Conocophillips
Management Discussion analysis.

•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. The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards and water quality standards, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the U.S. and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the U.S. and Canada. An example is the use of hydraulic fracturing, an essential completion technique that facilitates production of oil and natural gas otherwise trapped in lower permeability rock formations. A range of local, state, federal, or national laws and regulations currently govern hydraulic fracturing operations, with hydraulic fracturing currently prohibited in some jurisdictions. Although hydraulic fracturing has been conducted for many decades, potential new laws, regulations and permitting requirements from various state environmental agencies, and others could result in increased costs, operating restrictions, operational delays and/or limit the ability to develop oil and natural gas resources. Governmental restrictions on hydraulic fracturing could impact the overall profitability or viability of certain of our oil and natural gas investments. We have adopted operating principles that incorporate established industry standards that are designed to meet government requirements. Our practices continually evolve as technology improves and regulations change. 53

Regulated sustainability disclosures. Governments and financial regulators are developing new reporting rules requiring increased disclosure around a range of sustainability topics. The patchwork of reporting standards that is developing may require significant increases in disclosures, which may be costly to implement. In June 2023 the International Sustainability Standards Board issued inaugural sustainability reporting standards; in October 2023 in California multiple bills were signed into law requiring climate-related disclosures for companies that conduct business in the state; in September 2024, the Australian Government passed legislation which mandated a new standard for climate-related disclosures; and in the EU, the Corporate Sustainability Reporting Directive is expected to be finalized in 2026. Compliance with changes in laws and regulations that create a GHG tax, emission trading scheme or GHG reduction policies could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also increase demand for less carbon intensive energy sources, including natural gas. The ultimate impact on our financial performance, either positive or negative, will depend on a number of factors, including but not limited to: •Whether and to what extent legislation or regulation is enacted; •The timing of the introduction of such legislation or regulation; •The nature of the legislation (such as a cap and trade system or a tax on emissions) or regulation; •The price placed on GHG emissions (either by the market or through a tax); •The GHG emissions reductions required; •The price and availability of offsets; •The amount and allocation of allowances; •Technological and scientific developments leading to new products or services;

DD&A is expected to be $11.7 to $11.9 billion. Operating Segments We manage our operations through five operating segments, which are primarily defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; and Asia Pacific. Effective in the fourth quarter of 2025, we determined that our former Other International operating segment, which consisted of activities associated with prior operations in other countries, was no longer an operating segment. Residual results are aggregated into Corporate and Other. Our historical operating segment reporting has been recast to reflect this change. Our combined 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.

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, global demand for our products, oil and gas inventory levels, governmental policies, inflation and supply chain disruptions. Throughout 2025, the price of crude oil has been volatile due to multiple macroeconomic and geopolitical forces which slowed global oil demand growth concurrent with higher oil production from OPEC Plus and other major oil producing countries. We continue to closely monitor the macroeconomic environment, including any impacts from tariffs, and the ongoing market volatility in the energy landscape and across global markets for implications to our business, results of operations and financial condition. As the global energy industry continues to evolve, we remain committed to creating long-term value for our stockholders. We believe ConocoPhillips plays an essential role in responsibly meeting the global demand for energy, while continuing to deliver competitive returns on and of capital and working to meet our previously established emissions-reduction targets. Our value proposition to deliver competitive returns to stockholders through price cycles is guided by our foundational principles, which consist of maintaining balance sheet strength, providing peer-leading distributions, making disciplined investments, and demonstrating responsible and reliable ESG performance. Total company production in 2025 was 2,375 MBOED, yielding cash provided by operating activities of $19.8 billion. We invested $12.6 billion into the business in the form of capital expenditures and investments and provided returns of capital to shareholders of $9.0 billion through our ordinary dividend and share repurchases. In 2025, we returned $4.0 billion through the ordinary dividend, inclusive of an increase in December of eight percent to 84 cents per share. In addition, we returned $5.0 billion to shareholders through share repurchases. As of December 31, 2025, we have repurchased $39.3 billion of shares of our authorized share repurchase program since 2016. In February 2026, we declared a first-quarter ordinary dividend of 84 cents per share. 31

Legal and Tax Matters We are subject to various lawsuits and claims, including but not limited to matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, climate change, personal injury and property damage. Our primary exposures for such matters relate to alleged royalty and tax underpayments on certain federal, state and privately owned properties, claims of alleged environmental contamination and damages from historic operations and climate change. We will continue to defend ourselves vigorously in these matters. Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required. See Note 16.

•Our cost of compliance with Norwegian carbon legislation in 2024 was approximately $37 million (net share before-tax). Other environmental regulations. •The White House Council on Environmental Quality (CEQ) issued final National Environmental Policy Act implementation regulations (NEPA Phase 2) in 2024. Since then, the DC Circuit Court has suggested that CEQ lacks authority to adopt any binding regulations, introducing potential uncertainty into the regulatory process. •Climate Superfund laws. 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, it is likely that more states will consider a similar approach. Compliance with such legislation may expose us to significant additional liabilities. •Climate Private Action laws. In 2025, California, New Hampshire, and Oregon introduced bills seeking to create a private right of action for individuals to bring strict liability claims for alleged damages related to climate change impacts (including non-economic, actual and punitive damages). These bills also authorize insurance companies to pursue subrogation claims to recover damages for amounts paid to insureds for climate change impacts.

◦Building a resilient asset portfolio with a focus on low cost of supply and low GHG intensity to meet global energy demand. ◦Committing to capital discipline through use of a fully burdened cost of supply, including cost of carbon, as the basis for capital allocation. ◦Testing our portfolio against future energy demand scenarios through a comprehensive scenario planning process that helps us assess the resilience of our corporate strategy to climate risk.

In support of addressing our Scope 1 and 2 emissions, we have made recent progress in several key areas. •Completed our 2024 scope 1 and 2 emissions reduction projects within the allotted capital and cost budget. These projects will support our GHG emissions intensity reduction target of 50-60 percent by 2030 from a 2016 baseline for both gross operated and net equity emissions. •Achieved the Gold Standard Reporting for emissions reporting in the Oil and Gas Methane Partnership 2.0 Initiative, one of only three U.S. companies to earn this distinction.

Production Total average production increased 60 MBOED in 2024 compared with 2023. Increases to production resulted from our increased working interest in Surmont as well as new wells online in the Montney and Surmont. See Note 3. These production increases were partly offset by higher downtime resulting from a planned turnaround activity at a Surmont central processing facility and normal field decline. 45

67 68 80 Total Production (MMBOE) 25 25 29 Average Sales Prices Crude oil ($ per bbl)$82.42 84.79 105.52 Natural gas ($ per mcf)3.74 3.95 5.84 The Asia Pacific segment consists of operations in China, Malaysia, and Australia, and commercial operations in China, Singapore and Japan. During 2024, Asia Pacific contributed four percent of our consolidated liquids production and two percent of our consolidated natural gas production.

The terms "earnings" and "loss" as used in Management's Discussion and Analysis refer to net income (loss). Business Environment and Executive Overview ConocoPhillips is one of the world's leading E&P companies, based on both production and reserves, 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; global LNG developments; oil sands in Canada; and an inventory of global exploration prospects. Headquartered in Houston, Texas, at December 31, 2025, we employed approximately 9,900 people worldwide and had total assets of $122 billion.

Summarized Income Statement Data Millions of Dollars 2025 Revenues and Other Income$38,564 Income (loss) before income taxes*7,316 Net income (loss)7,988

*Includes approximately $11.6 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries. Summarized Balance Sheet Data

Millions of Dollars December 31, 2025 Current assets$8,206 Amounts due from Non-Obligated Subsidiaries, current855 Noncurrent assets130,320 Amounts due from Non-Obligated Subsidiaries, noncurrent11,231

Current liabilities4,947 Amounts due to Non-Obligated Subsidiaries, current1,244 Noncurrent liabilities74,824 Amounts due to Non-Obligated Subsidiaries, noncurrent52,813

ConocoPhillips 2025 10-K Capital Resources and Liquidity We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their equivalents in their respective jurisdictions. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly. We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain waste attributable to our past operations. As of December 31, 2025, there were 20 sites around the U.S. in which we were identified as a potentially responsible party under CERCLA and comparable state laws. For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition. Expensed environmental costs were $834 million in 2025 and are expected to be approximately $1.0 billion in each of 2026 and 2027. Capitalized environmental costs were $669 million in 2025 and are expected to be about $750 million and $550 million in 2026 and 2027, respectively. Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis). Many of these liabilities result from CERCLA, RCRA, and similar state or international laws that require us to undertake certain investigative and remedial activities at sites where we conduct or once conducted operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we identified that may require environmental remediation but which are not currently the subject of CERCLA, RCRA, or other agency enforcement activities. The laws that require or address environmental remediation may apply retroactively and regardless of fault, the legality of the original activities or the current ownership or control of sites. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA. Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs. At December 31, 2025, our balance sheet included total accrued environmental costs of $220 million, compared with $206 million at December 31, 2024, for remediation activities in the U.S. and Canada. We expect to incur a substantial amount of these expenditures within the next 30 years. Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect upon our results of operations or financial position as a result of compliance with current environmental laws and regulations. See Item 1A. Risk Factors-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 and Note 9 for information on environmental litigation.

Emissions trading schemes. •EU ETS is the program through which many of the EU member states aim to reduce emissions. Our cost of compliance with the EU ETS in 2025 was approximately $21 million (net share before-tax). •The U.K. Emissions Trading Scheme (U.K. ETS) is the program with which the U.K. has replaced the EU ETS. Our cost of compliance with the U.K. ETS in 2025 was approximately $2.2 million (net share before-tax).

GHG regulations for emissions reductions. •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. There was no cost of compliance related to this regulation in 2025, as our Surmont asset outperformed its target benchmark intensity over the full year reporting period. •As of April 2024, the British Columbia Output Based Pricing System (BC OBPS) regulation requires facilities or linear operations (such as oil and gas gathering systems) with emissions equal to or greater than 10,000 metric tonnes of carbon dioxide or equivalent per year to remit payments on the difference between actual emissions and allowable emissions based on product and activity benchmarks. The benchmarks and guidance for these emissions have yet to be finalized, and compliance payments for 2025 are not due until later in 2026. Based on interim benchmarks, our BC OBPS obligation is expected to total a maximum of $12.3 million (net share before-tax) for Montney in 2025. •In 2024, the EU passed regulation on the reduction of methane emissions in the energy sector that will apply a methane limit on oil and gas imports to the EU, as well as mandate the monitoring, reporting, verification and reduction of methane emissions. •Our APLNG assets in Australia are subject to the Safeguard Mechanism, enacted through the National Greenhouse and Energy Reporting Act 2007. In the previous Australian financial year of July 1, 2024, to June 30, 2025, our operated downstream APLNG facility was in excess of its baseline emissions, while the upstream partner-operated facilities were below their baseline emissions. As there was a surplus of eligible carbon units across the joint venture, there was no expense incurred by ConocoPhillips for the 2025 Australian financial year. •In 2024 the U.S. EPA published final rulemaking for New Source Performance Standards (OOOOb) and Emissions Guidelines (OOOOc). Implementing this regulation across our U.S. portfolio will result in additional compliance costs.

Non-regulatory initiatives or agreements. •The Global Methane Pledge (GMP) was launched at COP26 by the EU and the U.S., a global initiative to reduce global methane emissions by at least 30 percent from 2020 levels by 2030. •The agreement reached in Paris in December 2015 at the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change set out a process for achieving global emissions reductions. Accordingly, parties to the Paris Agreement have set targets to reduce emissions by 2030. While the current administration has officially withdrawn the U.S. from the Paris Agreement, some U.S. states have indicated that they plan to remain committed to the goals of the agreement.

Company Response to Climate-Related Risks The objective of our Climate-related Risk Strategy is to manage climate-related risk, optimize opportunities and equip the company to respond to changes in key uncertainties, including government policies around the world, emissions reduction technologies, alternative energy technologies and changes in consumer trends. The strategy guides our choices around portfolio composition, emissions reductions, targets, incentives, emissions-related technology development, and our climate-related policy and finance sector engagement. Our Climate-related Risk Strategy is intended to enable us to responsibly meet the global demand for energy, deliver competitive returns on and of capital and work to meet our operational emissions-reduction targets. First, meeting global energy demand requires a focus on delivering production that will best compete in any energy demand scenario. This production will be delivered from resources with a competitive cost of supply and low operational GHG intensity, as well as portfolio diversity by market and asset type. Next, our focus is on delivering superior returns through the cycles based on our foundational principles of balance sheet strength, peer-leading distributions and disciplined investments. Finally,

◦Evaluating potential investments in emerging alternative energy sources and low-carbon technologies. •External engagement ◦Supporting a well-designed, economy-wide price on carbon and development of other policy and legislation to address end-use emissions.

◦Working with our suppliers and commercial partners to understand our emissions along the value chain. Our Climate-related Risk Strategy does not include a Scope 3 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, Scope 3 targets would shift production to other global operators, potentially eroding energy security and increasing emissions. This is why we have consistently supported a well-designed, economy wide price on carbon as well as the development of other policies or legislation that could address end-use emissions. We have also supported policy interests beyond carbon pricing to include energy efficiency, end-use emissions policy and regulatory action, such as support for the direct federal regulation of methane.

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 2025, we held $10.0 billion of net capitalized unproved property costs. 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 $8.7 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.

Exploratory Costs For exploratory wells, drilling costs are temporarily capitalized, or "suspended," on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to justify development. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. The accounting notion of "sufficient progress" is a judgmental area, but the accounting rules do prohibit continued capitalization of suspended well costs on the expectation future market conditions will improve or new technologies will be found that would make the development economically profitable. Often, the ability to move into the development phase and record proved reserves is dependent on obtaining permits and government or coventurer approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits and believe they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves. At year-end 2025, total suspended well costs were $243 million, compared with $196 million at year-end 2024. For additional information on suspended wells, including an aging analysis, see Note 5.

ConocoPhillips 2025 10-K 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, 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 our 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; geopolitical tensions; 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.

•Risks, uncertainties and high costs that may prevent us from successfully executing on our Climate-related Risk Strategy. •Lack or inadequacy of, or disruptions in, reliable transportation for our crude oil, bitumen, natural gas, LNG and NGLs. •Inability to timely obtain or maintain permits, including those necessary for construction, drilling and/or development, or inability to make capital expenditures required to maintain compliance with any necessary permits or applicable laws or regulations. •Potential disruption or interruption of our operations and any resulting consequences due to accidents; extraordinary weather events; supply chain disruptions; civil unrest; political events; war; terrorism; cybersecurity threats or information technology failures, constraints or disruptions.

ConocoPhillips 2025 10-K 62 •Liability for remedial actions, including removal and reclamation obligations, under existing or future environmental regulations and litigation.

•Uncertainty as to the long-term value of our common stock. •The factors generally described in Part I-Item 1A in this 2025 Annual Report on Form 10-K and any additional risks described in our other filings with the SEC. 63

ConocoPhillips 2025 10-K

ConocoPhillips 2025 10-K 36 Results of Operations Table of Contents Results of Operations This section of the Form 10-K discusses year-to-year comparisons between 2025 and 2024. For discussion of year-to-year comparisons between 2024 and 2023, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our 2024 10-K.

Consolidated Results Summary Operating Statistics 202520242023 Average Net Production Crude oil (MBD) Consolidated operations1,133 969 923 Equity affiliates12 13 13

Total natural gas4.44 4.69 5.69 37 ConocoPhillips 2025 10-K Results of Operations Table of Contents Millions of Dollars Worldwide Exploration Expenses

General and administrative; geological and geophysical, lease rental, and other$226 309 236 Leasehold impairment91 6 53 Dry holes90 40 109 Total Exploration Expenses$407 355 398

Total production of 2,375 MBOED increased 388 MBOED or 20 percent in 2025 compared with 2024. Production increases include: •New wells online in the Lower 48, Canada, Australia, Norway, Alaska, Libya, China and Malaysia.

ConocoPhillips 2025 10-K 38 Results of Operations Table of Contents Income Statement Analysis Unless otherwise indicated, all results in Income Statement Analysis are before-tax.

Below is select financial data provided on a consolidated basis. The full income statement can be found in Item 8. Financial Statements and Supplementary Data.

See Note 15-Income Taxes for information regarding our income tax provision and effective tax rate. 39 ConocoPhillips 2025 10-K Results of Operations Table of Contents

Total Production (MBOED) 199 194 195 Total Production (MMBOE) 73 71 71 Average Sales Prices Crude oil ($ per BBL)$71.79 81.73 83.05 Natural gas ($ per MCF)3.81 3.90 4.47 The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. In 2025, Alaska contributed 12 percent of our consolidated liquids production and one percent of our consolidated natural gas production.

ConocoPhillips 2025 10-K Results of Operations Table of Contents Lower 48 202520242023 Select financial data by segment before-tax ($MM) Sales and other operating revenues ($MM)$41,395 37,026 38,237

Production and operating expenses ($MM)5,856 4,751 4,199 Depreciation, depletion and amortization ($MM)8,121 6,442 5,722 Taxes other than income taxes ($MM)1,506 1,378 1,352

Total Production (MBOED) 1,484 1,152 1,067 Total Production (MMBOE) 542 422 389 Average Sales Prices Crude oil ($ per BBL)$63.18 74.17 76.19 Natural gas liquids ($ per BBL)20.64 22.02 21.73

Natural gas ($ per MCF)1.74 0.87 2.12 The Lower 48 segment consists of operations located in the contiguous U.S. and related commercial operations. During 2025, the Lower 48 contributed 67 percent of our consolidated liquids production and 74 percent of our consolidated natural gas production.

Production Total average production increased 332 MBOED in 2025 compared with 2024, primarily due to new wells online from our development programs in the Delaware Basin, Eagle Ford, Bakken and Midland Basin and the impact from our acquisition of Marathon Oil. See Note 3.

Bitumen ($ per BBL)40.74 47.92 42.15 Natural gas ($ per MCF)*1.02 0.54 1.80 *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 2025, Canada contributed nine percent of our consolidated liquids production and five percent of our consolidated natural gas production.

•Acquire interests in existing or new fields. •Apply new technologies and processes to improve recovery from existing fields. •Successfully explore, develop and exploit new and existing fields. Reserve replacement represents the net change in proved reserves, net of production, divided by our current year production. Our reserve replacement was 80 percent in 2025, reflecting a net decrease from dispositions in noncore assets in Lower 48 and lower prices, partially offset by development drilling activity and extensions and discoveries. Our organic reserve replacement, which excludes a net decrease of 165 MMBOE from sales and purchases, was 99 percent in 2025. In the three years ended December 31, 2025, our reserve replacement was 145 percent. Our organic reserve replacement during the three years ended December 31, 2025, which excludes a net increase of 905 MMBOE related to sales and purchases, was 106 percent.

Total Production (MMBOE) 82 67 61 Average Sales Prices Crude oil ($ per BBL)$68.95 80.92 83.96 Natural gas liquids ($ per BBL)16.53 40.29 41.13 Natural gas ($ per MCF)10.87 10.70 12.68 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 2025, our Europe, Middle East and North Africa operations contributed eight percent of our consolidated liquids production and 18 percent of our consolidated natural gas production.

Other income (expense)(14)352 (70) $(1,138)(880)(821) Net interest expense consists of interest and debt expense, net of interest income and capitalized interest. Net interest expense increased in 2025 due to higher interest expense driven by debt assumed from our acquisition of Marathon Oil. See Note 3 and Note 7. Corporate G&A expenses include compensation programs and staff costs. These expenses decreased by $230 million in 2025 compared with 2024, primarily due to the absence of transaction expenses of $432 million associated with our acquisition of Marathon Oil in 2024, partially offset by severance costs related to a restructuring in 2025. See Note 3 and Note 14. 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. 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" decreased by $366 million in 2025 compared with 2024. This was primarily due to the absence of a tax benefit of $455 million as a result of the acquisition of Marathon Oil in 2024 and the subsequent utilization of foreign tax credits. The earnings decrease was partly offset by an increase due to the absence of a loss of $147 million associated with the extinguishment of debt in the fourth quarter of 2024. See Note 3, Note 7 and Note 15.

ConocoPhillips 2025 10-K 46 Capital Resources and Liquidity Capital Resources and Liquidity Financial Indicators Millions of DollarsExcept as Indicated

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 2025, the primary uses of our available cash were $12.6 billion to support our ongoing capital expenditures and investments program; $5.0 billion to repurchase common stock; $4.0 billion to pay the ordinary dividend; and $0.9 billion to retire debt, partly offset by proceeds from asset sales of $3.2 billion. In 2025, cash and cash equivalents increased by $0.9 billion to $6.5 billion. See Note 3 and Note 7. At December 31, 2025, we had cash and cash equivalents of $6.5 billion, short-term investments of $0.5 billion, and available borrowing capacity under our credit facility of $5.5 billion, totaling approximately $12.5 billion of liquidity. In addition, we have long-term investments in debt securities of $1.1 billion. 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 2025 totaled $19.8 billion, compared with $20.1 billion for 2024, and $20.0 billion for 2023. The decrease in 2025 compared to 2024 resulted from lower commodity prices, mostly offset by operations from the 2024 Marathon Oil acquisition. See Note 3. The increase in cash provided by operating activities in 2024 compared to 2023 is 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. Our short- and long-term operating cash flows are highly dependent on the prices for crude oil, bitumen, natural gas, LNG and NGLs. Prices and margins in our industry have historically been volatile, driven by market conditions beyond our control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows. 47

ConocoPhillips 2025 10-K Capital Resources and Liquidity The level of absolute production volumes, as well as the product and location mix, is another significant factor impacting our cash flows. Full-year production averaged 2,375 MBOED in 2025, an increase of 388 MBOED or 20 percent compared to 2024. First-quarter 2026 production is expected to be 2.30 MMBOED to 2.34 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.

Investing Activities In 2025, we invested $12.6 billion in capital expenditures and investments, $0.5 billion of which was primarily payments towards our equity investments in LNG projects, including NFE4, NFS3 and PALNG, while the remainder funded our operating capital program. Capital expenditures invested in 2024 and 2023 were $12.1 billion and $11.2 billion, respectively. See the "Capital Expenditures and Investments" section. In August 2025, we announced a total disposition target of $5 billion by year-end 2026. We disposed of $3.2 billion of assets in 2025 and we expect to meet our $5 billion disposition target by year-end 2026. See Note 3. Proceeds from asset sales were $3.2 billion in 2025 compared with $0.3 billion in 2024 and $0.6 billion in 2023. In 2025, we sold Lower 48 assets in the Anadarko basin for net proceeds of $1.2 billion and our interest in the Ursa and Europa fields, and Ursa Oil Pipeline Company LLC for net proceeds of $0.7 billion. Additionally, we sold other noncore Lower 48 and Corporate assets for approximately $1.3 billion. See Note 3. In the fourth quarter of 2024, 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 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 7. We invest in short-term and long-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 needed for short-term investments to support our operating plan and provide resiliency to react to short-term price volatility are invested in highly liquid instruments with maturities of less than one year. Funds we consider available to maintain resiliency in longer term price downturns and to capture opportunities outside a given operating plan are invested in highly liquid instruments with maturities of greater than one year. See Note 10 and Note 17. Investing activities in 2025 included net purchases of $55 million of investments. We had net sales of $502 million of short-term investments and net purchases of $557 million of long-term investments. See Note 17.

ConocoPhillips 2025 10-K 48 Capital Resources and Liquidity Financing Activities Our debt balance at December 31, 2025 was $23.4 billion compared with $24.3 billion at December 31, 2024. The current portion of debt, including payments for finance leases, is $1.0 billion. In 2025, the company retired $0.7 billion principal amount of debt at maturity, consisting of $0.2 billion of our 3.35% Notes, $0.4 billion of our 2.4% Notes and $0.1 billion of our 8.2% Debentures. 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 7. 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 7. 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 7. In February 2025, we refinanced our revolving credit facility maintaining a total aggregate principal amount of $5.5 billion and extended the expiration to February 2030. Our revolving credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as support for our commercial paper program. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or any of its consolidated subsidiaries. The amount of the facility is not subject to redetermination prior to its expiration date. Credit facility borrowings may bear interest at a margin above the Secured Overnight Financing Rate (SOFR). The 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, 2025.

In November 2025, Fitch affirmed our long-term credit rating. The current credit ratings on our long-term debt are: •Fitch: "A" with a "stable" outlook

ConocoPhillips 2025 10-K Capital Resources and Liquidity 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, 2025 and 2024, we had direct bank letters of credit of $331 million and $278 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.

Asia Pacific342 370 354 Segments Total12,438 11,646 10,113 Corporate and Other115 472 1,135 Capital Program*$12,553 $12,118 $11,248 * Excludes capital related to acquisitions of businesses, net of cash acquired. Our capital expenditures and investments for the three-year period ended December 31, 2025, totaled $35.9 billion. The 2025 capital expenditures and investments supported key operating activities and acquisitions, primarily:

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.

The terms "earnings" and "loss" as used in Management's Discussion and Analysis refer to net income (loss). Business Environment and Executive Overview ConocoPhillips is one of the world's leading E&P companies based on both production and reserves 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; global LNG developments; oil sands in Canada; and an inventory of global exploration prospects. Headquartered in Houston, Texas, at December 31, 2024, we employed approximately 11,800 people worldwide and had total assets of $123 billion.

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.

ConocoPhillips 2024 10-K 38 Results of Operations Table of Contents Results of Operations This section of the Form 10-K discusses year-to-year comparisons between 2024 and 2023. For discussion of year-to-year comparisons between 2023 and 2022, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our 2023 10-K.

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

ConocoPhillips 2024 10-K

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.

ConocoPhillips 2024 10-K 40 Results of Operations Table of Contents Income Statement Analysis Unless otherwise indicated, all results in Income Statement Analysis are before-tax.

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.

ConocoPhillips 2024 10-K 48 Capital Resources and Liquidity Capital Resources and Liquidity Financial Indicators Millions of DollarsExcept as Indicated

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

Capital Program*10,159 5,324 4,715 * Excludes capital related to acquisitions of businesses, net of capital acquired. Our capital expenditures and investments for the three-year period ended December 31, 2022, totaled $20.2 billion. The 2022 capital expenditures and investments supported key operating activities and acquisitions, primarily:

Contingencies We are subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See "Critical Accounting Estimates" and Note 11 for information on contingencies.

•U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells. •U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages.

•Technological and scientific developments leading to new products or services. •Any potential significant physical effects of climate change (such as increased severe weather events, changes in sea levels and changes in temperature).

•Our inability to realize anticipated cost savings and capital expenditure reductions. •The inadequacy of storage capacity for our products, and ensuing curtailments, whether voluntary or involuntary, required to mitigate this physical constraint.

Crude oil ($ per bbl)$99.20 68.97 43.30 Natural gas liquids ($ per bbl)54.52 43.97 23.27 Natural gas ($ per mcf)33.39 13.27 3.23 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; and commercial and terminalling operations in the U.K. In 2022, 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.

Dry holes109 251 34 Total Exploration Expenses$398 564 344 ConocoPhillips 2023 10-K 42 Results of Operations Table of Contents We explore for, produce, transport and market crude oil, bitumen, natural gas, NGLs and LNG on a worldwide basis. At December 31, 2023, our operations were producing in the U.S., Norway, Canada, Australia, China, Malaysia, Qatar and Libya. Total production of 1,826 MBOED increased 88 MBOED or 5 percent in 2023 compared with 2022, primarily due to new wells online in the Lower 48, Australia, Canada, China, Norway and Malaysia.

*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, proceeds from asset sales, our commercial paper and credit facility programs and our ability to sell securities using our shelf registration statement. In 2023, the primary uses of our available cash were $11.2 billion to support our ongoing capital expenditures and investments program, $2.7 billion for the acquisition of an additional 50 percent working interest in Surmont, $5.4 billion to repurchase common stock, and $5.6 billion to pay the ordinary dividend and VROC. In addition to cash from operating activities, the other primary sources of additional capital were $2.7 billion in proceeds from long-term debt issuances to fund the Surmont acquisition and $1.4 billion net sales of short-term investments. In 2023, cash and cash equivalents decreased by $0.8 billion to $5.6 billion. See Note 9. At December 31, 2023, we had cash and cash equivalents of $5.6 billion, short-term investments of $1.0 billion, and available borrowing capacity under our credit facility of $5.5 billion, totaling approximately $12.1 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, dividend payments and required debt payments.

•Appraisal and development activities at Montney as well as optimization and development of oil sands in Canada. •Development, exploration and appraisal activities across assets in Norway.

•Technological and scientific developments leading to new products or services. •Any potential significant physical effects of climate change (such as increased severe weather events, changes in sea levels and changes in temperature).

Technology32 25 (26) Other income (expense)482 883 (992) $(330)(210)(1,880) Net interest consists of interest and financing expense, net of interest income and capitalized interest. Net interest expense improved $201 million in 2022, compared with 2021, primarily due to higher interest income as well as lower interest expenses as a result of our debt reduction transactions. See Note 9. Corporate G&A expenses include compensation programs and staff costs. These expenses decreased by $73 million in 2022 compared with 2021, primarily due to the absence of restructuring expenses associated with our Concho acquisition, partially offset by mark-to-market adjustments associated with certain compensation programs. See Note 16. Technology includes our investment in new technologies or businesses, as well as licensing revenues. Activities are focused on both conventional and tight oil reservoirs, shale gas, heavy oil, oil sands, enhanced oil recovery as well as LNG. Other income (expense) ("Other") includes certain corporate tax-related items, 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" decreased by $401 million in 2022 compared with 2021. This was primarily due to a gain of $251 million on our CVE common shares in 2022, compared with a $1,040 million gain in 2021. Earnings in "Other" also decreased due to a $101 million tax impact associated with the disposition of our Indonesia assets and higher legal accruals of $81 million. Offsetting the decreases to earnings in "Other" include a $474 million federal tax benefit associated with the closing of the 2017 audit of our U.S. federal income tax return, the absence of a release of a $92 million deferred tax asset associated with prior dispositions and recognizing an after-tax gain of $62 million associated with the debt restructuring transactions. 47

The terms "earnings" and "loss" as used in Management's Discussion and Analysis refer to net income (loss). Business Environment and Executive Overview ConocoPhillips is one of the world's leading E&P companies based on both production and reserves with operations and activities in 13 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; global LNG developments; oil sands in Canada; and an inventory of global exploration prospects. Headquartered in Houston, Texas, at December 31, 2023, we employed approximately 9,900 people worldwide and had total assets of $96 billion.

ConocoPhillips 2023 10-K Capital Resources and Liquidity Capital Expenditures and Investments Millions of Dollars 202320222021 Alaska$1,705 1,091 982

Capital Program*$11,248 10,159 5,324 * Excludes capital related to acquisitions of businesses, net of cash acquired. Our capital expenditures and investments for the three-year period ended December 31, 2023, totaled $26.7 billion. The 2023 capital expenditures and investments supported key operating activities and acquisitions, primarily:

Summarized Income Statement Data Millions of Dollars 2023 Revenues and Other Income$37,992 Income (loss) before income taxes*10,737 Net Income (Loss)10,957

ConocoPhillips 2023 10-K Capital Resources and Liquidity Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs. At December 31, 2023, our balance sheet included total accrued environmental costs of $184 million, compared with $182 million at December 31, 2022, for remediation activities in the U.S. and Canada. We expect to incur a substantial amount of these expenditures within the next 30 years. Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect upon our results of operations or financial position as a result of compliance with current environmental laws and regulations. See Item 1A. Risk Factors-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 and Note 11 for information on environmental litigation.

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.

•Whether, and the extent to which, increased compliance costs are ultimately reflected in the prices of our products and services. See Item 1A. Risk Factors-Existing and future laws, regulations and internal initiatives relating to global climate changes, 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 and Note 11 for information on climate change litigation.

ConocoPhillips 2023 10-K Results of Operations Table of Contents Results of Operations This section of the Form 10-K discusses year-to-year comparisons between 2023 and 2022. For discussion of year-to-year comparisons between 2022 and 2021, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our 2022 10-K.

New Accounting Standards For discussion of new accounting standards, see Note 25. ConocoPhillips 2023 10-K 60 Critical Accounting Estimates The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1 for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent there is a reasonable likelihood materially different amounts would have been reported under different conditions, or if different assumptions had been used. These critical accounting estimates are discussed with the Audit and Finance Committee of the Board of Directors at least annually. We believe the following discussions of critical accounting estimates address all important accounting areas where the nature of accounting estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

Exploratory Costs For exploratory wells, drilling costs are temporarily capitalized, or "suspended," on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to justify development. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. The accounting notion of "sufficient progress" is a judgmental area, but the accounting rules do prohibit continued capitalization of suspended well costs on the expectation future market conditions will improve or new technologies will be found that would make the development economically profitable. Often, the ability to move into the development phase and record proved reserves is dependent on obtaining permits and government or coventurer approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits and believe they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves. At year-end 2023, total suspended well costs were $184 million, compared with $527 million at year-end 2022. For additional information on suspended wells, including an aging analysis, see Note 6. 61

ConocoPhillips 2023 10-K Proved Reserves Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. Reserve estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan, historical extraction recovery and processing yield factors, installed plant operating capacity and approved operating limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons. Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of "proved" reserve estimates due to the importance of these estimates to better understand the perceived value and future cash flows of a company's operations. There are several authoritative guidelines regarding the engineering criteria that must be met before estimated reserves can be designated as "proved." Our geosciences and reservoir engineering organization has policies and procedures in place consistent with these authoritative guidelines. We have trained and experienced internal engineering personnel who estimate our proved reserves held by consolidated companies, as well as our share of equity affiliates. See "Supplementary Data - Oil and Gas Operations" for additional information. Proved reserve estimates are adjusted annually in the fourth quarter and during the year if significant changes occur and take into account recent production and subsurface information about each field. Also, as required by current authoritative guidelines, the estimated future date when an asset will reach the end of its economic life is based on historical 12-month first-of-month average prices and current costs. This date estimates when production will end and affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Generally, our proved reserves decrease as prices decline and increase as prices rise. Our proved reserves include estimated quantities related to PSCs, reported under the "economic interest" method, as well as variable-royalty regimes, and are subject to fluctuations in commodity prices, recoverable operating expenses and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. We would expect reserves from these contracts to decrease when product prices rise and increase when prices decline. The estimation of proved reserves is also important to the income statement because the proved reserve estimate for a field serves as the denominator in the unit-of-production calculation of the DD&A of the capitalized costs for that asset. At year-end 2023, the net book value of productive PP&E subject to a unit-of-production calculation was approximately $62 billion and the DD&A recorded on these assets in 2023 was approximately $8.1 billion. The estimated proved developed reserves for our consolidated operations were 3.8 billion BOE at the end of 2022 and 3.7 billion BOE at the end of 2023. If the estimates of proved reserves used in the unit-of-production calculations had been lower by 10 percent across all calculations, before-tax DD&A in 2023 would have increased by an estimated $894 million.

ConocoPhillips 2023 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, projected costs and plans, and objectives of management for future operations, 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 future dividends. You can often identify our forward-looking statements by the words "ambition," "anticipate," "believe," "budget," "continue," "could," "effort," "estimate," "expect," "forecast," "intend," "goal," "guidance," "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, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. 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: •Fluctuations in crude oil, bitumen, natural gas, LNG and NGLs prices, including a prolonged decline in these prices relative to historical or future expected levels. •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, including the conflicts in Ukraine and the Middle East, and the global response to such conflict; security threats on facilities and infrastructure; a public health crisis; 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 impact of significant declines in prices for crude oil, bitumen, natural gas, LNG and NGLs, which may result in recognition of impairment charges on our long-lived assets, leaseholds and nonconsolidated equity investments. •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.

•Unexpected changes in costs, inflationary pressures or technical requirements for constructing, modifying or operating E&P facilities. •Legislative and regulatory initiatives addressing environmental concerns, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring, water disposal or LNG exports. •Significant operational or investment changes imposed by existing or future environmental statutes and regulations, including international agreements and national or regional legislation and regulatory measures to limit or reduce GHG emissions. •Substantial investment in and development use of, competing or alternative energy sources, including as a result of existing or future environmental rules and regulations.

•The impact of public health crises, including pandemics (such as COVID-19) and epidemics, and any related company or government policies or actions. 65

ConocoPhillips 2023 10-K •Lack of, or disruptions in, adequate and reliable transportation for our crude oil, bitumen, natural gas, LNG and NGLs. •Inability to timely obtain or maintain permits, including those necessary for construction, drilling and/or development, or inability to make capital expenditures required to maintain compliance with any necessary permits or applicable laws or regulations. •Failure to complete definitive agreements and feasibility studies for, and to complete construction of, announced and future E&P and LNG development in a timely manner (if at all) or on budget. •Potential disruption or interruption of our operations and any resulting consequences due to accidents; extraordinary weather events; supply chain disruptions; civil unrest; political events, war; terrorism; cybersecurity threats and information technology failures, constraints or disruptions.

•Changes in international monetary conditions and foreign currency exchange rate fluctuations. •Changes in international trade relationships, including the imposition of trade restrictions or tariffs relating to crude oil, bitumen, natural gas, LNG, NGLs, carbon and any materials or products (such as aluminum and steel) used in the operation of our business, including any sanctions imposed as a result of any ongoing military conflict, including the conflicts in Ukraine and the Middle East.

•Liability for remedial actions, including removal and reclamation obligations, under existing and future environmental regulations and litigation. •Liability resulting from litigation, including litigation directly or indirectly related to the transaction with Concho Resources Inc., or our failure to comply with applicable laws and regulations. •General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas, LNG and NGLs and carbon pricing, including the imposition of price caps; regulation or taxation; and other political, economic or diplomatic developments, including as a result of any ongoing military conflict, including the conflicts in Ukraine and the Middle East.

ConocoPhillips 2023 10-K

See Note 17-Income Taxes for information regarding our income tax provision and effective tax rate. 41 ConocoPhillips 2023 10-K Results of Operations Table of Contents

Summary Operating Statistics 202320222021 Average Net Production Crude oil (MBD) Consolidated Operations923 885 816 Equity affiliates13 13 13 Total crude oil936 898 829

Natural gas liquids (MBD) Consolidated Operations279 244 134 Equity affiliates8 8 8 Total natural gas liquids287 252 142 Bitumen (MBD)81 66 69 Natural gas (MMCFD)

Millions of Dollars Worldwide Exploration Expenses General and administrative; geological and geophysical, lease rental, and other$236 224 300 Leasehold impairment53 89 10

ConocoPhillips 2023 10-K Results of Operations Table of Contents Segment Results Unless otherwise indicated, discussion of Segment Results is after-tax.

Natural gas (MMCFD)38 34 16 Total Production (MBOED) 195 200 197 Average Sales Prices Crude oil ($ per bbl)$83.05 101.72 69.87 Natural gas ($ per mcf)4.47 3.64 2.81 The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. In 2023, Alaska contributed 15 percent of our consolidated liquids production and two percent of our consolidated natural gas production.

ConocoPhillips 2023 10-K 44 Results of Operations Table of Contents Lower 48 202320222021 Net Income (Loss) ($MM) $6,461 11,015 4,932 Average Net Production

Crude oil ($ per bbl)$76.19 94.46 66.12 Natural gas liquids ($ per bbl)21.73 35.36 30.63 Natural gas ($ per mcf)2.12 5.92 4.38 *Includes conversion of previously acquired Concho two-stream contracts to three-stream initiated in the fourth quarter of 2021. The Lower 48 segment consists of operations located in the contiguous U.S. and the Gulf of Mexico and commercial operations. During 2023, the Lower 48 contributed 64 percent of our consolidated liquids production and 76 percent of our consolidated natural gas production.

Production Total average production increased 78 MBOED in 2023 compared with 2022, primarily due to new wells online from our development programs in Delaware Basin, Midland Basin, Eagle Ford and Bakken.

Natural gas ($ per mcf)*1.80 3.62 2.54 *Average sales prices include unutilized transportation costs. Our Canadian operations consist of the Surmont oil sands development in Alberta, the Montney unconventional play in British Columbia and commercial operations. In 2023, Canada contributed seven percent of our consolidated liquids production and three percent of our consolidated natural gas production.

168 165 175 Average Sales Prices Crude oil ($ per bbl)$83.96 99.20 68.97 Natural gas liquids ($ per bbl)41.13 54.52 43.97 Natural gas ($ per mcf)12.68 33.39 13.27 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, and commercial and terminalling operations in the U.K. In 2023, our Europe, Middle East and North Africa operations contributed nine percent of our consolidated liquids production and 16 percent of our consolidated natural gas production.

▪Acquire interest in existing or new fields. ▪Apply new technologies and processes to improve recovery from existing fields. ▪Successfully explore, develop and exploit new and existing fields. As required by authoritative guidelines, the estimated future date when an asset will reach the end of its economic life is based on historical 12-month first-of-month average prices and current costs. This date estimates when production will end and affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Generally, our proved reserves decrease as prices decline and increase as prices rise. Reserve replacement represents the net change in proved reserves, net of production, divided by our current year production, as shown in our supplemental reserve table disclosures. Our reserve replacement was 123 percent in 2023, reflecting a net increase from development drilling activity, extensions and discoveries and purchases, partially offset by lower prices. Our organic reserve replacement, which excludes a net increase of 184 MMBOE from sales and purchases, was 96 percent in 2023. In the three years ended December 31, 2023, our reserve replacement was 219 percent. Our organic reserve replacement during the three years ended December 31, 2023, which excludes a net increase of 1,293 MMBOE related to sales and purchases, was 152 percent. See "Supplementary Data - Oil and Gas Operations" for more information. Access to additional resources may become increasingly difficult as lower commodity price cycles can make projects uneconomic or unattractive. In addition, prohibition of direct investment in some nations, national fiscal terms, political instability, competition from national oil companies, and lack of access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to fully replace our production over subsequent years.

ConocoPhillips 2023 10-K Capital Resources and Liquidity Capital Resources and Liquidity Financial Indicators Millions of DollarsExcept as Indicated

Significant Changes in Capital Operating Activities Cash provided by operating activities in 2023 totaled $20.0 billion, compared with $28.3 billion for 2022, and $17.0 billion for 2021. The decrease in cash provided by operating activities from 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. The increase in cash provided by operating activities from 2022 compared to 2021 is primarily due to higher realized commodity prices, higher sales volumes mostly due to our acquisition of Shell Permian assets and the absence of the 2021 settlement of oil and gas hedging positions acquired from Concho. The increase in cash provided by operating activities was partly offset by foreign tax and royalty payments in Libya and foreign tax payments in Norway in addition to U.S. tax payments. 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.

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.

Investing Activities In 2023, we invested $11.2 billion in capital expenditures and investments; $1.5 billion of which was primarily payments towards our investments in LNG projects, including PALNG, NFE4 and NFS3. See Note 3. The remaining $9.7 billion funded our operating capital program. Capital expenditures invested in 2022 and 2021 were $10.2 billion and $5.3 billion, respectively. See the "Capital Expenditures and Investments" section. 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 9. Proceeds from asset sales were $0.6 billion in 2023 compared with $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 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. In December 2021, we completed our acquisition of Shell's assets in the Delaware Basin for cash consideration of approximately $8.7 billion after customary adjustments. We funded this transaction with cash on hand. We completed our acquisition of Concho on January 15, 2021 in an all-stock transaction. The assets acquired in the transaction included $382 million of cash. The net impact of these items is recognized within "Acquisition of businesses, net of cash acquired" on our consolidated statement of cash flows. See Note 3. In 2021, total proceeds from asset dispositions were $1.7 billion. We received cash proceeds of $250 million from the sale of noncore assets in our Lower 48 segment, $1.1 billion from sales of our investment in CVE common shares and $244 million of contingent payments related to dispositions completed before 2021. 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 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 12 and Note 19. Investing activities in 2023 included net sales of $1,373 million of investments. We had net sales of $2,111 million of short-term instruments and net purchases of $738 million of long-term instruments. See Note 19. 51

ConocoPhillips 2023 10-K Capital Resources and Liquidity Financing Activities Our debt balance at December 31, 2023 was $18.9 billion compared with $16.6 billion at December 31, 2022. The current portion of debt, including payments for finance leases, is $1.1 billion. 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 9. 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, 2023.

In December 2023, Fitch affirmed our long-term credit ratings. The current credit ratings on our long-term debt are: •Fitch: "A" with a "stable" outlook

•S&P: "A-" with a "stable" outlook •Moody's: "A2" with a "stable" outlook 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.

ConocoPhillips 2023 10-K 52 Capital Resources and Liquidity Capital Requirements For information about our capital expenditures and investments, see the "Capital Expenditures and Investments" section. Our debt balance at December 31, 2023, was $18.9 billion, an increase of $2.3 billion from the balance at December 31, 2022 of $16.6 billion. 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. In 2022, we executed concurrent debt refinancing transactions, repurchased existing notes, and retired floating rate notes upon natural maturity, that in aggregate reduced our total debt by $3.3 billion while also lowering our annual cash interest expense and extending the weighted average maturity of our debt portfolio. See Note 9 for information regarding debt and Note 19 for information regarding non-cash consideration of the Surmont transaction. 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 plan to deliver a compelling, growing ordinary dividend, through-cycle share repurchases and a VROC payment. The VROC provides a flexible tool for meeting our commitment of returning greater than 30 percent of cash from operating activities during periods where commodity prices are meaningfully higher than our planning price range. Our 2023 total capital returned was $11 billion. Consistent with our commitment to deliver value to shareholders, for the full year of 2023, we paid ordinary dividends of $2.11 per common share and VROC payments of $2.50 per common share. This was an increase over 2022 when we paid ordinary dividends of $1.89 and VROC payments of $2.60 per common share and an increase over 2021 when we paid an ordinary dividend of $1.75 per common share. In February 2024, we declared a first quarter ordinary dividend of $0.58 per common share and a VROC payment of $0.20 per common share, both payable March 1, 2024, to shareholders of record on February 19, 2024. The ordinary dividend and VROC are subject to numerous considerations and are determined and approved each quarter by the Board of Directors. All VROC payments to date have been declared along with the ordinary dividend, but paid in the following quarter. However, beginning in the first quarter of 2024, we plan to pay any quarterly dividend and VROC payment concurrently and will announce such payments in the same quarter they will be paid. In late 2016, we initiated our current share repurchase program. In October 2022, our Board of Directors approved an increase to our authorization from $25 billion to $45 billion of our common stock to support our plan for future share repurchases. Share repurchases were $5.4 billion, $9.3 billion, and $3.6 billion in 2023, 2022, and 2021, respectively. As of December 31, 2023, share repurchases since the inception of our current program totaled 383.4 million shares and $28.8 billion. Repurchases are made at management's discretion, at prevailing prices, subject to market conditions and other factors. For more information on factors considered when determining the levels of returns of capital see "Item 1A-Risk Factors - Our ability to execute our capital return program is subject to certain considerations." As of December 31, 2023, in addition to the priorities described above, we have contractual obligations to purchase goods and services of approximately $29.7 billion. We expect to fulfill $7.4 billion of these obligations in 2024. These figures exclude purchase commitments for jointly owned fields and facilities where we are not the operator. Purchase obligations of $9.8 billion are related to agreements to access and utilize the capacity of third-party equipment and facilities, including pipelines and LNG product terminals, to transport, process, treat and store commodities. Purchase obligations of $17.8 billion are related to market-based contracts for commodity product purchases with third parties. The remainder is primarily our net share of purchase commitments for materials and services for jointly owned fields and facilities where we are the operator. 53