Conocophillips,
Fiscal Year 2023.

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.

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.

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.

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

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

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.

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

Political and economic factors in international markets could have a material adverse effect on us. Approximately 31 percent of our hydrocarbon production was derived from production outside the U.S. in 2023, and 33 percent of our proved reserves, as of December 31, 2023, were located outside the U.S. We are subject to risks associated with our operations in foreign jurisdictions and international markets, including changes in foreign governmental policies relating to crude oil, bitumen, LNG, natural gas or NGL pricing and taxation; other regulatory or economic developments (including the macro effects of international trade policies and disputes); disruptive geopolitical conditions, and international monetary and currency rate fluctuations. For example, in December 2022, in response to higher energy prices resulting from the conflict between Russia and Ukraine, Australia's Parliament passed legislation setting a one-year price cap on natural gas. Further legislation was introduced in 2023 that extends the price cap through to at least June 2025, subject to further review and certain exemptions. Restrictions on production of oil and gas could increase to the extent governments view such measures as a viable approach for pursuing national and global energy security and climate policies. The escalation of geopolitical tension in the Middle East in late 2023 and early 2024 underscores the continued relevance of this consideration. In addition, some countries where we operate lack a fully independent judiciary system. This, coupled with changes in foreign law or policy, results in a lack of legal certainty that exposes our operations to increased risks, including increased difficulty in enforcing our agreements in those jurisdictions and increased risks of adverse actions by local government authorities, such as expropriations. Actions by host governments, such as the expropriation of our oil assets by the Venezuelan government, have affected operations significantly in the past and may continue to do so in the future. In addition, the U.S. government has the authority to prevent or restrict us from doing business in foreign jurisdictions or with certain parties. These restrictions and similar restrictions imposed by foreign governments have in the past limited our ability to operate in, or gain access to, opportunities in various jurisdictions. Diplomatic relations or policies between the U.S. government and one or more foreign jurisdictions may impair our ability to collect awards in legal actions against such foreign jurisdictions. Changes in domestic and international policies and regulations may also restrict our ability to obtain or maintain licenses or permits necessary to operate in foreign jurisdictions, including those necessary for drilling and development of wells. Similarly, the declaration of a "climate emergency" could result in actions to limit exports of our products and other restrictions.

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

Risks Related to Our Industry Our operating results, our ability to execute on our strategy and the carrying value of our assets are exposed to the effects of volatile commodity prices or prolonged periods of low commodity prices. Among the most significant factors impacting our revenues, operating results and future rate of growth are the sales prices for crude oil, bitumen, LNG, natural gas and NGL. These prices are tied to market prices that can fluctuate widely, and many of the factors influencing the prices are beyond our control. For example, over the course of 2023, WTI crude oil prices ranged from a low of $67 per barrel in March to a high of $94 per barrel in August. Given the volatility in commodity price drivers and the worldwide political and economic environment, including potential economic slowdowns or recessions, unexpected shocks to supply and demand resulting from future global health crises such as those experienced in connection with the COVID-19 pandemic or increased uncertainty generated by recent (and potential future) armed hostilities in various oil-producing regions around the globe, prices for crude oil, bitumen, LNG, natural gas and NGLs may continue to be volatile. Prolonged periods of low commodity prices could have a material adverse effect on our revenues, operating income, cash flows and liquidity, and may also affect the amount of dividends we elect to declare and pay on our common stock and the amount of shares we elect to acquire as part of our share repurchase program and the timing of such acquisitions. Lower prices may also limit the amount of reserves we can produce economically, thus adversely affecting our proved reserves and reserve replacement ratio and accelerating the reduction in our existing reserve levels as we continue production from upstream fields. Prolonged depressed prices may affect strategic decisions related to our operations, including decisions to reduce capital investments or curtail operated production. Significant reductions in crude oil, bitumen, LNG, natural gas and NGL prices could also require us to reduce our capital expenditures, impair the carrying value of our assets or discontinue the classification of certain assets as proved reserves. Although it is not reasonably practicable to quantify the impact of any future impairments or estimated change to our unit-of-production rates at this time, our results of operations could be adversely affected as a result.

ConocoPhillips 2023 10-K Risk FactorsTable of Contents impact the demand for our products, impose taxes on our products or operations, or require us to purchase emission credits or reduce emissions of GHGs from our operations. For example, in August 2022, the U.S. enacted the Inflation Reduction Act of 2022, which includes a charge on methane emissions from selected facilities in the oil and gas industry, including many of the facilities operated by ConocoPhillips. As a result, we may incur substantial capital expenditures and compliance, operating, maintenance and remediation costs, any of which may have an adverse effect on our business and results of operations. For more information on legislation or precursors for possible regulation relating to global climate change that affect or could affect our operations and a description of the company's response, see the "Contingencies-Climate Change" and "-Company Response to Climate-Related Risks" sections of Management's Discussion and Analysis of Financial Condition and Results of Operations. Broader investor and societal attention to and efforts to address global climate change may limit who can do business with us or our access to financial markets and could subject us to litigation. Increasing attention to global climate change has also resulted in pressure from and upon stockholders, financial institutions and other financial market participants to potentially limit or discontinue investments, insurance and funding to oil and gas companies. For example, a significant number of financial institutions are now members of the Glasgow Financial Alliance for Net Zero (GFANZ), thereby pledging to the goal of net zero by 2050, as well as setting interim targets for 2030 or earlier. While they are not prohibited from doing business with oil and gas companies, GFANZ members may self-impose limits. Conversely, we also face pressure from some in the investment community and certain public interest groups to limit the focus on ESG in our decision-making, arguing that ESG considerations do not relate to financial outcomes. As public pressure continues to mount on the financial sector, our costs of capital may increase. Furthermore, increasing attention to global climate change has resulted in an increased likelihood of governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business. Beginning in 2017 and continuing through 2023, cities, counties, governments and other entities in several states/territories in the U.S. have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged climate change impacts. Additional lawsuits with similar allegations are expected to be filed. The amounts claimed by plaintiffs are unspecified and the legal and factual issues involved in these cases are unprecedented. ConocoPhillips believes these lawsuits are factually and legally meritless, and are an inappropriate vehicle to address the challenges associated with climate change and will vigorously defend against such lawsuits. The ultimate outcome and impact to us cannot be predicted with certainty, and we expect to incur substantial legal costs associated with defending these and similar lawsuits in the future. We could also receive lawsuits alleging a failure or lack of diligence to meet our publicly stated ESG goals, or alleging misrepresentation related to our ESG activity.

Political and economic developments could damage our operations and materially reduce our profitability and cash flows. Actions of the U.S., state, local and foreign governments, through sanctions, tax and other legislation, executive orders and commercial restrictions, could reduce our operating profitability both in the U.S. and abroad. In certain locations, restrictions on our operations; leasing restrictions; special taxes or tax assessments; and payment transparency regulations that could require us to disclose competitively sensitive information or might cause us to violate non-disclosure laws of other countries have been imposed or proposed by governments or certain interest groups. In addition, we may face regulatory changes in the U.S. including, but not limited to, the enactment of tax law changes that adversely affect the fossil fuel industry, new methane emissions standards, requirements restricting or prohibiting flaring and subsurface water disposal, more stringent environmental impact studies and reviews and policies inhibiting or curtailing LNG exports. Similar regulatory shifts, including attendant higher costs and market access constraints, may also occur in international jurisdictions in which we operate. Hydraulic fracturing, an essential completion technique that facilitates production of oil and natural gas otherwise trapped in lower permeability rock formations, has historically attracted political and regulatory scrutiny. A range of local, state, federal and national laws and regulations currently govern, constrain or prohibit hydraulic fracturing in some jurisdictions. New or more stringent permitting, disclosure or other regulatory requirements on hydraulic fracturing or other oil and natural gas operations, including subsurface water disposal, could result in increased costs, operating restrictions or operational delays or could limit the ability to develop oil and natural gas resources. In addition, certain interest groups have also proposed ballot initiatives, contested lease sales and challenged project permits, for example, to restrict oil and natural gas development generally as well as specific projects, including the

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

Unless we successfully develop resources, the scope of our business will decline, resulting in an adverse impact to our business. As we produce crude oil, bitumen, natural gas and NGLs from our existing portfolio, the amount of our remaining reserves declines. If we do not successfully replace the resources we produce with good prospects for future organic development or through acquisitions, our business will decline. In addition, our ability to successfully develop our reserves depends on our achievement of a number of operational and strategic objectives, some aspects of which are beyond our control, including navigating political and regulatory challenges to obtain and renew rights to develop and produce hydrocarbons; reservoir optimization; bringing long-lead time, capital intensive projects to completion on budget and on schedule; and efficiently and profitably operating mature properties. If we are not successful in developing the resources in our portfolio, our financial condition and results of operations may be adversely affected.

•Total yield; and •Other factors our Board of Directors deems relevant. We expect to continue to pay a quarterly ordinary dividend to our stockholders. In addition, based on the current environment, we anticipate also paying a quarterly VROC to our shareholders; however, the amount of dividends and VROC is variable and will depend upon the above factors, and our Board of Directors may determine not to pay a dividend or VROC in a quarter or may cease declaring a dividend or VROC at any time. Since the inception of the three-tier return of capital program, the VROC has both increased and decreased across quarters, and it may continue to fluctuate in the future. Additionally, as of December 31, 2023, $16.2 billion of repurchase authority remained of the $45 billion share repurchase program our Board of Directors had authorized. Our share repurchase program does not obligate us to acquire a specific number of shares during any period, and our decision to commence, discontinue or resume repurchases in any period will depend on the same factors that our Board of Directors may consider when declaring dividends, among other factors. In the past we have suspended our share repurchase program in response to market downturns, including as a result of the oil market downturn that began in early 2020, and we may do so again in the future. Any downward revision in the amount of our ordinary dividend or VROC or the volume of shares we purchase under our share repurchase program could have an adverse effect on the market price of our common stock.

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

ConocoPhillips 2023 10-K 20 Risk FactorsTable of Contents Our ability to successfully execute on our energy transition plans is subject to a number of risks and uncertainties and may be costly to achieve. In 2020, we announced our Paris-aligned climate risk framework, including an ambition to achieve net-zero operational emissions by 2050. In 2022, we published our Plan for the Net-Zero Energy Transition (the "Plan") and continued to set increasingly ambitious targets around operational GHG emissions intensity and reducing methane emissions and flaring. Our ability to achieve stated targets, goals and ambitions is subject to a number of risks and uncertainties out of our control, government policies and markets, as well as potential regulations that may impair our ability to execute on current or future plans. Such achievement also depends on the accelerated pace of development of effective emissions measurement and abatement technologies, and the actual pace of development may be inadequate, or the technologies actually developed may be insufficient. Furthermore, we are still in the planning stages, and the Plan's execution could be costly, may have unforeseen obstacles, may proceed at varying paces during the timeframe allotted for the Plan and may be accomplished in a manner that we cannot predict at this time. We may be required to purchase emission credits in the future, and there may be an insufficient supply of offsets to achieve our goals, or we could incur increasingly greater expenses related to our purchase of such offsets. As advanced technologies are developed to accurately measure emissions, we may be required to revise our emissions estimates and reduction goals or otherwise revise our strategies outlined in the Plan. We may be adversely affected and potentially need to reduce economic end-of-field life of certain assets and impair associated net book value due to the emissions intensity of some of our assets. Even if we meet our goals, our efforts may be characterized as insufficient. In 2021, we established our Low-Carbon Technologies organization to identify and evaluate business opportunities that address end-use emissions and early-stage low-carbon technology opportunities that would leverage our existing expertise and adjacencies. Our investments in these technologies may expose us to numerous financial, legal, operational, reputational and other risks. While we perform a thorough analysis on these investments, the related technologies and markets are at early stages of development and we do not yet know what rate of return we will achieve, if any. Furthermore, we may not be able to deploy such technologies at a commercial scale. The success of our low-carbon strategy will depend in part upon the cooperation of government agencies, the support of stakeholders, our ability to research and forecast potential investments, and our ability to apply our existing strengths and expertise to new technologies, projects and markets. Estimates of crude oil, bitumen, natural gas and NGL reserves are imprecise and may be subject to revision, and any material change in the factors and assumptions underlying our estimates of crude oil, bitumen, natural gas and NGL reserves could impair the quantity and value of those reserves. Our proved reserve information included in this annual report represents management's best estimates based on assumptions, as of a specified date, of the volumes to be recovered from underground accumulations of crude oil, bitumen, natural gas and NGLs. Such volumes cannot be directly measured, and the estimates and underlying assumptions used by management are subject to substantial risk and uncertainty. Any material changes in the factors and assumptions underlying our estimates of these items could result in a material negative impact to the volume of reserves reported or could cause us to incur impairment expenses on property associated with the production of those reserves. Future reserve revisions could also result from changes in, among other things, governmental regulation and commodity prices. For more information on estimates used, see the "Critical Accounting Estimates" section of Management's Discussion and Analysis of Financial Condition and Results of Operations. Our business may be adversely affected by price controls; government-imposed limitations on production or exports of crude oil, bitumen, LNG, natural gas and NGLs; or the unavailability of adequate gathering, processing, compression, transportation, and pipeline facilities and equipment for our production of crude oil, bitumen, natural gas and NGLs. As discussed herein, our operations are subject to extensive governmental regulations across numerous jurisdictions. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil, bitumen, natural gas and NGL wells below actual production capacity. Similarly, in response to increased domestic energy costs, circumstances determined to be in the economic interest of the country, or a declared national emergency, governments could restrict the export or import of our products which would adversely impact our business. Because legal requirements are frequently changed and subject to interpretation, we cannot predict whether future restrictions on our business may be enacted or become applicable to us. 21

Our ability to manage risk or influence outcomes in joint ventures may be constrained. We conduct many of our operations through joint ventures in which another joint venture partner is operator or we may not have majority control. In these cases, the economic, business, or legal interests or goals of the operator or the voting majority may be inconsistent with ours, and we may not be able to influence the decision making or outcomes to align with our interests or goals. Failure by an operator or a voting majority, with whom we have a joint venture interest, to adequately manage the risks associated with any operations could have an adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations.

ConocoPhillips 2023 10-K 22 Risk FactorsTable of Contents Legal and Regulatory Risks We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations. Our business is subject to numerous laws and regulations relating to the protection of the environment, which are expected to continue to have an increasing impact on our operations. For a description of the most significant of these environmental laws and regulations, see the "Contingencies-Environmental", "-Climate Change" and "-Company Response to Climate-Related Risks" sections of Management's Discussion and Analysis of Financial Condition and Results of Operations. These laws and regulations continue to increase in both number and complexity and affect our operations with respect to, among other things: •Permits required in connection with exploration, drilling, production and other activities, including those issued by national, subnational, and local authorities; •The discharge of pollutants into the environment; •Emissions into the atmosphere, such as nitrogen oxides, sulfur dioxide, mercury and GHG emissions, including methane; •Carbon taxes; •The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous and nonhazardous wastes;

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

QatarEnergy LNG N(3)30.0 %QatarEnergy LNG13 8 375 83 QatarEnergy LNG N(3) (N3), formerly Qatar Liquefied Gas Company Limited (3) (QG3), is an integrated development jointly owned by QatarEnergy (68.5 percent), ConocoPhillips (30 percent) and Mitsui & Co., Ltd. (1.5 percent). N3 consists of upstream natural gas production facilities, which produce approximately 1.4 gross BCF per day of natural gas from Qatar's North Field over a 25-year life, in addition to a 7.8 million gross tonnes per year LNG facility. LNG is shipped in leased LNG carriers destined for sale globally. N3 executed the development of the onshore and offshore assets as a single integrated development with QatarEnergy LNG N(4) (N4), formerly Qatargas 4 (QG4), a joint venture between QatarEnergy and Shell plc. This included the joint development of offshore facilities situated in a common offshore block in the North Field, as well as the construction of two identical LNG process trains and associated gas treating facilities for both the N3 and N4 joint ventures. Production from the LNG trains and associated facilities is combined and shared. During 2022, we were awarded a 25 percent interest in each of two new joint ventures with QatarEnergy to participate in the North Field East (NFE) and North Field South (NFS) LNG projects. Formation of the NFE joint venture, QatarEnergy LNG NFE (4) (NFE4), formerly Qatar Liquefied Gas Company Limited (8) (QG8), closed in December 2022 and the formation of the NFS joint venture, QatarEnergy LNG NFS (3) (NFS3), formerly Qatar Liquefied Gas Company Limited (12) (QG12), closed in June 2023. See Note 3 and Note 4.

Penglai49.0 %CNOOC32 - - 32 Penglai The Penglai 19-3, 19-9 and 25-6 fields are located in the Bohai Bay Block 11/05 and are being developed in stages from large offshore platforms and a FPSO. Most crude oil produced from the block is sold to the China domestic market, with the remainder exported to international markets. Phase 3 consists of three wellhead platforms and a central processing platform. First production from Phase 3 was achieved in 2018. This project could include up to 186 wells, 175 of which have been completed and brought online as of December 2023. Phase 4A consists of one wellhead platform and achieved first production in 2020. This project could include up to 62 new wells, 54 of which have been completed and brought online as of December 2023. Phase 4B consists of two wellhead platforms, WHP-H and WHP-N, both of which achieved first production in the fourth quarter of 2023. This project could include up to 144 new wells, 3 of which have been completed and brought online as of December 2023.

Colombia We have an 80 percent operating interest in the Middle Magdalena Basin Block VMM-3 extending over approximately 67,000 net acres. In addition, we have an 80 percent working interest in the VMM-2 Block, which extends over approximately 58,000 net acres and is contiguous to the VMM-3 Block. The contracts for this project are currently in force majeure due to the lack of a defined environmental licensing required for the execution of unconventional exploratory activities. Additionally, the government of Colombia supports a ban on such activities.

Low-Carbon Technologies In 2021, we established a multi-disciplinary Low-Carbon Technologies organization, with the remit to support our net-zero ambition, understand the alternative energy landscape and prioritize opportunities for future competitive investment. We continue our focus on implementing emissions reduction projects across our global portfolio, including operational efficiency measures and methane and flaring reductions. In April 2023, we accelerated our 2030 GHG emissions intensity reduction target to a 50-60 percent reduction by 2030 from a 2016 baseline on both a gross operated and net equity basis. In addition, we set a new near-zero methane intensity target of less than 1.5-kilogram carbon dioxide equivalent per BOE by 2030. We are also on track to meet the World Bank Zero Routine Flaring goal by 2025. To help achieve these targets, the Low-Carbon Technologies organization continued to work with the company's business units to develop and implement region-specific emission reduction initiatives and identify potential technology solutions for hard-to-abate emissions. Over the last two years, we continued our work to identify additional pathways to abate our Scope 1 and 2 emissions as well as low-carbon opportunities for future competitive investment. For example: •We conducted CCS and electrification studies, initiated zero/low emission equipment design enhancements, installed mechanisms to continuously monitor and detect methane emissions and implemented operational changes to reduce flaring and methane venting volumes. •We evaluated carbon dioxide storage sites primarily along the U.S. Gulf Coast, progressed land acquisition efforts and business development work, initiated permitting activities for potential appraisal wells for carbon sequestration and advanced engineering studies for multiple opportunities. •We advanced hydrogen opportunities in the U.S., Middle East and Asia Pacific regions. In September 2023, JERA and Uniper announced a non-binding Heads of Agreement together with ConocoPhillips, for the potential sale of ammonia to Uniper. This agreement further advanced our cooperation to potentially develop a low-carbon, ammonia production facility on the U.S. Gulf Coast that would supply low-carbon fuels from the U.S. for use in the U.S., Europe, Japan and greater Asia.

Diversity, Equity and Inclusion As our industry evolves, we will continue to face both new opportunities and challenges, requiring a workforce that is equipped to address this evolution. We also need to cultivate an environment where everyone is encouraged and able to contribute - no matter their role, level or location. This is how innovation thrives, leading to a better business outcome. That is why we have put an emphasis on, and are committed to, elevating DEI and creating a great place to work. At ConocoPhillips, we believe our unique differences power the future of energy. Our DEI vision is to foster an inclusive culture that values the rich mixture of backgrounds, identities and workstyles of our people, built on equitable practices that support all employees in unlocking their full potential. Our commitment to DEI is foundational to our SPIRIT Values and to achieving our business objectives. All employees play a part in creating and sustaining an inclusive work environment because everyone benefits from DEI.

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

Western North Slope100.0ConocoPhillips44 - 1 44 Total Alaska177 17 34 200 Greater Prudhoe Area The Greater Prudhoe Area includes the Prudhoe Bay Unit, which consists of the Prudhoe Bay Field and five satellite fields, as well as the Greater Point McIntyre Area fields. Prudhoe Bay, the largest conventional oil field in North America, is the site of a large waterflood and enhanced oil recovery operation, supported by a large gas and water processing operation. Prudhoe Bay's western satellite fields are Aurora, Borealis, Polaris, Midnight Sun and Orion, while the Point McIntyre, Niakuk, Raven, Lisburne and North Prudhoe Bay State fields are part of the Greater Point McIntyre Area. Field installations include seven production facilities, two gas plants, two seawater plants and a central power station. Activity in 2022 consisted of rotary and coil tubing drilling throughout the year.

Montney The Montney is an unconventional resource play located in northeastern British Columbia. At December 31, 2022, we held approximately 300,000 acres of land with 100 percent working interest in the liquids-rich section of the Montney. In 2022, development activity consisted of drilling 17 horizontal wells and bringing 12 wells online. In addition, we are progressing development of additional pads along with construction on the second phase of our processing facility with start-up scheduled for the third quarter of 2023.

ConocoPhillips 2022 10-K 8 Business and PropertiesTable of Contents Visund is an oil and gas field located in the North Sea and consists of a floating drilling, production and processing unit, and subsea installations. Crude oil is transported by pipeline to a nearby third-party field for storage and export via tankers. The natural gas is transported to a gas processing plant at Kollsnes, Norway, through the Gassled transportation system. The Alvheim Field is located in the northern part of the North Sea near the border with the U.K. sector, and consists of a FPSO vessel and subsea installations. Produced crude oil is exported via shuttle tankers, and natural gas is transported to the Scottish Area Gas Evacuation (SAGE) Terminal at St. Fergus, Scotland, through the SAGE Pipeline. The Kobra East Gekko (KEG) project, a new subsea tieback to the Alvheim FPSO, is currently being developed, with first production expected in 2024.

Australia 2022 InterestOperatorCrude OilMBDNGLMBDNatural GasMMCFDTotalMBOED Average Daily Net Production Australia Pacific LNG47.5 %ConocoPhillips/Origin Energy- - 817 136 Australia Pacific LNG Pty Ltd. (APLNG), our joint venture with Origin Energy Limited and China Petrochemical Corporation (Sinopec), is focused on producing CBM from the Bowen and Surat basins in Queensland, Australia, to supply the domestic gas market and convert the CBM into LNG for export. Origin operates APLNG's upstream production and pipeline system, and we operate the downstream LNG facility, located on Curtis Island near Gladstone, Queensland, as well as the LNG export sales business. We operate two fully subscribed 4.5 million metric tonnes per year LNG trains. Approximately 3,500 net wells are ultimately expected to supply both the LNG sales contracts and domestic gas market. The wells are supported by gathering systems, central gas processing and compression stations, water treatment facilities and an export pipeline connecting the gas fields to the LNG facilities. The LNG is being sold to Sinopec under 20-year sales agreements for 7.6 million metric tonnes of LNG per year, and Japan-based Kansai Electric Power Co., Inc. under a 20-year sales agreement for approximately 1 million metric tonnes of LNG per year. In February 2022, we completed the acquisition of an additional 10 percent interest in APLNG from Origin Energy, increasing our ownership to 47.5 percent, with Origin and Sinopec retaining 27.5 percent and 25 percent interests, respectively.

ConocoPhillips 2022 10-K 16 Business and PropertiesTable of Contents The ELT has ultimate accountability for advancing our DEI commitments through a governance structure that includes a Chief Diversity Officer (CDO), a dedicated DEI organization and a global DEI Council consisting of senior leaders from across the company. The company sets goals and measures progress based on a transparent DEI strategy with four pillars that guide our focus and approach: people, programs and processes, culture and our external brand and reputation. All company leaders are accountable for setting personal DEI goals and advancing DEI through local efforts. Our DEI efforts and progress are regularly reviewed with the Board of Directors. In 2022, we welcomed our new CDO. Over the course of the year, the CDO established the DEI organization and embarked on a global listening tour to understand the impact of current efforts, areas for improvement and the overall employee experience. Based on the insights and perspectives from employees, the company's DEI strategy was refreshed. Highlights from our 2022 DEI accomplishments include: •Reviewing the results of the 2022 Perspectives survey and continuing to integrate the insights into our DEI efforts; •Staffing the newly established DEI organization;

Business and PropertiesTable of Contents Alaska The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas and NGLs. We are the largest crude oil producer in Alaska and have major ownership interests in two of North America's largest oil fields located on Alaska's North Slope: Prudhoe Bay and Kuparuk. We operate Kuparuk in addition to several fields on the Western North Slope, in which we have 100 percent interest. Additionally, we are one of Alaska's largest owners of state, federal and fee exploration leases, with approximately 1.2 million net undeveloped acres at year-end 2022. Alaska operations contributed 16 percent of our consolidated liquids production and two percent of our consolidated natural gas production.

2023 InterestOperatorCrude OilMBDNGLMBDNatural GasMMCFDTotalMBOED Average Daily Net Production Greater Prudhoe Area36.1 %Hilcorp66 16 35 87 Greater Kuparuk Area89.2-94.7ConocoPhillips64 - 2 65

ConocoPhillips 2023 10-K Business and PropertiesTable of Contents Lower 48 The Lower 48 segment consists of operations located in the 48 contiguous U.S. states and the Gulf of Mexico, with a portfolio mainly consisting of low cost of supply, short cycle time, resource-rich unconventional plays and commercial operations. Based on 2023 production volumes, the Lower 48 is our largest segment and contributed 64 percent of our consolidated liquids production and 76 percent of our consolidated natural gas production.

2023 Crude OilMBDNGLMBDNatural GasMMCFDTotalMBOED Average Daily Net Production Delaware Basin274 135 768 537 Eagle Ford114 61 306 226 Midland Basin105 42 205 182

ConocoPhillips 2023 10-K 2 Business and PropertiesTable 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, Malaysia, Libya, China and Qatar. The information listed below appears in the "Supplementary Data - Oil and Gas Operations" disclosures following the Notes to Consolidated Financial Statements and is incorporated herein by reference:

ConocoPhillips 2023 10-K 6 Business and PropertiesTable of Contents Canada Our Canadian operations consist of the Surmont oil sands development in Alberta, the liquids-rich Montney unconventional play in British Columbia and commercial operations. In 2023, operations in Canada contributed seven percent of our consolidated liquids production and three percent of our consolidated natural gas production.

2023 InterestOperatorCrude OilMBDNGLMBDNatural GasMMCFDBitumenMBDTotalMBOED Average Daily Net Production Surmont*100.0 %ConocoPhillips- - - 81 81 Montney100.0ConocoPhillips9 3 65 - 23

ConocoPhillips 2023 10-K Business and PropertiesTable of Contents Europe, Middle East and North Africa The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian sector of the North Sea, the Norwegian Sea, Qatar, Libya, and commercial and terminalling operations in the U.K. In 2023, operations in Europe, Middle East and North Africa contributed nine percent of our consolidated liquids production and 16 percent of our consolidated natural gas production.

Norway 2023 InterestOperatorCrude OilMBDNGLMBDNatural GasMMCFDTotalMBOED Average Daily Net Production Greater Ekofisk Area28.3-35.1%ConocoPhillips42 2 42 51

Heidrun24.0 Equinor10 - 39 17 Aasta Hansteen10.0 Equinor- - 66 11 Troll1.6 Equinor1 - 59 11 Visund9.1 Equinor1 2 48 11 Alvheim20.0 Aker BP5 - 10 7

Transportation We have a 35.1 percent interest in the Norpipe Oil Pipeline System, a 220-mile pipeline which carries crude oil from Ekofisk to a crude oil stabilization and NGLs processing facility in Teesside, U.K.

Facilities We operate and have a 40.25 percent ownership interest in a crude oil stabilization and NGLs processing facility at Teesside, U.K. to support our Norway operations. 9

ConocoPhillips 2023 10-K Business and PropertiesTable of Contents Qatar 2023 InterestOperatorCrude OilMBDNGLMBDNatural GasMMCFDTotalMBOED Average Daily Net Production

ConocoPhillips 2023 10-K 10 Business and PropertiesTable of Contents Asia Pacific The Asia Pacific segment has exploration and production operations in China, Malaysia, Australia and commercial operations in China, Singapore and Japan. In 2023, operations in the Asia Pacific segment contributed five percent of our consolidated liquids production and three percent of our consolidated natural gas production.

Millions of Barrels of Oil Equivalent Net Proved Reserves at December 312023 2022 2021 Crude oil Consolidated operations3,032 2,975 2,964 Equity affiliates89 93 63

Kebabangan (KBB)30.0 KPOC1 - 47 9 Siakap North-Petai21.0 PTTEP2 - 1 2 Total Malaysia28 - 48 36 We have varying stages of exploration, development and production activities across approximately 2.7 million net acres in Malaysia, with working interests in six PSCs. Four of these PSCs are located in waters off the eastern Malaysian state of Sabah: Block G, Block J, the Kebabangan Cluster (KBBC), which we do not operate, and Block SB405, an operated exploration block acquired in 2021. We also operate another two exploration blocks, Block WL4-00 and Block SK304, in waters off the eastern Malaysian state of Sarawak.

Block J Gumusut We own a 29.5 percent working interest in the unitized Gumusut Field. Gumusut Phase 3 first oil was achieved in 2022. Development drilling associated with Gumusut Phase 4, a four-well program targeting the Brunei acreage of the unitized Gumusut Field that straddles Malaysia and Brunei waters, is planned to commence in early 2024 with first oil anticipated in early 2025. The unitized Gumusut Field is operated on a FPS with oil evacuation via a pipeline to the Sabah Oil and Gas Terminal (SOGT) for tanker liftings.

Marketing Activities Our Commercial organization manages our worldwide commodity portfolio, which includes natural gas, crude oil, bitumen, NGLs, LNG and power. Marketing activities are performed through offices in the U.S., Canada, Europe and Asia. In marketing our production, we attempt to minimize flow disruptions, maximize realized prices and manage credit-risk exposure. Commodity sales are generally made at prevailing market prices at the time of sale. We also purchase and sell third-party commodity volumes to better position the company to satisfy customer demand while fully utilizing transportation and storage capacity.

Crude Oil, Bitumen and NGLs Our crude oil, bitumen and NGL revenues are derived from production in the U.S., Canada, Asia, Africa and Europe. These commodities are primarily sold under contracts with prices based on market indices, adjusted for location, quality and transportation.

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

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

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

A Compelling Culture How we do our work is what sets us apart and drives our performance. We are experts in what we do and continuously find ways to do our jobs better. Our different backgrounds, ideas and views drive our success. Together, we deliver strong performance, but not at all costs. We embrace our core cultural attributes that are shared by everyone, everywhere.

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

2023 Employees by Gender and Race/Ethnicity GlobalU.S. MaleFemaleWhitePOC* All Employees73 %27 %68 %32 % All Leadership74 26 76 24 Top Leadership74 26 82 18