNG licensing activities are focused on both conventional and tight oil reservoirs, shale gas, oil sands, enhanced oil recovery as well as LNG. Earnings in Technology decreased due to increased costs in low-carbon and other new technologies and lower licensing revenues. Other income (expense) or "Other" includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, other costs not directly associated with an operating segment, gains or losses on early retirement of debt, holding gains or losses on equity securities and pension settlement expense. Earnings in "Other" increased by $422 million in 2024 compared with 2023. This was primarily due to a tax benefit of $455 million as a result of the acquisition of Marathon Oil and the subsequent utilization of foreign tax credits, and the absence of $89 million loss associated with forward foreign exchange contracts to buy CAD, in support of our acquisition of additional working interest in Surmont in 2023. Decreases to earnings in "Other" were driven by a loss of $147 million associated with the extinguishment of debt in the fourth quarter of 2024. See Note 3, Note 8 and Note 16.

ConocoPhillips 2024 10-K 50 Capital Resources and Liquidity Financing Activities In November 2024, we acquired Marathon Oil. At closing, the acquisition was valued at $16.5 billion and was allocated to assets acquired and liabilities assumed. ConocoPhillips common stock was issued and exchanged for outstanding Marathon Oil shares. With the acquisition, we also assumed Marathon Oil's debt of approximately $4.6 billion. See Note 3 and Note 8. Our debt balance at December 31, 2024 was $24.3 billion compared with $18.9 billion at December 31, 2023. The current portion of debt, including payments for finance leases, is $1.0 billion. In 2024, the company retired $726 million principal amount of Notes at maturity consisting of $265 million of our 3.35% Notes and $461 million of our 2.125% Notes. In addition, we completed concurrent debt transactions consisting of new long-term debt issuances of $5.2 billion; a $4.1 billion repurchase of certain existing Marathon Oil and ConocoPhillips debt (with priority for Marathon Oil debt assumed); a non-cash obligor exchange offer to retire $0.9 billion of Marathon Oil debt in exchange for new ConocoPhillips debt; and remarketing of $0.4 billion in available municipal bonds. The debt transactions simplified our capital structure, extended the debt portfolio's weighted average maturity, lowered its weighted average coupon and reduced near-term maturities. See Note 8. In 2023, we issued $2.7 billion principal amount of new debt to fund our acquisition of the remaining 50 percent working interest in Surmont and completed refinancing transactions consisting of $1.1 billion in tender offers to repurchase existing debt with cash and a $1.1 billion new debt issuance to fund the repurchases, extending the weighted average maturity of our portfolio from 15 to 17 years and reducing near-term debt maturities. See Note 8. In 2022, we repurchased notes, retired floating rate debt and executed a debt refinancing comprised of concurrent transactions including new debt issuances, a cash tender offer and debt exchange offers. In aggregate, these transactions along with naturally maturing debt, reduced the company's total debt by $3.3 billion. In 2022, we refinanced our revolving credit facility from a total aggregate principal amount of $6.0 billion to $5.5 billion with an expiration date of February 2027. Our revolving credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as support for our commercial paper program. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or any of its consolidated subsidiaries. The amount of the facility is not subject to redetermination prior to its expiration date. Credit facility borrowings may bear interest at a margin above the Secured Overnight Financing Rate (SOFR). The agreement calls for commitment fees on available, but unused, amounts. The 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 ConocoPhillips Company's ability to issue up to $5.5 billion of commercial paper, which is primarily a funding source for short-term working capital needs. Commercial paper maturities are generally limited to 90 days. 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.

Climate Change Continuing political and social attention to the issue of global climate change has resulted in a broad range of proposed or promulgated state, national and international laws focusing on GHG emissions reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. Examples of legislation and precursors for possible regulation that do or could affect our operations include: •European Emissions Trading Scheme (ETS), the program through which many of the EU member states are implementing the Kyoto Protocol. Our cost of compliance with the EU ETS in 2023 was approximately $28 million (net share before-tax). •U.K. Emissions Trading Scheme, the program with which the U.K. has replaced the ETS. Our cost of compliance with the U.K. ETS in 2023 was approximately $0.8 million (net share before-tax). •The Alberta Technology Innovation and Emissions Reduction (TIER) regulation requires any existing facility with emissions equal to or greater than 100,000 metric tonnes of carbon dioxide, or equivalent, per year to meet a facility benchmark intensity. The total cost of compliance related to this regulation in 2023 was approximately $3.5 million (net share before-tax). •The U.S. government has announced on September 17, 2021 the Global Methane Pledge, a global initiative to reduce global methane emissions by at least 30 percent from 2020 levels by 2030. •Carbon taxes in certain jurisdictions. Our cost of compliance with Norwegian carbon legislation in 2023 was approximately $35 million (net share before-tax). We also incur a carbon tax for emissions from fossil fuel combustion in our British Columbia and Alberta operations in Canada, totaling approximately $8.2 million (net share before-tax). •The agreement reached in Paris in December 2015 at the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change, setting out a process for achieving global emissions reductions. The new administration has recommitted the United States to the Paris Agreement, and a significant number of U.S. state and local governments and major corporations headquartered in the U.S. have also announced related commitments. Accordingly, the U.S. administration set a new target on April 22, 2021 of a 50 to 52 percent reduction in GHG emissions from 2005 levels in 2030. •The U.S. EPA announced the final New Source Performance Standards (OOOOb) and Emissions Guidelines (OOOOc) rulemaking on December 2, 2023. While industry is awaiting final publication of the rulemaking, we do anticipate that implementing this regulation across our U.S. portfolio will result in additional compliance costs. The proposed sub-part W regulations and the Methane Emission Reduction Program (MERP), passed as part of the Inflation Reduction Act of 2022 will potentially result in impacts to our business. The implementation of the MERP fee, while applicable for 2024 emissions, has not yet been finalized by the EPA.

◦Evaluating potential investments in emerging energy transition and low-carbon technologies. Our Plan does not include a Scope 3 (end-use) emissions target. We recognize that end-use emissions must be reduced to meet global climate objectives. However, it is our view that supply-side constraints through Scope 3 targets for North American and European upstream oil and gas producers would be counterproductive to climate goals. In the absence of policy measures that address global demand and with the shape and pace of technology and policy yet to be determined, setting and meeting Scope 3 targets would require a shift of production to other global operators that have established less ambitious targets or no targets to reduce their own operational emissions or do not have any other ambitions or plans to manage climate-related risks, potentially eroding energy security and affordability as well as undercutting global climate change objectives. This is why we have consistently taken a prominent role in advocating for a well-designed, economy wide price on carbon and engaged in development of other policies or legislation that could address end-use emissions from high-carbon intensity energy use. We have also expanded policy advocacy beyond carbon pricing to include regulatory action, such as support for the direct regulation of methane.

•The risk that we will be unable to retain and hire key personnel. •Uncertainty as to the long-term value of our common stock. •The factors generally described in Part I-Item 1A in this 2023 Annual Report on Form 10-K and any additional risks described in our other filings with the SEC.

Overview At ConocoPhillips, we anticipate that commodity prices will continue to be cyclical and volatile, and our view is that a successful business strategy in the E&P industry must be resilient in lower price environments while also retaining upside during periods of higher prices. As such, we are unhedged, remain committed to our disciplined investment framework and continually monitor market fundamentals, including the impacts associated with geopolitical tensions and conflicts, OPEC Plus supply updates, global demand for our products, oil and gas inventory levels, governmental policies, inflation and supply chain disruptions. The macro-environment of the global energy industry, including the energy transition, continues to evolve. We believe ConocoPhillips will continue to play an essential role by executing on three objectives: responsibly meeting energy transition pathway demand, delivering competitive returns on and of capital and achieving our net-zero operational emissions ambition. We call this our Triple Mandate, and it represents our commitment to create long-term value for our stakeholders. Our Triple Mandate and our foundational principles guide our differential value proposition to deliver competitive returns to stockholders through price cycles. Our foundational principles consist of maintaining balance sheet strength, providing peer-leading distributions, making disciplined investments, and demonstrating responsible and reliable ESG performance. Total company production in 2023 was 1,826 MBOED, yielding cash provided by operating activities of $20 billion. We invested $11.2 billion into the business in the form of capital expenditures and investments and provided returns of capital to shareholders of approximately $11 billion through our ordinary dividend, share repurchases and our VROC. For 2023, we returned $2.6 billion from our ordinary dividend, which included an increase from 51 cents per share to 58 cents per share, effective in December. We also returned $3.0 billion to shareholders from the VROC in 2023. In total for 2023, we returned $5.4 billion to shareholders through share repurchases. As of December 31, 2023, we have repurchased $28.8 billion of the $45 billion authorized share repurchase program. In February 2024, we announced our 2024 planned return of capital to shareholders of $9 billion through our three-tier return of capital framework. We also declared a first quarter ordinary dividend of 58 cents per share and a VROC of 20 cents per share. In March, the Department of Interior published its ROD approving our Willow project in Alaska, which adopted a plan consisting of three core pads. In December, following a Ninth Circuit Court of Appeals denial of a request for an injunction, we reached FID on the Willow project and began winter construction.

ConocoPhillips 2023 10-K 50 Capital Resources and Liquidity The level of absolute production volumes, as well as product and location mix, is another significant factor impacting our cash flows. Full-year production averaged 1,826 MBOED in 2023, an increase of 88 MBOED or 5 percent compared to 2022. First quarter 2024 production is expected to be 1.88 MMBOED to 1.92 MMBOED. Future production is subject to numerous uncertainties, including, among others, the volatile crude oil and natural gas price environment, which may impact investment decisions; the effects of price changes on production sharing and variable-royalty contracts; acquisition and disposition of fields; field production decline rates; new technologies; operating efficiencies; timing of startups and major turnarounds; political instability; weather-related disruptions; and the addition of proved reserves through exploratory success and their timely and cost-effective development. While we actively monitor and manage these factors, changes in production levels can cause variability in cash flows, although we generally experience less variability in our cash flows due to changes in production levels than due to changes in commodity prices. To maintain or grow our production volumes on an ongoing basis, we must continue to add to our proved reserve base. Our estimates of our proved reserves generally increase as of a specified date as prices rise and decrease as prices decline. Reserve replacement represents the net change in proved reserves, net of production, divided by our current year production. For information on proved reserves, including both developed and undeveloped reserves, see the reserve table disclosures contained in "Supplementary Data - Oil and Gas Operations." See "Item 1A-Risk Factors - Unless we successfully develop resources, the scope of our business will decline, resulting in an adverse impact to our business." As discussed in the "Critical Accounting Estimates" section, engineering estimates of proved reserves are imprecise; therefore, reserves may be revised upward or downward each year due to the impact of changes in commodity prices or as more technical data becomes available on reservoirs. It is not possible to reliably predict how revisions will impact future reserve quantities.

•S&P: "A-" with a "stable" outlook •Moody's: "A2" with a "stable" outlook See Note 9 for additional information on debt and the revolving credit facility. 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 rating 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. Certain of our project-related contracts, commercial contracts and derivative instruments contain provisions requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters of credit as collateral. At December 31, 2023 and December 31, 2022, we had direct bank letters of credit of $340 million and $368 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business. In the event of a credit rating downgrade, we may be required to post additional letters of credit.

Summarized Income Statement Data Millions of Dollars 2024 Revenues and Other Income$35,033 Income (loss) before income taxes*8,252 Net Income (Loss)9,245

*Includes approximately $8.6 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries. Summarized Balance Sheet Data

Millions of Dollars December 31, 2024 Current assets$6,077 Amounts due from Non-Obligated Subsidiaries, current319 Noncurrent assets120,845 Amounts due from Non-Obligated Subsidiaries, noncurrent11,719

Current liabilities4,504 Amounts due to Non-Obligated Subsidiaries, current935 Noncurrent liabilities64,088 Amounts due to Non-Obligated Subsidiaries, noncurrent41,826

•EU Trading Directive resulting in EU Emissions Trading Scheme (EU ETS). These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also establish standards and impose obligations for the remediation of releases of hazardous substances and hazardous wastes. In most cases, these regulations require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agency's processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant. Many states and foreign countries where we operate also have or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders. 55

Guidance for 2025 includes DD&A of $11.3 to $11.5 billion and capital expenditures of approximately $12.9 billion. Operating Segments We manage our operations through six operating segments, which are primarily defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International. Corporate and Other represents income and costs not directly associated with an operating segment, such as most interest income and expense; impacts from certain debt transactions; corporate overhead and certain technology activities, including licensing revenues; and unrealized holding gains or losses on equity securities. All cash and cash equivalents and short-term investments are included in Corporate and Other. Our key performance indicators, shown in the statistical tables provided at the beginning of the operating segment sections that follow, reflect results from our operations, including commodity prices and production.

Property Acquisition Costs For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For insignificant individual leasehold acquisition costs, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves, including estimates of future expirations, and pools that leasehold information with others in similar geographic areas. For prospects in areas with limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense. This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. At year-end 2024, we held $14.7 billion of net capitalized unproved property costs, $10.8 billion of which was added this year through our acquisition of Marathon Oil. These capitalized costs consist primarily of individually significant and pooled leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells currently being drilled, suspended exploratory wells and capitalized interest. Of this amount, approximately $13.4 billion is concentrated in the Lower 48 Basins, primarily the Delaware, Eagle Ford and Bakken Basins, where we have an ongoing significant and active development program. Outside of the Lower 48 Basins, the remaining $1.3 billion is primarily concentrated in Canada. Management periodically assesses our unproved property for impairment based on the results of exploration and drilling efforts and the outlook for commercialization.

Contingencies A number of claims and lawsuits are made against the company arising in the ordinary course of business. Management exercises judgment related to accounting and disclosure of these claims which includes losses, damages and underpayments associated with environmental remediation, tax, contracts and other legal disputes. As we learn new facts concerning contingencies, we reassess our position both with respect to amounts recognized and disclosed considering changes to the probability of additional losses and potential exposure; however, actual losses can and do vary from estimates for a variety of reasons including legal, arbitration or other third-party decisions; settlement discussions; evaluation of scope of damages; interpretation of regulatory or contractual terms; expected timing of future actions; and proportion of liability shared with other responsible parties. Estimated future costs related to contingencies are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes. For additional information on contingent liabilities, see the "Contingencies" section within "Capital Resources and Liquidity" and Note 10.

ConocoPhillips 2024 10-K 64 Cautionary Statement for the Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995 This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, costs and plans, objectives of management for future operations, the anticipated benefits of our acquisition of Marathon Oil, the anticipated impact of our acquisition of Marathon Oil on the combined company's business and future financial and operating results and the expected amount and timing of synergies from our acquisition of Marathon Oil are forward-looking statements. Examples of forward-looking statements contained in this report include our expected production growth and outlook on the business environment generally, our expected capital budget and capital expenditures, and discussions concerning development or replacement of reserves and future dividends. You can often identify our forward-looking statements by the words "ambition," "anticipate," "believe," "budget," "continue," "could," "effort," "estimate," "expect," "forecast," "goal," "guidance," "intend," "may," "objective," "outlook," "plan," "potential," "predict," "projection," "seek," "should," "target," "will," "would" and similar expressions. We based the forward-looking statements on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect or inaccurate, and involve risks and uncertainties we cannot predict. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors and uncertainties, including, but not limited to, the following: •Effects of volatile commodity prices, including prolonged periods of low commodity prices, which may adversely impact our operating results and our ability to execute on our strategy and could result in recognition of impairment charges on our long-lived assets, leaseholds and nonconsolidated equity investments. •Global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and gas, including changes as a result of any ongoing military conflict and the global response to such conflict; security threats on facilities and infrastructure; global health crises; the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC and other producing countries; or the resulting company or third-party actions in response to such changes. •The potential for insufficient liquidity or other factors, such as those described herein, that could impact our ability to repurchase shares and declare and pay dividends, whether fixed or variable. •Potential failures or delays in achieving expected reserve or production levels from existing and future oil and gas developments, including due to operating hazards, drilling risks and the inherent uncertainties in predicting reserves and reservoir performance.

•The operation, financing and management of risks of our joint ventures. •The ability of our customers and other contractual counterparties to satisfy their obligations to us, including our ability to collect payments when due from the government of Venezuela or PDVSA.

Consolidated Results Summary Operating Statistics 202420232022 Average Net Production Crude oil (MBD) Consolidated Operations969 923 885 Equity affiliates13 13 13

The increase in production during 2024 was partly offset by normal field decline. After adjusting for closed acquisitions and dispositions, production increased by 69 MBOED or three percent.

See Note 16-Income Taxes for information regarding our income tax provision and effective tax rate. 41 ConocoPhillips 2024 10-K Results of Operations Table of Contents

Total Production (MBOED) 194 195 200 Total Production (MMBOE) 71 71 73 Average Sales Prices Crude oil ($ per bbl)$81.73 83.05 101.72 Natural gas ($ per mcf)3.90 4.47 3.64 The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. In 2024, Alaska contributed 14 percent of our consolidated liquids production and two percent of our consolidated natural gas production.

Bitumen ($ per bbl)47.92 42.15 55.56 Natural gas ($ per mcf)*0.54 1.80 3.62 *Average sales prices include unutilized transportation costs. The Canada segment operations include the Surmont oil sands development in Alberta, the Montney unconventional play in British Columbia and commercial operations. In 2024, Canada contributed ten percent of our consolidated liquids production and five percent of our consolidated natural gas production.

Crude oil ($ per bbl)$80.92 83.96 99.20 Natural gas liquids ($ per bbl)40.29 41.13 54.52 Natural gas ($ per mcf)10.70 12.68 33.39 The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian sector of the North Sea, the Norwegian Sea, Qatar, Libya, Equatorial Guinea and commercial and terminalling operations in the U.K. In 2024, our Europe, Middle East and North Africa operations contributed nine percent of our consolidated liquids production and 17 percent of our consolidated natural gas production.

Balance Sheet related line items are shown as of December 31st. *Capital includes total debt and total equity. To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, including cash generated from operating activities, our commercial paper and credit facility programs and our ability to sell securities using our shelf registration statement. In 2024, the primary uses of our available cash were $12.1 billion to support our ongoing capital expenditures and investments program, which included $0.4 billion of spend related to fourth-quarter acquisitions; $5.5 billion to repurchase common stock; and $3.6 billion to pay the ordinary dividend and VROC. In addition to cash from operating activities, the other primary sources of capital were $5.6 billion in proceeds from long-term debt issuances, of which $4.1 billion was used to repurchase certain existing Marathon Oil debt assumed in the acquisition and ConocoPhillips debt; and $0.4 billion net sales of short-term investments. In 2024, cash and cash equivalents remained flat with 2023 at $5.6 billion. See Note 8. At December 31, 2024, we had cash and cash equivalents of $5.6 billion, short-term investments of $0.5 billion, and available borrowing capacity under our credit facility of $5.5 billion, totaling approximately $11.6 billion of liquidity. We believe current cash balances and cash generated by operations, together with access to external sources of funds as described below in the "Significant Changes in Capital" section, will be sufficient to meet our funding requirements in the near- and long-term, including our capital spending program, capital return program and required debt payments.

Significant Changes in Capital Operating Activities Cash provided by operating activities in 2024 totaled $20.1 billion, compared with $20.0 billion for 2023, and $28.3 billion for 2022. In 2024, cash provided by operating activities improved from 2023 due to increased production primarily from Canada and the Lower 48, including the Surmont 50 percent working interest acquired in the fourth quarter of 2023 and our acquisition of Marathon Oil in late 2024. The increase in production was partly offset by lower commodity prices and lower distributions from equity affiliates. See Note 3. The decrease in cash provided by operating activities from 2023 compared to 2022 is primarily due to lower realized commodity prices across all products, partly offset by higher sales volumes, net of associated production and operating costs. Our short- and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and NGLs. Prices and margins in our industry have historically been volatile and are driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows. 49

Investing Activities In 2024, we invested $12.1 billion in capital expenditures and investments; $0.8 billion of which was primarily payments towards our equity investments in LNG projects, including Port Arthur Liquefaction Holdings, LLC (PALNG), QatarEnergy LNG NFE(4) (NFE4) and QatarEnergy LNG NFS(3) (NFS3); and $0.4 billion of spend related to fourth-quarter acquisitions. See Note 3. The remaining $10.9 billion funded our operating capital program. Capital expenditures invested in 2023 and 2022 were $11.2 billion and $10.2 billion, respectively. See the "Capital Expenditures and Investments" section. In conjunction with the announcement of our acquisition of Marathon Oil, we communicated a disposition target of approximately $2 billion of assets across the portfolio. We recently entered into agreements to sell noncore assets within our Lower 48 segments that are expected to close in the first half of 2025 for approximately $600 million, subject to customary closing adjustments. See Note 3. After exercising our preferential rights, we completed an acquisition that increased our working interest by approximately five percent in the Kuparuk River Unit and approximately 0.4 percent in the Prudhoe Bay Unit in Alaska from Chevron U.S.A. Inc. and Union Oil Company of California in the fourth quarter of 2024 for $296 million before customary adjustments. See Note 3. In October 2023, we acquired the remaining 50 percent working interest in Surmont from TotalEnergies EP Canada Ltd. for approximately $2.7 billion of cash after customary adjustments. We funded this transaction by issuing new long-term debt. See Note 3 and Note 8. Proceeds from asset sales were $0.3 billion in 2024, $0.6 billion in 2023 and $3.5 billion in 2022. In 2022, we received proceeds of $1.4 billion for the sale of our remaining 91 million common shares of Cenovus Energy (CVE), proceeds of approximately $1.5 billion, primarily from asset divestitures in our Asia Pacific and Lower 48 segments, and $0.5 billion in contingent payments associated with prior divestitures. See Note 3 and Note 5. We invest in short-term investments as part of our cash investment strategy, the primary objective of which is to protect principal, maintain liquidity and provide yield and total returns; these investments include time deposits, commercial paper, as well as debt securities classified as available for sale. Funds for short-term investments needs to support our operating plan and provide resiliency to react to short-term price volatility are invested in highly liquid instruments with maturities within the year. Funds we consider available to maintain resiliency in longer term price downturns and to capture opportunities outside a given operating plan may be invested in instruments with maturities greater than one year. See Note 11 and Note 19. Investing activities in 2024 included net sales of $415 million of investments. We had net sales of $961 million of short-term investments and net purchases of $546 million of long-term investments. See Note 18.

In November 2024, Fitch affirmed our long-term credit rating. The current credit ratings on our long-term debt are: •Fitch: "A" with a "stable" outlook

Risks Related to Our Industry Our operating results, our ability to execute on our strategy and the carrying value of our assets are exposed to the effects of volatile commodity prices or prolonged periods of low commodity prices. Among the most significant factors impacting our revenues, operating results and future rate of growth are the sales prices for crude oil, bitumen, LNG, natural gas and NGLs. These prices are tied to market prices that can fluctuate widely due to factors beyond our control. For example, over the course of 2024, WTI crude oil prices ranged from a high of $87 per barrel in April to a low of $66 per barrel in September. Given the volatility in commodity price drivers and the worldwide political and economic environment, including potential economic slowdowns or recessions, unexpected shocks to supply and demand resulting from future global health crises, such as those that were experienced in connection with the COVID-19 pandemic, or increased uncertainty generated by armed hostilities and geopolitical tension in various oil-producing regions around the globe, prices for crude oil, bitumen, LNG, natural gas and NGLs may continue to be volatile. Prolonged periods of low commodity prices could have a material adverse effect on our revenues, operating income, cash flows and liquidity, and may also affect the amount of dividends we elect to declare and pay on our common stock and the amount of shares we elect to acquire as part of our share repurchase program and the timing of such repurchases. Lower prices may also limit the amount of reserves we can produce economically, thus adversely affecting our proved reserves and reserve replacement ratio and accelerating the reduction in our existing proved reserve levels as we continue production from upstream fields. Prolonged depressed prices may affect strategic decisions related to our operations, including decisions to reduce capital investments or curtail operated production. Significant reductions in crude oil, bitumen, LNG, natural gas and NGLs prices could also require us to reduce our capital expenditures, impair the carrying value of our assets or discontinue the classification of certain assets as proved reserves. Although it is not reasonably practicable to quantify the impact of any future impairments or estimated change to our unit-of-production rates at this time, our results of operations could be adversely affected as a result. If we do not successfully develop resources, the scope of our business will decline, and our financial condition and results of operations may be adversely affected. As we produce crude oil, bitumen, natural gas and NGLs from our existing portfolio, the amount of our remaining reserves declines. If we do not successfully replace the resources we produce with good prospects for future organic development or through acquisitions, our business will decline. In addition, our ability to successfully develop our reserves depends on our achievement of a number of operational and strategic objectives, some aspects of which are beyond our control, including navigating political and regulatory challenges to obtain and renew rights to develop and produce hydrocarbons; reservoir optimization; bringing long-lead time, capital intensive projects to completion on budget and on schedule; and efficiently and profitably operating mature properties. If we are not successful in developing the resources in our portfolio, our financial condition and results of operations may be adversely affected.

ConocoPhillips 2024 10-K 22 Risk FactorsTable of Contents For example, in 2024, New York and Vermont passed legislation seeking to hold certain energy companies financially responsible for state climate change mitigation and adaptation measures, following the "polluter pays" model of existing Superfund laws. This responsibility may include paying into a fund for infrastructure repairs and recovery from extreme weather events that would otherwise be covered by the government. While only two U.S. states have enacted such laws to date, other states have introduced similar measures, and it is likely that more states will consider a similar approach. Compliance with such legislation may expose us to significant additional liabilities. Furthermore, in December 2023, the EPA published a final rule that revises the regulations governing, among other things, the emission of methane and volatile organic compounds from new oil and gas production facilities and emission guidelines for states to use when revising Clean Air Act implementation plans to limit methane emissions from existing oil and gas facilities. Also pursuant to the Inflation Reduction Act of 2022, the EPA published certain rules in 2024 to facilitate the determination and payment of a charge on methane emissions from selected facilities in the oil and natural gas industry, including many of the facilities operated by ConocoPhillips. These final rules could result in additional capital expenditures and compliance, operating and maintenance costs, any of which may have an adverse effect on our business and results of operations. Additionally, in 2023, at the international community at the 28th Conference of the Parties (COP28), nearly 200 countries, including most of the countries in which we operate, renewed their commitment to deliver on the aims of the 2015 Paris Agreement. COP28 included a decision on the world's first 'global stocktake' to ratchet up climate action before the end of the decade - including a goal to triple renewable energy capacity by 2030 - and for the first time its final agreement explicitly recommended "transitioning away from fossil fuels in the energy system." The implementation of current agreements and regulatory or judicial measures, as well as any future agreements or measures addressing climate change and GHG emissions, may adversely increase our capital and operating expenses, impact the demand for our products, impose taxes on our products or operations, or require us to purchase emission credits or reduce emissions of GHGs from our operations. As a result, we may incur substantial capital expenditures and compliance, operating, maintenance and remediation costs, any of which may have an adverse effect on our business and results of operations. For more information on legislation or precursors for possible regulation relating to global climate change that affect or could affect our operations and a description of the company's response, see the "Contingencies-Climate Change" and "-Company Response to Climate-Related Risks" sections of Management's Discussion and Analysis of Financial Condition and Results of Operations. Broader investor and societal attention to and efforts to address global climate change may limit who can do business with us or our access to financial markets and could subject us to litigation. Increasing attention to global climate change has also resulted in pressure from and upon stockholders, financial institutions and other financial market participants to potentially limit or discontinue investments, insurance and funding to oil and gas companies. For example, a significant number of financial institutions have pledged to meet the goal of net zero by 2050, as well as setting interim targets for 2030 or earlier. While these targets do not prohibit financial sector stakeholders from doing business with oil and gas companies, stakeholders may self-impose limits. Conversely, we also face pressure from some in the investment community and certain public interest groups to limit the focus on ESG in our decision-making, arguing that ESG considerations do not relate to financial outcomes. As public pressure continues to mount on the financial sector, our costs of capital may increase. Furthermore, increasing attention to global climate change has resulted in an increased likelihood of governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business. Beginning in 2017 and continuing through 2024, cities, counties, governments and other entities in several states/territories in the U.S. have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged climate change impacts. Additional lawsuits with similar allegations are expected to be filed. The amounts claimed by plaintiffs are unspecified and the legal and factual issues involved in these cases are unprecedented. We believe these lawsuits are factually and legally meritless and are an inappropriate vehicle to address the challenges associated with climate change, and we will vigorously defend against such lawsuits. The ultimate outcome and impact to us cannot be predicted with certainty, and we expect to incur substantial legal costs associated with defending these and similar lawsuits in the future. We could also receive lawsuits alleging a failure or lack of diligence to meet our publicly stated ESG goals or alleging misrepresentation related to our ESG activity. 23

ConocoPhillips 2024 10-K Risk FactorsTable of Contents Political and economic developments could damage our operations and materially reduce our profitability and cash flows. Actions of the U.S., state, local and foreign governments, through sanctions, tax, tariffs and other legislation, executive orders and commercial restrictions, could reduce our operating profitability both in the U.S. and abroad. In certain locations, restrictions on our operations; leasing restrictions; special taxes or tax assessments; tariffs; and payment transparency regulations that could require us to disclose competitively sensitive information or might cause us to violate non-disclosure laws of other countries have been imposed or proposed by governments or certain interest groups. In addition, we may face regulatory changes in the U.S. including, but not limited to, the enactment of tax law changes that adversely affect the fossil fuel industry, new methane emissions standards, requirements restricting or prohibiting flaring and subsurface water disposal, more stringent environmental impact studies and reviews and policies inhibiting or curtailing LNG or crude oil exports. Similar regulatory shifts, including attendant higher costs and market access constraints, may also occur in international jurisdictions in which we currently operate or seek to operate. Hydraulic fracturing, an essential completion technique that facilitates production of oil and natural gas otherwise trapped in lower permeability rock formations, has historically attracted political and regulatory scrutiny. A range of local, state, federal and national laws and regulations currently govern, constrain or prohibit hydraulic fracturing in some jurisdictions. New or more stringent permitting, disclosure or other regulatory requirements on hydraulic fracturing or other oil and natural gas operations, including subsurface water disposal, could result in increased costs, operating restrictions or operational delays or could limit the ability to develop oil and natural gas resources. In addition, certain interest groups have also proposed ballot initiatives, contested lease sales and challenged project permits, for example, to restrict oil and natural gas development generally as well as specific projects, including the Willow project in Alaska. In the event that ballot initiatives, local, state, or national restrictions or prohibitions are adopted and result in more stringent limitations on the production and development of oil and natural gas in areas where we conduct operations, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the permitting or pursuit of exploration, development or production activities. Such compliance costs and delays, curtailments, limitations or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, liquidity and ability to implement and advance the Climate Risk Strategy.

ConocoPhillips 2024 10-K Risk FactorsTable of Contents In addition, we are regularly evaluated by the major rating agencies based on a number of factors, including our financial strength and conditions affecting the oil and gas industry generally. We and other industry companies have had our ratings reduced in the past due to negative commodity price outlooks. These major rating agencies are now considering ESG attributes when assessing credit profiles. While these assessments have limited impact today, they have the potential to pressure credit ratings over time. Any downgrade in our credit rating or announcement that our credit rating is under review for possible downgrade could increase the cost associated with any additional indebtedness we incur. Our business may be adversely affected by deterioration in the credit quality of, or defaults under our contracts with, third parties with whom we do business. The operation of our business requires us to engage in transactions with numerous counterparties operating in a variety of industries, including other companies operating in the oil and gas industry. These counterparties may default on their obligations to us as a result of operational failures or a lack of liquidity, or for other reasons, including bankruptcy. Market speculation about the credit quality of these counterparties, or their ability to continue performing on their existing obligations, may also exacerbate any operational difficulties or liquidity issues they are experiencing. Any default by any of our counterparties may result in our inability to perform our obligations under agreements we have made with third parties or may otherwise adversely affect our business or results of operations. In addition, our rights against any of our counterparties as a result of a default may not be adequate to compensate us for the resulting harm caused or may not be enforceable at all in some circumstances. We may also be forced to incur additional costs as we attempt to enforce any rights we have against a defaulting counterparty, which could further adversely impact our results of operations.

ConocoPhillips 2024 10-K 20 Risk FactorsTable of Contents Our business may be adversely affected by price controls; government-imposed limitations on production or exports of crude oil, bitumen, LNG, natural gas and NGLs; or the unavailability of adequate gathering, processing, compression, transportation, and pipeline facilities and equipment for our production of crude oil, bitumen, natural gas and NGLs. As discussed herein, our operations are subject to extensive governmental regulations across numerous jurisdictions. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil, bitumen, natural gas and NGLs wells below actual production capacity. Similarly, in response to increased domestic energy costs, circumstances determined to be in the economic or other interest of the country, or a declared national emergency, governments could restrict the export or import of our products which would adversely impact our business. For example, in January 2024, in response to concerns from environmental groups, the U.S. announced a temporary pause on new authorizations of certain LNG exports. The pause was subsequently lifted in January 2025. This pause and other difficulties in the regulatory approval processes may have an extended adverse impact on our global LNG business. Furthermore, because legal requirements are frequently changed and subject to interpretation, we cannot predict whether future restrictions on our business may be enacted or become applicable to us. Our ability to sell and deliver the crude oil, bitumen, LNG, natural gas and NGLs that we produce also depends on the availability, proximity and capacity of gathering, processing, compression, transportation and pipeline facilities and equipment, as well as any necessary diluents to prepare our crude oil, bitumen, LNG, natural gas and NGLs for transport. The facilities, equipment and diluents we rely on may be temporarily unavailable to us due to market conditions, extreme weather events, permitting delays and other regulatory matters, mechanical reasons or other factors or conditions, many of which are beyond our control. In addition, in certain newer plays, the capacity of necessary facilities, equipment and diluents may not be sufficient to accommodate production from existing and new wells, and construction and permitting delays, permitting costs and regulatory or other constraints could limit or delay the construction, manufacture or other acquisition of new facilities and equipment. If any facilities, equipment or diluents, or any of the transportation methods and channels that we rely on become unavailable for any period of time, we may incur increased costs to transport our crude oil, bitumen, LNG, natural gas and NGLs for sale; we may be forced to curtail our production of crude oil, bitumen, natural gas or NGLs, or we may not be able to meet all the objectives in our Climate Risk Strategy, such as reducing routine flaring.

We may need additional capital in the future, and it may not be available on acceptable terms or at all. We have historically relied primarily upon cash generated by our business to fund our operations and strategy; however, we have also relied from time to time on access to the capital markets for funding. There can be no assurance that additional financing will be available in the future on acceptable terms or at all. In addition, although we anticipate we will be able to repay our existing indebtedness when it matures or in accordance with our stated plans, there can be no assurance we will be able to do so. Our ability to obtain additional financing or refinance our existing indebtedness when it matures or in accordance with our plans, will be subject to a number of factors, including market conditions, our operating performance, investor sentiment, risks impacting financial institutions and the credit markets more broadly and financial institution policies regarding the oil and gas industry. If we are unable to generate sufficient funds from operations or raise additional capital for any reason, our business could be adversely affected. In addition, we are regularly evaluated by the major rating agencies based on a number of factors, including our financial strength and conditions affecting the oil and gas industry generally. We and other industry companies have had our ratings reduced in the past due to negative commodity price outlooks. These major rating agencies are now considering ESG attributes when assessing credit profiles. While these assessments have limited impact today, they have the potential to pressure credit ratings over time. Any downgrade in our credit rating or announcement that our credit rating is under review for possible downgrade could increase the cost associated with any additional indebtedness we incur. 25

Our operations are subject to hazards and risks that require significant and continuous oversight. Our operations are subject to a variety of hazards and risks that require significant and continuous oversight, such as the monitoring, prevention or mitigation of or protection from explosions, fires, product spills, severe weather, geological events, global health crises, such as epidemics and pandemics, labor disputes, geopolitical tensions, armed hostilities, terrorist or piracy attacks, sabotage, civil unrest or cyberattacks. Our operations are subject to additional hazards concerning exposure to and potential release of pollutants and toxic substances, as well as other environmental hazards and risks. For example, offshore activities may pose incrementally greater risks because of complex subsurface conditions such as higher reservoir pressures, water depths and metocean conditions. All such hazards could result in loss of human life, significant property and equipment damage, environmental pollution, impairment of operations, substantial losses to us and damage to our reputation. Our business and operations may be disrupted if we do not respond, or are perceived not to respond, in an appropriate manner to any of these hazards and risks or any other major crisis or if we are unable to efficiently restore or replace affected operational components and capacity. Countermeasures to address global health crises, epidemics or pandemics, including future outbreaks of COVID-19, may result in reduced demand for our products; disruptions to our supply chain, the global economy or financial or commodity markets; disruptions in our contractual arrangements with our service providers, suppliers and other counterparties; failures by our suppliers, contract manufacturers, contractors, joint venture partners and external business partners, to meet their obligations to us; reduced workforce productivity; and voluntary or involuntary curtailments. Further, our insurance may not be adequate to compensate us for all resulting losses described above, and the cost to obtain adequate coverage may increase for us in the future or may not be available. In addition, although we design and operate our business operations to accommodate expected climatic conditions, to the extent there are significant changes in the earth's climate, such as more severe or frequent weather conditions in the markets where we operate or the areas where our assets reside, we could incur increased expenses, our operations and supply chain could be adversely impacted and demand for our products could fall. Any of these factors, or other cascading effects of such factors, could materially increase our costs; negatively impact our revenues or ability to implement and advance the Plan; and damage our financial condition, results of operations, cash flows and liquidity position. The full extent and duration of any such impacts cannot be predicted at this time because of the lack of certainty surrounding their sources, causes and outcomes.

•The dismantlement, abandonment and restoration of historic properties and facilities at the end of their useful lives; and •Exploration and production activities in certain areas, such as offshore environments, arctic fields, oil sands reservoirs and unconventional plays. We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations. In addition, to the extent these expenditures are assumed by a buyer as a result of a disposition, it may result in our incurring substantial costs if the buyer is unable to satisfy these obligations. Any actual or perceived failure by us to comply with existing or future laws, regulations and other requirements could result in administrative or civil penalties, criminal fines, other enforcement actions or third-party litigation against us. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products, our business, financial condition, results of operations and cash flows in future periods as well as our ability to implement and advance the Plan could be adversely affected. Existing and future laws, regulations and internal initiatives relating to global climate change, such as limitations on GHG emissions, may impact or limit our business plans, result in significant expenditures, promote alternative uses of energy or reduce demand for our products. Continuing political and societal attention to the issue of global climate change has resulted in both existing and pending international agreements and national, regional or local legislation and regulatory measures to limit GHG emissions, such as cap and trade regimes, specific emission standards, carbon taxes, restrictive permitting, increased fuel efficiency standards, and incentives or mandates for renewable and alternative energy. Although we may support the intent of legislative and regulatory measures aimed at addressing climate-related risks, the specifics of how and when they are enacted could result in a material adverse effect to our business, financial condition, results of operations and cash flows in future periods as well as our ability to implement and advance the Plan. For example, in December 2023, the EPA published a final rule that revises the regulations governing, among other things, the emission of methane and volatile organic compounds from new oil and gas production facilities, and emission guidelines for states to use when revising Clean Air Act implementation plans to limit methane emissions from existing oil and gas facilities. The final rule could result in additional capital expenditures and compliance, operating and maintenance costs, any of which may have an adverse effect on our business and results of operations. Additionally, in 2023, the U.S. joined the international community at the 28th Conference of the Parties (COP28), where the U.S. and nearly 200 other countries, including most of the countries in which we operate, renewed their commitment to deliver on the aims of the 2015 Paris Agreement. COP28 included a decision on the world's first 'global stocktake' to ratchet up climate action before the end of the decade - including a goal to triple renewable energy capacity by 2030 - and for the first time its final agreement explicitly recommended "transitioning away from fossil fuels in the energy system." The implementation of current agreements and regulatory measures, as well as any future agreements or measures addressing climate change and GHG emissions, may adversely increase our capital and operating expenses, 23

Political and economic factors in international markets could have a material adverse effect on us. Approximately 32 percent of our hydrocarbon production was derived from production outside the U.S. in 2024, and 32 percent of our proved reserves, as of December 31, 2024, were located outside the U.S. We are subject to risks associated with our operations in foreign jurisdictions and international markets, including changes in foreign governmental policies relating to crude oil, bitumen, LNG, natural gas or NGLs pricing and taxation; other regulatory or economic developments (including the macro effects of international trade policies and disputes); disruptive geopolitical conditions such as the escalation of geopolitical tension in the Middle East in late 2023 and through 2024; and international monetary and currency rate fluctuations. Restrictions on production of oil and gas could increase to the extent governments view such measures as a viable approach for pursuing national and global energy security and climate policies. In addition, some countries where we operate lack a fully independent judiciary system. This, coupled with changes in foreign law or policy, results in a lack of legal certainty that exposes our operations to increased risks, including increased difficulty in enforcing our agreements in those jurisdictions and increased risks of adverse actions by local government authorities, such as expropriations. Actions by host governments, such as the expropriation of our oil assets by the Venezuelan government, have affected operations significantly in the past and may continue to do so in the future. In addition, the U.S. government has the authority to prevent or restrict us from doing business in foreign jurisdictions or with certain parties. These restrictions and similar restrictions imposed by foreign governments have in the past limited our ability to operate in, or gain access to, opportunities in various jurisdictions. Diplomatic relations or policies between the U.S. government and one or more foreign jurisdictions may increase our expenses or impair our ability to collect awards in legal actions against such foreign jurisdictions. Changes in domestic and international policies and regulations may also restrict our ability to obtain or maintain licenses or permits necessary to operate in foreign jurisdictions, including those necessary for drilling and development of wells. Similarly, the declaration of a "climate emergency" could result in actions to limit exports of our products and other restrictions.

•Our operating expenses; and •Other factors our Board of Directors deems relevant. We paid a quarterly VROC to our shareholders in the first three quarters of 2024. In the fourth quarter of 2024, we declared an ordinary dividend that incorporated the prior VROC equivalent per share payment and did not make a separate VROC payment. VROC distributions remain an option in elevated price environments, to be authorized and determined by our Board of Directors in its sole discretion and depending on factors it deems relevant. Our Board may determine not to pay a dividend in a quarter or may cease declaring a dividend at any time. Additionally, as of December 31, 2024, $30.7 billion of repurchase authority remained. 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. Our share repurchase program does not obligate us to acquire a specific number of shares during any period, and our decision to commence, discontinue or resume repurchases in any period will depend on the same factors that our Board of Directors may consider when declaring dividends, among other factors. In the past, we have suspended our share repurchase program in response to market downturns, including as a result of the oil market downturn that began in early 2020, and we may do so again in the future. Any downward revision in the amount of our ordinary dividend or the volume of shares we purchase under our share repurchase program could have an adverse effect on the market price of our common stock.

The exploration and production of oil and gas is a highly competitive industry. The exploration and production of crude oil, bitumen, natural gas and NGLs is a highly competitive business. We compete with private, public and state-owned companies in all facets of the exploration and production business, including locating, acquiring and developing new sources of supply and producing crude oil, bitumen, natural gas and NGLs in an efficient, cost-effective manner. In addition, we anticipate the oil and gas industry will face additional competition from alternative fuels. We must also compete for the materials, equipment, services, employees and other personnel (including geologists, geophysicists, engineers and other specialists) necessary to conduct our business. If we are not successful in any facet of this competition, our financial condition and results of operations may be adversely affected. 19

•Threats to the security of our facilities and infrastructure; and •Cyber terrorism. In addition, we have exposure to cybersecurity risks where our data and proprietary information are collected, hosted, and/or processed by third-party cloud and service providers. In addition, many of our vendors, including suppliers that are closely integrated into our business, have been victims of cybersecurity attacks that have accessed and exfiltrated information from their systems. Our risks may be exacerbated by a delay or failure to detect a cybersecurity incident or understand the full extent of such incident notwithstanding our risk management processes and controls. We face risks associated with new and ever-increasing phishing techniques, hidden malware, as well as risks associated with electronic data proliferation and technology digitization. We also face increased risk with the increased sophistication of generative artificial intelligence capabilities, which may improve or expand the existing capabilities of cybercriminals described above in a manner we cannot predict at this time. Our increasing reliance on IT in our production, distribution and marketing systems may allow cybersecurity threats to disrupt our oil and gas operations, both domestically and abroad. If our data, IT, operational technology (OT), including industrial control and supervisory control and data acquisition (SCADA) systems were to be breached, damaged or disrupted due to a cybersecurity incident or cyber-attack (directly, indirectly through third parties or through the IT networks, servers, software, or infrastructure on which they rely), we could be subject to serious negative consequences. These consequences could include physical damage to production, distribution or storage assets; delay or prevention of delivery to markets; disruption or prevention of accurate accounting for production and settlement of transactions; negative impacts on public health, safety, the environment, economic security, or national security; financial impacts; business interruption; reputational damage; loss of employee, supplier, contractor, partner and/or public trust; reimbursement or other costs; increased compliance costs; regulatory investigations; litigation exposure and legal liability or regulatory fines; penalties or other external intervention. Although we have business continuity plans in place, our operations may be adversely affected by significant and widespread disruption to our systems and infrastructure that support our business. If we seek insurance against cybersecurity risks, it may be limited by the availability and increasing expense of sufficient coverage.

ConocoPhillips 2024 10-K Risk FactorsTable of Contents Our ability to successfully execute on our plans to reduce operational GHG emissions intensity is subject to a number of risks and uncertainties and such reductions may be costly and challenging to achieve. Our framework for managing climate-related business risk is set out in our Climate Risk Strategy, which describes our strategic flexibility, approach to reducing Scope 1 and 2 emissions intensity, technology choices and engagement efforts. Among other things, we have set near- and medium-term GHG intensity reduction targets, as well as targets around flaring and methane. Our ability to achieve the stated targets, goals and ambitions within the Climate Risk Strategy's framework is subject to a number of risks and uncertainties beyond our control, including government policies and markets, acceptance of carbon capture technologies, development of markets and potential permitting and regulatory changes, all of which may impair our ability to execute on current or future plans. In addition, the pace of development of effective emissions measurement and abatement technologies, and the actual pace of development may be inadequate, or the technologies actually developed may be insufficient to allow us to achieve our stated targets, goals and ambitions. Furthermore, executing our Climate Risk Strategy could be costly, is likely to encounter unforeseen obstacles, will proceed at varying paces and may be accomplished in a manner that we cannot predict at this time. We expect to be required to purchase emission credits and/or offsets in the future. There may be an insufficient supply of offsets, and we could incur increasingly greater expenses related to our purchase of such offsets. Even if we are able to acquire an adequate amount of such offsets at satisfactory prices, investors, regulators or other third parties may not perceive this practice as an acceptable means of achieving our emission reduction goals. As advanced technologies are developed to accurately measure emissions, we may be required to revise our emissions estimates and reduction goals or otherwise revise aspects of our Climate Risk Strategy. We may be adversely affected and potentially need to reduce economic end-of-field life of certain assets and impair associated net book value due to the emissions intensity of some of our assets. Even if we meet our goals, our efforts may be characterized as insufficient. In early 2021, we established a multidisciplinary Low Carbon Technologies organization with the remit of supporting our emissions reduction objectives, understanding the alternative energy landscape and prioritizing opportunities for future competitive investment. Such potential investments may expose us to numerous financial, legal, operational, reputational and other risks. While we perform a thorough analysis on these investments, the related technologies and markets are at early stages of development and we do not yet know what rate of return we will achieve, if any, and we may suspend our evaluation or investment if we determine that applicable markets have not developed at the pace required to support further investment. For example, as a result of the hydrogen and ammonia markets not developing at a pace required to support further investment, in 2024 we decided to suspend our evaluation of a low-carbon ammonia production facility on the U.S. Gulf Coast. Furthermore, we may not be able to scale potential investments. The success of our low-carbon strategy will depend in part upon the cooperation of government agencies, the support of stakeholders, the development of relevant markets for low carbon fuels, our ability to research and forecast potential investments, willingness of industry partners to collaborate and our ability to apply our existing strengths and expertise to new technologies, projects and markets. Estimates of crude oil, bitumen, natural gas and NGL reserves are imprecise and may be subject to revision, and any material change in the factors and assumptions underlying our estimates of crude oil, bitumen, natural gas and NGL reserves could impair the quantity and value of those reserves. Our proved reserve information included in this annual report represents management's best estimates based on assumptions, as of a specified date, of the volumes to be recovered from underground accumulations of crude oil, bitumen, natural gas and NGLs. Such volumes cannot be directly measured, and the estimates and underlying assumptions used by management are subject to substantial risk and uncertainty. Any material changes in the factors and assumptions underlying our estimates of these items could result in a material negative impact to the volume of reserves reported or could cause us to incur impairment expenses on property associated with the production of those reserves. Future reserve revisions could also result from changes in, among other things, governmental regulation and commodity prices. For more information on estimates used, see the "Critical Accounting Estimates" section of Management's Discussion and Analysis of Financial Condition and Results of Operations.

Legal and Regulatory Risks We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations. Our business is subject to numerous laws and regulations relating to the protection of the environment, which are expected to continue to have an increasing impact on our operations. For a description of the most significant of these environmental laws and regulations, see the "Contingencies-Environmental", "-Climate Change" and "-Company Response to Climate-Related Risks" sections of Management's Discussion and Analysis of Financial Condition and Results of Operations. These laws and regulations continue to increase in both number and complexity and affect our operations with respect to, among other things: •Permits required in connection with exploration, drilling, production and other activities, including those issued by national, subnational and local authorities; •The discharge of pollutants into the environment; •Emissions into the atmosphere, such as nitrogen oxides, sulfur dioxide, mercury and GHG emissions, including methane and carbon dioxide; •Carbon taxes; •The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous and nonhazardous wastes;

Items 1 and 2. Business and Properties Corporate Structure ConocoPhillips is an independent E&P company headquartered in Houston, Texas with operations and activities in 14 countries. Our diverse, low cost of supply portfolio includes resource-rich unconventional plays in North America; conventional assets in North America, Europe, Africa and Asia; LNG developments; oil sands in Canada; and an inventory of global exploration prospects. On December 31, 2024, we employed approximately 11,800 people worldwide and had total assets of about $123 billion. Total company production for the year was 1,987 MBOED. ConocoPhillips was incorporated in the state of Delaware in 2001, in connection with, and in anticipation of, the merger between Conoco Inc. and Phillips Petroleum Company. The merger between Conoco and Phillips was consummated on August 30, 2002. In April 2012, ConocoPhillips completed the separation of the downstream business into an independent, publicly traded energy company, Phillips 66. On November 22, 2024, we completed our acquisition of Marathon Oil Corporation (Marathon Oil), an independent oil and gas exploration and production company with operations in multiple basins in the Lower 48, as well as Equatorial Guinea internationally. For additional information related to this transaction, see Note 3.

Segment and Geographic Information ConocoPhillips 2024 10-K 2 Business and PropertiesTable of Contents 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. For operating segment and geographic information, see Note 23. We explore for, produce, transport and market crude oil, bitumen, natural gas, NGLs and LNG on a worldwide basis. At December 31, 2024, our operations were producing in the U.S., Norway, Canada, Australia, Malaysia, Libya, China, Qatar and Equatorial Guinea. The information listed below appears in the "Supplementary Data - Oil and Gas Operations" disclosures following the Notes to Consolidated Financial Statements and is incorporated herein by reference:

Penglai49.0 %CNOOC33 - - 33 Penglai The Penglai 19-3, 19-9 and 25-6 fields are located in the Bohai Bay Block 11/05 and are being developed in stages from large offshore platforms and a FPSO. Most of the crude oil produced from the block is sold to the domestic market in China, with the remainder exported to international markets. Phase 3 consists of three wellhead platforms and a central processing platform. First production was achieved in 2018 and as of December 2024, all 186 wells have been completed and brought online. Phase 4A consists of one wellhead platform. First production was achieved in 2020 and as of December 2024, all 62 wells have been completed and brought online. Phase 4B consists of two wellhead platforms. First production was achieved in the fourth quarter of 2023. This project could include up to 144 new wells, 41 of which have been completed and brought online as of December 2024. Phase 5 consists of two new wellhead platforms and four wellhead platform expansions. First production was achieved in the fourth quarter of 2024. This project could include up to 91 new wells, 10 of which have been completed and brought online as of December 2024.

ConocoPhillips 2024 10-K 12 Business and PropertiesTable of Contents KBBC We own a 30 percent working interest in the KBB, Kamunsu East and Kamunsu East Upthrown Canyon gas and condensate fields. KBBC was previously operated by a joint operating company, Kebabangan Petroleum Operating Company, and in January 2025, we became the sole operator of KBBC. There was no change to working interest as part of ConocoPhillips becoming sole operator.

Exploration We operate three exploration PSCs with 85 percent working interest in Block SK304, 50 percent working interest in Block WL4-00 and 35 percent working interest in the Ubah Cluster. Off the coast of Sarawak, offshore Malaysia, Block SK304 encompasses 1.8 million net acres and Block WL4-00 encompasses 0.3 million net acres. Off the coast of Sabah, offshore Malaysia near the KBBC, the Ubah Cluster encompasses 11 thousand net acres. We continue to evaluate these blocks and are using information from seismic and prior well results to help optimize future plans. In 2021, we were awarded operatorship and an 85 percent working interest in Block SB405 encompassing 1.2 million net acres off the coast of Sabah, offshore Malaysia. A 3D seismic survey was acquired in 2022, and processing and evaluation work was completed in 2024. In the fourth quarter of 2024, we elected not to proceed to the second phase of exploration for SB405 PSC and relinquished the block.

All Employees73 %27 %67 %33 % All Leadership74 26 75 25 Top Leadership74 26 81 19 Junior Leadership74 26 74 26 *"POC" refers to People of Color or racial and ethnic minorities self-reported in the U.S.

OtherVariousEquinor5 - 15 7 Total Norway64 4 279 115 Greater Ekofisk Area The Greater Ekofisk Area is located offshore Stavanger, Norway, in the North Sea, and is comprised of five producing fields. Crude oil is exported to our operated terminal located at Teesside, U.K., and the natural gas is exported to Emden, Germany. The Tommeliten A development, a new subsea tieback to Ekofisk, achieved first production in 2023, and the Eldfisk North subsea development will be tied back to Eldfisk, with first production expected in 2024.

Alvheim Field The Alvheim Field is located in the northern part of the North Sea and consists of a FPSO vessel and subsea installations. Produced crude oil is exported via shuttle tankers and natural gas is transported to the Scottish Area Gas Evacuation (SAGE) Terminal at St. Fergus, U.K., through the SAGE Pipeline. The Kobra East and Gekko (KEG) project, a new subsea tieback to the Alvheim FPSO, achieved first production in 2023.

For additional information, see Note 3, Note 4 and Note 10. Exploration We own an 80 percent working interest in both Exploration Permit (T/49P) and (VIC/P79) located in the Otway Basin, Australia. Existing seismic data for both permits is being evaluated for future exploration drilling opportunities. During 2023, we executed a drilling consortium agreement with other operators in Australia and secured a contract for a semi-sub drilling rig. The proposed exploration program involves seabed surveys and two exploration wells planned for 2025. 11

ConocoPhillips 2023 10-K Business and PropertiesTable of Contents Human Capital Management Values, Principles and Governance At ConocoPhillips, our strategy, performance, culture and reputation are fueled by our workforce. We recognize that attracting, retaining, and developing talent is a competitive imperative within our changing industry. Our human capital management (HCM) approach starts with a foundation in our core SPIRIT Values - Safety, People, Integrity, Responsibility, Innovation, and Teamwork. These SPIRIT Values set the tone for how we interact with all of our internal and external stakeholders. We believe a safe organization is a successful organization, and therefore, we prioritize personal and process safety across the company. Our SPIRIT Values are a source of pride. Our day-to-day work is guided by the principles of accountability and performance, which means the way we do our work is as important as the results we deliver. We believe these core values and principles set us apart, align our workforce and provide a foundation for our culture. Our Executive Leadership Team (ELT) and our Board of Directors play a key role in setting our HCM strategy and driving accountability for meaningful progress. The ELT and Board of Directors engage often on workforce-related topics. Our HCM programs are overseen and administered by our human resources function with support from business leaders across the company. We depend on our workforce to successfully execute our company's strategy and we recognize the importance of creating a workplace where our people feel valued. Our HCM programs are built around three pillars that we believe are necessary for success: a compelling culture, attracting a world-class workforce and valuing our people. Each of these pillars is described in more detail below.

Health, Safety and Environment Our HSE organization sets expectations and provides tools and assurance to our workforce to promote and achieve HSE excellence. We manage and assure ConocoPhillips HSE policies, standards and practices, to help ensure business activities are consistently safe, healthy and conducted in an environmentally and socially responsible manner across the globe. Each business unit manages its local operational risks with particular attention to process safety, occupational safety and environmental and emergency preparedness risk. Objectives, targets and deadlines are set and tracked annually to drive strong HSE performance. Progress is tracked and reported to our ELT and the Board of Directors. HSE audits are conducted on business units and staff groups to ensure conformance with ConocoPhillips HSE policies, standards and practices where improvement actions are identified and tracked to completion. We continuously look for ways to operate more safely, efficiently and responsibly. We focus on reducing human error by emphasizing interaction among people, equipment and work processes. We believe our HSE policies such as Life Saving Rules, Process Safety Fundamentals, safety procedures and our stop work policy can reduce the likelihood and severity of unexpected incidents. We conduct thorough investigations of all serious incidents to understand the root cause and share lessons learned globally to improve our facility designs, procedures, training, maintenance programs and designs. It is important that we drive an HSE culture of continuous learning and improvement, refine our existing HSE processes and tools and enhance our commitment to safe, efficient and responsible operations.

Compensation, Benefits and Well-Being We offer competitive, performance-based compensation packages and have global equitable pay practices. Our compensation programs are generally comprised of a base pay, the annual Variable Cash Incentive Program (VCIP) and, for eligible employees, the Restricted Stock Unit (RSU) program. From the CEO to the frontline worker, every employee participates in VCIP, our annual incentive program, which aligns employee compensation with ConocoPhillips' success on critical performance metrics and also recognizes individual performance. Our RSU program is designed to attract and retain employees, reward performance and align employee interest with stockholders by encouraging stock ownership. Our retirement and savings plans are intended to support the financial futures of our employees and are competitive within local markets. We routinely benchmark our global compensation and benefits programs to ensure they are competitive, inclusive, aligned with company culture and allow our employees to meet their individual needs and the needs of their families. We provide flexible work schedules and competitive time off, including parental leave policies in many locations. We also offer employees flexibility through the Hybrid Office Work (HOW) program in all of our global locations, which provides eligible employees a combination of work from both office and home. We also provide coverage for families requiring disability support, elder care and childcare, including onsite childcare, where access locally is a challenge. Our global wellness programs include biometric screenings and fitness challenges designed to educate and promote a healthy lifestyle. All employees have access to our employee assistance program, and many of our locations offer custom programs to support mental well-being.

Greater Prudhoe Area The Greater Prudhoe Area includes the Prudhoe Bay Unit, which consists of the Prudhoe Bay Field and five satellite fields, as well as the Greater Point McIntyre Area fields. Prudhoe Bay, the largest conventional oil field in North America, is the site of a large waterflood and enhanced oil recovery operation, supported by a large gas and water processing operation. Field installations include seven production facilities, two gas plants, two seawater plants and a central power station. In 2024, on average, there were two rigs drilling throughout the year.

Greater Kuparuk Area The Greater Kuparuk Area includes the Kuparuk River Unit, which consists of the Kuparuk Field and six satellite fields. Field installations include three central production facilities which separate oil, natural gas and water, and a seawater treatment plant. In 2024, we operated two drilling rigs and two workover rigs. The Nuna project, which targets the Moraine reservoir, was sanctioned in 2023 and achieved first oil in the fourth quarter of 2024. The Coyote reservoir discovered in 2021 progressed to development in 2023 with additional wells drilled in 2024 and planned for 2025.

ConocoPhillips 2024 10-K 4 Business and PropertiesTable of Contents Western North Slope The Western North Slope includes the Colville River Unit, the Greater Mooses Tooth Unit and the Bear Tooth Unit. In 2024, we operated one full-time drilling rig and one seasonal drilling rig between the Colville River and Greater Mooses Tooth Units. The Colville River Unit includes the Alpine Field and four satellite fields. Field installations include one central production facility, which separates oil, natural gas and water. The Greater Mooses Tooth Unit is the first unit established entirely within the National Petroleum Reserve Alaska (NPR-A). The unit was constructed in two phases: Greater Mooses Tooth #1 (GMT1) and Greater Mooses Tooth #2 (GMT2). In December 2023, we announced Willow FID. The project will consist of three drill sites, an operations center and camp, and a processing facility. In 2024, construction included installation of the Willow Access Road, the Willow Operations Center pad and pipeline segments. Additionally, fabrication and delivery of the Willow Operations Center modules to the North Slope were completed. First oil is anticipated in 2029.

Transportation We transport the petroleum liquids produced on the North Slope to Valdez, Alaska through an 800-mile pipeline that is part of the Trans-Alaska Pipeline System (TAPS). We have a 29.5 percent ownership interest in TAPS, and also have ownership interests in, and operate the Alpine, Kuparuk and Oliktok pipelines on the North Slope. We manage the marine transportation of our North Slope production using five company-owned, double-hulled tankers, and charter third-party vessels, as necessary. The tankers deliver oil from Valdez, Alaska, primarily to refineries on the west coast of the U.S. 5

2024 Crude OilMBDNGLMBDNatural GasMMCFDTotalMBOED Average Daily Net Production Delaware Basin301 144 884 593 Eagle Ford124 66 322 244 Midland Basin101 44 224 182

Delaware Basin We hold approximately 792,000 unconventional net acres in the Delaware Basin, spanning west Texas through southeast New Mexico. Current development activity targets prospects in the Avalon, Bone Springs and Wolfcamp formations while balancing leasehold obligations and permit terms. We operated ten rigs and two frac crews on average during 2024, resulting in 166 operated wells drilled and 151 operated wells brought online.

Eagle Ford We hold approximately 484,000 unconventional net acres in the Eagle Ford, located in south Texas. The current focus is on full-field development, using customized well spacing and stacking patterns adapted through reservoir analysis. We operated seven rigs and two frac crews on average during 2024, resulting in 182 operated wells drilled and 154 operated wells brought online.

Midland Basin We hold approximately 265,000 unconventional net acres in the Midland Basin, located in west Texas. The current development strategy is focused on full-field development utilizing multi-well pad projects targeting both Spraberry and Wolfcamp reservoir targets. We operated five rigs and two frac crews on average during 2024, resulting in 119 operated wells drilled and 111 operated wells brought online.

Bakken We hold approximately 790,000 unconventional net acres in the Williston Basin, located in North Dakota and eastern Montana. The primary producing zones are the Middle Bakken and Three Forks formations. We operated four rigs and one frac crew on average during 2024, resulting in 66 operated wells drilled and 83 operated wells brought online.

Facilities We operate and own, with varying interests, centralized processing facilities in Texas and New Mexico in support of our Delaware, Eagle Ford and Midland assets.

ConocoPhillips 2024 10-K 6 Business and PropertiesTable of Contents Canada Our Canadian operations consist of the Surmont oil sands development in Alberta, the liquids-rich Montney unconventional play in British Columbia and commercial operations. In 2024, operations in Canada contributed ten percent of our consolidated liquids production and five percent of our consolidated natural gas production.

2024 InterestOperatorCrude OilMBDNGLMBDNatural GasMMCFDBitumenMBDTotalMBOED Average Daily Net Production Surmont100.0 %ConocoPhillips- - - 122 122 Montney100.0ConocoPhillips17 6 115 - 42

Total Canada17 6 115 122 164 Our bitumen resources in Canada are produced via SAGD, an enhanced thermal oil recovery method where steam is injected into the reservoir, effectively liquefying the heavy bitumen, which is recovered and pumped to the surface for further processing. Operations include two central processing facilities for treatment and blending of bitumen, and a diluent recovery unit. These facilities have allowed the asset to lower blend ratio and diluent supply costs, while gaining protection from diluent supply disruptions and increased market access for our product. At December 31, 2024, we held approximately 684,000 net acres of land in the Athabasca Region of northeastern Alberta.

Surmont The Surmont oil sands leases are located south of Fort McMurray, Alberta. Surmont is a 100 percent working interest asset that offers sustained, long-life production. We are focused on keeping facilities full, structurally lowering costs, reducing GHG intensity and optimizing asset performance. In 2024, we brought all wells at Pad 267 to expected production, commenced the drilling of Pad 104 and executed the asset's largest re-drill program to date of 29 wells. First production from Pad 104 is expected in 2026.

ConocoPhillips 2024 10-K Business and PropertiesTable of Contents Europe, Middle East and North Africa The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian sector of the North Sea, the Norwegian Sea, Qatar, Libya, Equatorial Guinea and commercial and terminalling operations in the U.K. In 2024, operations in Europe, Middle East and North Africa contributed nine percent of our consolidated liquids production and 17 percent of our consolidated natural gas production.

Norway 2024 InterestOperatorCrude OilMBDNGLMBDNatural GasMMCFDTotalMBOED Average Daily Net Production Greater Ekofisk Area28.3-35.1 %ConocoPhillips43 2 73 57

Aasta Hansteen Field The Aasta Hansteen Field is located in the Norwegian Sea. Gas is transported through the Polarled gas pipeline to the onshore Nyhamna processing plant for final processing prior to export to market. Produced condensate is loaded onto shuttle tankers and transported to market.

Millions of Barrels of Oil Equivalent Net Proved Reserves at December 312024 2023 2022 Crude oil Consolidated operations3,406 3,032 2,975 Equity affiliates108 89 93

Facilities We operate and have a 40.25 percent ownership interest in a crude oil stabilization and NGLs processing facility at Teesside, U.K. to support our Norway operations.

Qatar 2024 InterestOperatorCrude OilMBDNGLMBDNatural GasMMCFDTotalMBOED Average Daily Net Production QatarEnergy LNG N(3)30.0 %QatarEnergy LNG13 8 374 83 QatarEnergy LNG N(3) (N3), is an integrated development jointly owned by QatarEnergy (68.5 percent), ConocoPhillips (30 percent) and Mitsui & Co., Ltd. (1.5 percent). N3 consists of upstream natural gas production facilities, which produce approximately 1.4 gross BCF per day of natural gas from Qatar's North Field over a 25-year life, in addition to a 7.8 million gross tonnes per year LNG facility. LNG is shipped in leased LNG carriers destined for sale globally, while liquids are sold into the domestic market or marketed internationally through QatarEnergy Marketing. N3 executed the development of the onshore and offshore assets as a single integrated development with QatarEnergy LNG N(4) (N4), a joint venture between QatarEnergy and Shell plc. This included the joint development of offshore facilities situated in a common offshore block in Qatar's North Field, as well as the construction of two identical LNG process trains and associated gas treating facilities for both the N3 and N4 joint ventures. Production from the LNG trains and associated facilities is mutualized between the two joint ventures. We have a 25 percent interest in both QatarEnergy LNG NFE (4) (NFE4) and QatarEnergy LNG NFS (3) (NFS3) joint ventures, which are participating in the North Field East (NFE) and North Field South (NFS) LNG projects. See Note 3 and Note 4. 9

ConocoPhillips 2024 10-K Business and PropertiesTable of Contents Libya 2024 InterestOperatorCrude OilMBDNGLMBDNatural GasMMCFDTotalMBOED Average Daily Net Production

ConocoPhillips 2024 10-K 10 Business and PropertiesTable of Contents Asia Pacific The Asia Pacific segment has exploration and production operations in China, Malaysia, Australia and commercial operations in China, Singapore and Japan. In 2024, operations in the Asia Pacific segment contributed four percent of our consolidated liquids production and two percent of our consolidated natural gas production.

Australia 2024 InterestOperatorCrude OilMBDNGLMBDNatural GasMMCFDTotalMBOED Average Daily Net Production Australia Pacific LNG47.5 %ConocoPhillips/Origin Energy- - 859 143 Australia Pacific LNG Pty Ltd. (APLNG), our joint venture with Origin Energy Limited (Origin) and China Petrochemical Corporation (Sinopec), is focused on producing CBM from the Bowen and Surat basins in Queensland, Australia, to supply the domestic gas market and convert the CBM into LNG for export. Origin operates APLNG's upstream production and pipeline system, and we operate the downstream LNG facility, located on Curtis Island near Gladstone, Queensland, as well as the LNG export sales business. We operate two fully subscribed 4.5 MTPA LNG trains. Approximately 3,500 net wells are ultimately expected to supply both the LNG sales contracts and domestic gas market. The wells are supported by gathering systems, central gas processing and compression stations, water treatment facilities and an export pipeline connecting the gas fields to the LNG facilities. The LNG is being sold to Sinopec under a 20-year sales agreement for 7.6 MTPA of LNG, and Japan-based Kansai Electric Power Co., Inc. under a 20-year sales agreement for approximately one MTPA of LNG.

Malaysia 2024 InterestOperatorCrude OilMBDNGLMBDNatural GasMMCFDTotalMBOED Average Daily Net Production Gumusut29.5 %Shell12 - - 12 Malikai35.0 Shell12 - - 12

Kebabangan (KBB)30.0 KPOC1 - 49 9 Siakap North-Petai21.0 PTTEP1 - 1 1 Total Malaysia26 - 50 34 We have varying stages of exploration, development and production activities across approximately 2.6 million net acres in Malaysia, with working interests in six PSCs. Four of these PSCs are located in waters off the eastern Malaysian state of Sabah: Block G, Block J, the Kebabangan Cluster (KBBC) and the Ubah Cluster, acquired in 2024. We also operate another two exploration blocks, Block WL4-00 and Block SK304, in waters off the eastern Malaysian state of Sarawak.

Block J Gumusut We own a 29.5 percent working interest in the unitized Gumusut Field. Development associated with Gumusut Phase 4, a four-well program targeting the Brunei acreage of the unitized Gumusut Field that straddles Malaysia and Brunei waters, completed drilling in 2024 with first oil anticipated in early 2025. The unitized Gumusut Field is operated on a FPS with oil evacuation via a pipeline to the Sabah Oil and Gas Terminal (SOGT) for tanker liftings.

KBB Gas is transported from the KBB platform via pipeline for sale to the domestic gas market. Since 2019, KBB tied-in to a nearby third-party floating LNG vessel, which provided additional gas offtake capacity.

Oil Spill Response Organizations (OSROs) We maintain memberships in several OSROs, many of which are not-for-profit cooperatives owned by member companies. We may actively participate in these organizations as members of the board of directors, steering committees, work groups or other supporting roles. In North America, our primary OSROs include the Marine Spill Response Corporation for the continental U.S. and Alaska Clean Seas and Ship Escort/Response Vessel System for the Alaska North Slope and Prince William Sound, respectively. Internationally, we maintain memberships in various OSROs, including Oil Spill Response Limited, the Norwegian Clean Seas Association for Operating Companies, the Australian Marine Oil Spill Center and Petroleum Industry of Malaysia Mutual Aid Group.

ConocoPhillips 2024 10-K 14 Business and PropertiesTable of Contents Technology We have several technology programs that improve our ability to develop unconventional reservoirs, increase recovery from our legacy fields, improve the efficiency of our exploration program, produce heavy oil economically with lower emissions and implement sustainability measures.

LNG Liquefaction Technology We are the second-largest LNG liquefaction technology provider globally. Our Optimized Cascade® LNG liquefaction technology has been licensed for use in 28 LNG trains around the world, with FEED studies ongoing for additional trains.

Delivery Commitments We sell crude oil and natural gas from our producing operations under a variety of contractual arrangements, some of which specify the delivery of a fixed and determinable quantity. Our commercial organization also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be the spot market or a combination of our reserves and the spot market. Worldwide, we are contractually committed to deliver approximately 675 billion cubic feet of natural gas and 253 million barrels of crude oil in the future. These contracts have various expiration dates through the year 2034. We have a variety of options to fulfill our delivery commitments including third-party purchases, as supported by our gas management and power supply agreements, proved developed reserves and PUDs. See the disclosure on "Proved Undeveloped Reserves" in the "Supplementary Data - Oil and Gas Operations" section following the Notes to Consolidated Financial Statements, for information on the development of PUDs.

Business and PropertiesTable of Contents Alaska The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas and NGLs. We are the largest crude oil producer in Alaska and have major ownership interests in the Prudhoe Bay, Kuparuk and Western North Slope asset areas. Additionally, we are one of Alaska's largest owners of state, federal and fee exploration leases, with approximately one million net undeveloped acres at year-end 2024. Alaska operations contributed 14 percent of our consolidated liquids production and two percent of our consolidated natural gas production.

ConocoPhillips 2024 10-K Business and PropertiesTable of Contents General The environmental information contained in Management's Discussion and Analysis of Financial Condition and Results of Operations beginning on page 55 under the caption "Environmental" and beginning on page 57 under the caption "Climate Change" is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2024 and those expected for 2025 and 2026.

2024 InterestOperatorCrude OilMBDNGLMBDNatural GasMMCFDTotalMBOED Average Daily Net Production Greater Prudhoe Area*36.5 %Hilcorp67 15 36 88 Greater Kuparuk Area*94.2-99.8ConocoPhillips63 - 2 63