COP 10-K diff: FY 2023-12-31 → FY 2025-12-31
Paragraph-level diff of Risk Factors (Item 1A) and Management's Discussion & Analysis (Item 7).
Item 1A · Risk Factors
+49 paragraphs −52 paragraphs ~49 changed
FY 2023-12-31 (earlier)
Item 1A. Risk Factors
You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. These risk factors are not the only risks we face. Our business could also be affected by additional risks and uncertainties not currently known to us or that we currently consider to be immaterial. If any of these risks or other risks that are yet unknown or currently considered immaterial were to occur, our business, operating results and financial condition, as well as the value of an investment in our common stock, could be materially and adversely affected.
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.
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.
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
20Risk Factors Table of ContentsOur 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 Accountin g 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.
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ConocoPhillips 2023 10-KRisk Factors Table of ContentsOur ability to sell and deliver the crude oil, bitumen, LNG, natural gas and NGLs that we produce also depends on the availability, proximity, and capacity of gathering, processing, compression, transportation and pipeline facilities and equipment, as well as any necessary diluents to prepare our crude oil, bitumen, LNG, natural gas and NGLs for transport. The facilities, equipment and diluents we rely on may be temporarily unavailable to us due to market conditions, extreme weather events, permitting delays and other regulatory matters, mechanical reasons or other factors or conditions, many of which are beyond our control. In addition, in certain newer plays, the capacity of necessary facilities, equipment and diluents may not be sufficient to accommodate production from existing and new wells, and construction and permitting delays, permitting costs and regulatory or other constraints could limit or delay the construction, manufacture or other acquisition of new facilities and equipment. If any facilities, equipment or diluents, or any of the transportation methods and channels that we rely on become unavailable for any period of time, we may incur increased costs to transport our crude oil, bitumen, LNG, natural gas and NGLs for sale; we may be forced to curtail our production of crude oil, bitumen, natural gas or NGLs or we may not be able to meet all the objectives in the Plan, such as reducing routine flaring.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.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.
ConocoPhillips 2023 10-K
22Risk Factors Table of ContentsLegal 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 Re sponse 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,
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ConocoPhillips 2023 10-KRisk Factors Table of Contentsimpact 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
ConocoPhillips 2023 10-K
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Risk Factors Table of Contents
Willow project in Alaska. In the event that ballot initiatives, local, state, or national restrictions or prohibitions are adopted and result in more stringent limitations on the production and development of oil and natural gas in areas where we conduct operations, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the permitting or pursuit of exploration, development or production activities. Such compliance costs and delays, curtailments, limitations or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, liquidity and ability to implement and advance the Plan.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.
Any of these actions could adversely affect our business or operating results, including our ability to implement and advance the Plan.Other Risk Factors Facing our Business or Operations
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
ConocoPhillips 2023 10-K
Risk Factors Table of Contents
Our business may be adversely affected by deterioration in the credit quality of, or defaults under our contracts with, third-parties with whom we do business.
The operation of our business requires us to engage in transactions with numerous counterparties operating in a variety of industries, including other companies operating in the oil and gas industry. These counterparties may default on their obligations to us as a result of operational failures or a lack of liquidity, or for other reasons, including bankruptcy. Market speculation about the credit quality of these counterparties, or their ability to continue performing on their existing obligations, may also exacerbate any operational difficulties or liquidity issues they are experiencing. Any default by any of our counterparties may result in our inability to perform our obligations under agreements we have made with third-parties or may otherwise adversely affect our business or results of operations. In addition, our rights against any of our counterparties as a result of a default may not be adequate to compensate us for the resulting harm caused or may not be enforceable at all in some circumstances. We may also be forced to incur additional costs as we attempt to enforce any rights we have against a defaulting counterparty, which could further adversely impact our results of operations.Our ability to execute our capital return program is subject to certain considerations.In December 2021, we initiated a three-tier capital return program that consists of our ordinary dividend, share repurchases and a variable return of cash (VROC).Ordinary dividends are authorized and determined by our Board of Directors in its sole discretion and depend upon a number of factors, including:
• Cash available for distribution;
• Our results of operations and anticipated future results of operations;• Our financial condition, especially in relation to the anticipated future capital needs of our properties;• The level of distributions paid by comparable companies;
• Our operating expenses; and
• Other factors our Board of Directors deems relevant.VROC distributions are also authorized and determined by our Board of Directors in its sole discretion and depend upon a number of factors, including:
• The anticipated level of distributions required to meet our capital returns commitment;
• Forward prices;
• The amount of cash we hold;
• 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.
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26Risk Factors Table of Contents
There are substantial risks with any acquisitions or divestitures we have completed or that we may choose to undertake.
We regularly review our portfolio and pursue growth through acquisitions and seek to divest noncore assets or businesses. We may not be able to complete these transactions on favorable terms, on a timely basis, or at all. Even if we do complete such transactions, our cash flow from operations may be adversely impacted or otherwise the transactions may not result in the benefits anticipated due to various risks, including, but not limited to (i) the failure of the acquired assets or businesses to meet or exceed expected returns, including risk of impairment; (ii) the inability to dispose of noncore assets and businesses on satisfactory terms and conditions; and (iii) the discovery of unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections are inadequate or we lack insurance or indemnities, including environmental liabilities, or with regard to divested assets or businesses, claims by purchasers to whom we have provided contractual indemnification. In addition, we may face difficulties in integrating the operations, technologies, products and personnel of any acquired assets or businesses.
Our technologies, systems and networks are subject to cybersecurity threats.
Our business is faced with growing cybersecurity threats as we increasingly rely on digital technologies across our business. Cybersecurity risks to our business, including our suppliers, third-party service providers, contractors, joint venture partners and external business partners, include but are not limited to:
• Unauthorized access to, or control of or disclosure of sensitive information about our business and our employees;• Compromise of our data or systems, including corruption, sabotage, encryption or acts that otherwise render our data or systems unusable (or those of third-parties with whom we do business, including third-party cloud and information technology (IT) service providers);• Theft or manipulation of our proprietary information;
• Ransom;
• Extortion;
• Threats to the security of our facilities and infrastructure; and
• Cyber terrorism.In addition, we have exposure to cybersecurity risks where our data and proprietary information are collected, hosted, and/or processed by third-party cloud and service providers. Our risks may be exacerbated by a delay or failure to detect a cybersecurity incident or understand the full extent of such incident notwithstanding our risk management processes and controls. We face risks associated with new and ever-increasing phishing techniques, hidden malware, as well as risks associated with electronic data proliferation and technology digitization. We also face increased risk with the increased sophistication of Generative Artificial Intelligence capabilities, which may improve or expand the existing capabilities of cybercriminals described above in a manner we cannot predict at this time.Our increasing reliance on IT in our production, distribution and marketing systems may allow cybersecurity threats to disrupt our oil and gas operations, both domestically and abroad.If our data, IT, operational technology (OT), including industrial control and supervisory control and data acquisition (SCADA) systems were to be breached, damaged or disrupted due to a cybersecurity incident or cyber-attack (directly, indirectly through third-parties or through the IT networks, servers, software, or infrastructure on which they rely), we could be subject to serious negative consequences. These consequences could include physical damage to production, distribution or storage assets; delay or prevention of delivery to markets; disruption or prevention of accurate accounting for production and settlement of transactions; negative impacts on public health, safety, the environment, economic security, or national security; financial impacts; business interruption; reputational damage; loss of employee, supplier, contractor, partner and/or public trust; reimbursement or other costs; increased compliance costs; regulatory investigations; litigation exposure and legal liability or regulatory fines; penalties or other external intervention.
Although we have business continuity plans in place, our operations may be adversely affected by significant and widespread disruption to our systems and infrastructure that support our business. Further, our ability to insure against cybersecurity risks may be limited by the availability and increasing expense of sufficient coverage.
For additional information regarding our cybersecurity risk management, strategy and governance, see I tem 1C. Cyber s ecurity .
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ConocoPhillips 2023 10-KTable of Contents
FY 2025-12-31 (later)
Item 1A. Risk Factors
You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. These risk factors are not the only risks we face. Our business could also be affected by additional risks and uncertainties not currently known to us or that we currently consider to be immaterial. If any of these risks or other risks that are yet unknown or currently considered immaterial were to occur, our business, operating results and financial condition, as well as the value of an investment in our common stock, could be materially and adversely affected.
Risks Related to Our Industry
Our operating results, our ability to execute on our strategy and the carrying value of our assets are exposed to the effects of volatile commodity prices or prolonged periods of low commodity prices.Among the most significant factors impacting our revenues, operating results and future rate of growth are the sales prices for crude oil, bitumen, LNG, natural gas and NGLs. These prices are tied to market prices that can fluctuate widely due to factors beyond our control. For example, over the course of 2025, WTI crude oil prices ranged from a high of $80 per barrel in January to a low of $55 per barrel in December. Given the volatility in the drivers of commodity prices and our associated realizations, the worldwide political and economic environment, including potential economic slowdowns or recessions, unexpected shocks to supply and demand, or increased uncertainty generated by armed hostilities and geopolitical tension and escalations in various oil-producing regions around the globe, prices for crude oil, bitumen, LNG, natural gas and NGLs may continue to be volatile.
Prolonged periods of low commodity prices could have a material adverse effect on our revenues, operating income, cash flows and liquidity, and may also affect the amount of dividends we elect to declare and pay on our common stock and the amount of shares we elect to acquire as part of our share repurchase program and the timing of such repurchases.
Lower prices may also limit the amount of reserves we can produce economically, thus adversely affecting our proved reserves and reserve replacement ratio and accelerating the reduction in our existing proved reserve levels as we continue production from upstream fields. Prolonged depressed prices may affect strategic decisions related to our operations, including decisions to reduce capital investments or curtail operated production.
Significant reductions in crude oil, bitumen, LNG, natural gas and NGLs prices could also require us to reduce our capital expenditures, impair the carrying value of our assets or discontinue the classification of certain assets as proved reserves. Although it is not reasonably practicable to quantify the impact of any future impairments or estimated change to our unit-of-production rates at this time, our results of operations could be adversely affected as a result.
If we do not successfully develop resources, the scope of our business will decline, and our financial condition and results of operations may be adversely affected.As we produce crude oil, bitumen, natural gas and NGLs from our existing portfolio, the amount of our remaining reserves declines. If we do not successfully replace the resources we produce with good prospects for future organic development or through acquisitions, our business will decline. In addition, our ability to successfully develop our reserves depends on our achievement of a number of operational and strategic objectives, some aspects of which are beyond our control, including navigating political and regulatory challenges to obtain and renew rights to develop and produce hydrocarbons; reservoir optimization; bringing long-lead time, capital intensive projects to completion on budget and on schedule; and efficiently and profitably operating mature properties. If we are not successful in developing the resources in our portfolio, our financial condition and results of operations may be adversely affected.
The exploration and production of oil and gas is a highly competitive industry.The exploration and production of crude oil, bitumen, natural gas and NGLs is a highly competitive business. We compete with private, public and state-owned companies in all facets of the exploration and production business, including locating, acquiring and developing new sources of supply and producing crude oil, bitumen, natural gas and NGLs in an efficient, cost-effective manner. In addition, we anticipate the oil and gas industry will face additional competition from alternative fuels. We must also compete for the materials, equipment, services, employees and other personnel (including geologists, geophysicists, engineers and other specialists) necessary to conduct our business. If we are not successful in any facet of this competition, our financial condition and results of operations may be adversely affected.
ConocoPhillips 2025 10-K
18Risk Factors Table of ContentsOur ability to successfully execute on our plans to reduce operational GHG emissions intensity is subject to a number of risks and uncertainties and such reductions may be costly and challenging to achieve.
Our framework for managing climate-related business risk is set out in our Climate-related Risk Strategy, which describes our strategic flexibility, approach to reducing Scope 1 and 2 emissions intensity, technology choices and engagement efforts. Among other things, we have set near- and medium-term GHG intensity reduction targets, as well as targets around flaring and methane. Our ability to achieve the stated targets, goals and ambitions within the Climate-related Risk Strategy's framework is subject to a number of risks and uncertainties beyond our control, including government policies and markets, acceptance of carbon capture technologies, development of markets and potential permitting and regulatory changes, all of which may impair our ability to execute on current or future plans. In addition, the pace of development of effective emissions measurement and abatement technologies, and the actual pace of deployment may be inadequate, or the technologies actually developed may be insufficient to allow us to achieve our stated targets, goals and ambitions.
Furthermore, executing our Climate-related Risk Strategy could be costly, is likely to encounter unforeseen obstacles, will proceed at varying paces and may be accomplished in a manner that we cannot predict at this time. We expect to be required to purchase emission credits and/or offsets in the future. There may be an insufficient supply of offsets, and we could incur increasingly greater expenses related to our purchase of such offsets. Even if we are able to acquire an adequate amount of such offsets at satisfactory prices, investors, regulators or other third parties may not perceive this practice as an acceptable means of achieving our operational emission reduction targets. As advanced technologies are developed to accurately measure emissions, we may be required to revise our emissions estimates and reduction goals or otherwise revise aspects of our Climate-related Risk Strategy. We may be adversely affected and potentially need to reduce economic end-of-field life of certain assets and impair associated net book value due to the emissions intensity of some of our assets. Even if we meet our goals, our efforts may be characterized as insufficient.
We continue to evaluate low carbon opportunities for potential future investment in support of our operational emission reduction targets. Such potential investments may expose us to numerous financial, legal, operational, reputational and other risks and may not ultimately contribute materially to operational emissions reductions. The success of any such investment will depend in part upon the cooperation of government agencies, the support of stakeholders, the development of relevant markets for low carbon fuels, our ability to research and forecast potential investments, willingness of industry partners to collaborate and our ability to apply our existing strengths and expertise to new technologies, projects and markets.Estimates of crude oil, bitumen, natural gas and NGL reserves are imprecise and may be subject to revision, and any material change in the factors and assumptions underlying our estimates of crude oil, bitumen, natural gas and NGL reserves could impair the quantity and value of those reserves.Our proved reserve information included in this annual report represents management’s best estimates based on assumptions, as of a specified date, of the volumes to be recovered from underground accumulations of crude oil, bitumen, natural gas and NGLs. Such volumes cannot be directly measured, and the estimates and underlying assumptions used by management are subject to substantial risk and uncertainty. Any material changes in the factors and assumptions underlying our estimates of these items could result in a material negative impact to the volume of reserves reported or could cause us to incur impairment expenses on property associated with the production of those reserves. Future reserve revisions could also result from changes in, among other things, governmental regulation and commodity prices. For more information on estimates used, see the "Critical Accounting Estimates" section of Management's Discussion and Analysis of Financial Condition and Results of Operations .
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ConocoPhillips 2025 10-KRisk Factors Table of ContentsOur business may be adversely affected by price controls; government-imposed limitations on production or exports of crude oil, bitumen, LNG, natural gas and NGLs; or the unavailability of adequate gathering, processing, compression, transportation, and pipeline facilities and equipment for our production of crude oil, bitumen, natural gas and NGLs.
As discussed herein, our operations are subject to extensive governmental regulations across numerous jurisdictions. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil, bitumen, natural gas and NGLs wells below actual production capacity. Similarly, in response to increased domestic energy costs, circumstances determined to be in the economic or other interest of the country, or a declared national emergency, governments could restrict the export or import of our products which would adversely impact our business. For example, in January 2024, in response to concerns from environmental groups, the U.S. announced a temporary pause on new authorizations of certain LNG exports. The pause was subsequently lifted in January 2025. This pause and other difficulties in the regulatory approval processes may have an extended adverse impact on our global LNG business. Furthermore, because legal requirements are frequently changed and subject to interpretation, we cannot predict whether future restrictions on our business may be enacted or become applicable to us.
Our ability to sell and deliver the crude oil, bitumen, LNG, natural gas and NGLs that we produce also depends on the availability, proximity and capacity of gathering, processing, compression, transportation and pipeline facilities and equipment, as well as any necessary diluents to prepare our crude oil, bitumen, LNG, natural gas and NGLs for transport. The facilities, equipment and diluents we rely on may be temporarily unavailable to us due to market conditions, extreme weather events, permitting delays and other regulatory matters, mechanical reasons or other factors or conditions, many of which are beyond our control. In addition, in certain newer plays, the capacity of necessary facilities, equipment and diluents may not be sufficient to accommodate production from existing and new wells, and construction and permitting delays, permitting costs and regulatory or other constraints could limit or delay the construction, manufacture or other acquisition of new facilities and equipment. If any facilities, equipment or diluents, or any of the transportation methods and channels that we rely on become unavailable for any period of time, we may incur increased costs to transport our crude oil, bitumen, LNG, natural gas and NGLs for sale; we may be forced to curtail our production of crude oil, bitumen, natural gas or NGLs, or we may not be able to meet all the objectives in our Climate-related Risk Strategy, such as reducing routine flaring.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 the 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.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 and escalations; 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 technological challenges, operating risks and potential for adverse consequences from operational failures 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 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.
ConocoPhillips 2025 10-K
20Risk Factors Table of ContentsIn 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 our Climate-related Risk Strategy; 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.Legal and Regulatory Risks
We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations.Our business is subject to numerous laws and regulations relating to the protection of the environment, which are expected to continue to have an increasing impact on our operations. For a description of the most significant of these environmental laws and regulations, see the “Contingencies—Environmental” , “—Climate Change” and "—Company Response to Climate-Related Risks" sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations. These laws and regulations continue to increase in both number and complexity and affect our operations with respect to, among other things:
• Permits required in connection with exploration, drilling, production and other activities, including those issued by national, subnational and local authorities;• The discharge of pollutants into the environment;• Emissions into the atmosphere, such as nitrogen oxides, sulfur dioxide, mercury and GHG emissions, including methane and carbon dioxide;• Carbon taxes;
• The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous and nonhazardous wastes;
• 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 our Climate-related Risk Strategy could be adversely affected.
Existing and future laws, regulations and internal initiatives relating to global climate change, such as limitations on GHG emissions or provisions aimed at reducing such 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 our Climate-related Risk Strategy.
For example, in 2024, New York and Vermont passed legislation seeking to hold certain energy companies financially responsible for state climate change mitigation and adaptation measures, following the "polluter pays" model of existing Superfund laws. This responsibility may include paying into a fund for infrastructure repairs and recovery from extreme
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ConocoPhillips 2025 10-KRisk Factors Table of Contentsweather events that would otherwise be covered by the government. While only two U.S. states have enacted such laws to date, other states have introduced similar measures, and it is likely that more states will consider a similar approach. Compliance with such legislation may expose us to significant additional liabilities. Additionally, legislation has been introduced in certain U.S. states that would provide Attorneys General, insurers and individuals a right to recover against certain energy companies for alleged climate change impacts. Should such legislation become law, we may be exposed to additional, significant liabilities.
Furthermore, in December 2023, the EPA published a final rule that revises the regulations governing, among other things, the emission of methane and volatile organic compounds from new oil and gas production facilities and emission guidelines for states to use when revising Clean Air Act implementation plans to limit methane emissions from existing oil and gas facilities. However, in 2025 the EPA moved to dismantle some climate-related regulations (e.g. delaying compliance deadlines for methane standards and proposing to eliminate most obligations under the Greenhouse Gas Reporting Program). These policy swings create additional uncertainty for companies who need to plan for operations that will endure through administrations. These regulatory changes may also complicate our ability to access non-operated or joint venture emissions data to complete our inventory of emissions.
Additionally, international climate initiatives, such as the United Nations Conference of the Parties summits, continue to shape the global response to climate change. These summits can lead to commitments from numerous countries to meet the objectives of agreements like the Paris Agreement, through adopting country level regulation to reduce greenhouse gas emissions.
The implementation of current agreements and regulatory or judicial measures, as well as any future agreements or measures addressing climate change and GHG emissions, may adversely increase our capital and operating expenses, impact the demand for our products, impose taxes on our products or operations, or require us to purchase emission credits or reduce emissions of GHGs from our operations. As a result, we may incur substantial capital expenditures and compliance, operating, maintenance and remediation costs, any of which may have an adverse effect on our business and results of operations.
For more information on legislation or precursors for possible regulation relating to global climate change that affect or could affect our operations and a description of the company's response, see the "Contingencies—Climate Change” and "—Company Response to Climate-Related Risks" sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations.Broader investor and societal attention to and efforts to address global climate change may limit who can do business with us or our access to financial markets and could subject us to litigation.Attention to global climate change has also resulted in pressure from and upon stockholders, financial institutions and other financial market participants to potentially limit or discontinue investments, insurance and funding to oil and gas companies. For example, a significant number of financial institutions have pledged to meet the goal of net zero by 2050, as well as setting interim targets for 2030 or earlier. While these targets do not prohibit financial sector stakeholders from doing business with oil and gas companies, stakeholders may self-impose limits. Conversely, we also face pressure from some in the investment community and certain public interest groups to limit the focus on ESG in our decision-making, arguing that ESG considerations do not relate to financial outcomes. As public pressure continues to mount on the financial sector, our costs of capital may increase.
Furthermore, 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 2025, 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 by governmental entities. In 2025, a putative class action was filed against oil and gas companies, including ConocoPhillips, seeking to hold energy companies liable for increased home insurance premiums allegedly due to climate change losses. The amounts claimed by plaintiffs are unspecified and the legal and factual issues involved in these cases are unprecedented. We believe these lawsuits are factually and legally meritless and are an inappropriate vehicle to address the challenges associated with climate change, and we will vigorously defend against such lawsuits. The ultimate outcome and impact to us cannot be predicted with certainty, and we expect to incur substantial legal costs associated with defending these and similar lawsuits in the future. We could also receive lawsuits alleging a failure or lack of diligence to meet our publicly stated ESG goals or alleging misrepresentation related to our ESG activity.
ConocoPhillips 2025 10-K
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Risk Factors Table of ContentsPolitical and economic developments could damage our operations and materially reduce our profitability and cash flows.Actions of the U.S., state, local and foreign governments, through sanctions, tax, tariffs and other legislation, executive orders and commercial restrictions, could reduce our operating profitability both in the U.S. and abroad. In certain locations, restrictions on our operations; leasing restrictions; special taxes or tax assessments; tariffs; and payment transparency regulations that could require us to disclose competitively sensitive information or might cause us to violate non-disclosure laws of other countries have been imposed or proposed by governments or certain interest groups. In addition, we may face regulatory changes in the U.S. including, but not limited to, the enactment of tax law changes that adversely affect the fossil fuel industry, new methane emissions standards, requirements restricting or prohibiting flaring and subsurface water disposal, more stringent environmental impact studies and reviews and policies inhibiting or curtailing LNG or crude oil exports. Similar regulatory shifts, including attendant higher costs and market access constraints, may also occur in international jurisdictions in which we currently operate or seek to operate.Hydraulic fracturing, an essential completion technique that facilitates production of oil and natural gas otherwise trapped in lower permeability rock formations, has historically attracted political and regulatory scrutiny. A range of local, state, federal and national laws and regulations currently govern, constrain or prohibit hydraulic fracturing in some jurisdictions. New or more stringent permitting, disclosure or other regulatory requirements on hydraulic fracturing or other oil and natural gas operations, including subsurface water disposal, could result in increased costs, operating restrictions or operational delays or could limit the ability to develop oil and natural gas resources.In addition, certain interest groups have also proposed ballot initiatives, contested lease sales and challenged project permits, for example, to restrict oil and natural gas development generally as well as specific projects, including the Willow project in Alaska. In the event that ballot initiatives, local, state, or national restrictions or prohibitions are adopted and result in more stringent limitations on the production and development of oil and natural gas in areas where we conduct operations, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the permitting or pursuit of exploration, development or production activities. Such compliance costs and delays, curtailments, limitations or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, liquidity and ability to implement and advance the Climate-related Risk Strategy.Political and economic factors in international markets could have a material adverse effect on us.Approximately 29 percent of our hydrocarbon production was derived from production outside the U.S. in 2025, and 31 percent of our proved reserves, as of December 31, 2025, were located outside the U.S. We are subject to risks associated with our operations in foreign jurisdictions and international markets, including changes in foreign governmental policies relating to crude oil, bitumen, LNG, natural gas or NGLs pricing and taxation; other regulatory or economic developments (including the macro effects of U.S. and international trade policies and disputes); disruptive geopolitical conditions such as recent conflict escalation in the Middle East and Eastern Europe; and international monetary and currency rate fluctuations. Restrictions on production of oil and gas could increase to the extent governments view such measures as a viable approach for pursuing national and global energy security and climate policies. In addition, some countries where we operate lack a fully independent judiciary system. This, coupled with changes in foreign law or policy, results in a lack of legal certainty that exposes our operations to increased risks, including increased difficulty in enforcing our agreements in those jurisdictions and increased risks of adverse actions by local government authorities, such as expropriations. Actions by host governments, such as the expropriation of our oil assets by the Venezuelan government, have affected operations significantly in the past and may continue to do so in the future.
In addition, the U.S. government has the authority to prevent or restrict us from doing business in foreign jurisdictions or with certain parties. These restrictions and similar restrictions imposed by foreign governments have in the past limited our ability to operate in, or gain access to, opportunities in various jurisdictions. Diplomatic relations or policies between the U.S. government and one or more foreign jurisdictions may increase our expenses or impair our ability to collect awards in legal actions against such foreign jurisdictions. Changes in domestic and international policies and regulations may also restrict our ability to obtain or maintain licenses or permits necessary to operate in foreign jurisdictions, including those necessary for drilling and development of wells. Similarly, the declaration of a “climate emergency” could result in actions to limit exports of our products and other restrictions.
Any of these actions could adversely affect our business or operating results, including our ability to implement and advance the Climate-related Risk Strategy.
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ConocoPhillips 2025 10-K
Risk Factors Table of ContentsOther Risk Factors Facing our Business or Operations
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.Our business may be adversely affected by deterioration in the credit quality of, or defaults under our contracts with, third parties with whom we do business.
The operation of our business requires us to engage in transactions with numerous counterparties operating in a variety of industries, including other companies operating in the oil and gas industry. These counterparties may default on their obligations to us as a result of operational failures or a lack of liquidity, or for other reasons, including bankruptcy. Market speculation about the credit quality of these counterparties, or their ability to continue performing on their existing obligations, may also exacerbate any operational difficulties or liquidity issues they are experiencing. Any default by any of our counterparties may result in our inability to perform our obligations under agreements we have made with third parties or may otherwise adversely affect our business or results of operations. In addition, our rights against any of our counterparties as a result of a default may not be adequate to compensate us for the resulting harm caused or may not be enforceable at all in some circumstances. We may also be forced to incur additional costs as we attempt to enforce any rights we have against a defaulting counterparty, which could further adversely impact our results of operations.Our ability to execute our capital return program is subject to certain considerations.Ordinary dividends are authorized and determined by our Board of Directors in its sole discretion and depend upon a number of factors, including:
• Cash available for distribution;
• Our results of operations and anticipated future results of operations;• Our financial condition, especially in relation to anticipated future capital needs;• The level of distributions paid by comparable companies;
• Our operating expenses; and
• Other factors our Board of Directors deems relevant.We paid a quarterly ordinary dividend to our shareholders in each quarter of 2025. Our Board may determine not to pay a dividend in a quarter or may cease declaring a dividend at any time.
Additionally, as of December 31, 2025, up to $25.7 billion of share repurchase authority remained. Our share repurchase program does not obligate us to acquire a specific number of shares during any period, and our decision to commence, discontinue or resume repurchases in any period will depend on the same factors that our Board of Directors may consider when declaring dividends, among other factors. In the past, we have suspended our share repurchase program in response to market downturns, including as a result of the oil market downturn that began in early 2020, and we may do so again in the future.
Any downward revision in the amount of our ordinary dividend or the volume of shares we purchase under our share repurchase program could have an adverse effect on the market price of our common stock.
ConocoPhillips 2025 10-K
24Risk Factors Table of Contents
There are substantial risks with any acquisitions or divestitures we have completed or that we may choose to undertake.
We regularly review our portfolio and pursue growth through acquisitions and seek to divest noncore assets or businesses. We may not be able to complete these transactions on favorable terms, on a timely basis, or at all. Even if we do complete such transactions, our cash flow from operations may be adversely impacted or otherwise the transactions may not result in the benefits anticipated due to various risks, including, but not limited to (i) the failure of the acquired assets or businesses to meet or exceed expected returns, including risk of impairment; (ii) the inability to dispose of noncore assets and businesses on satisfactory terms and conditions; and (iii) the discovery of unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections are inadequate or we lack insurance or indemnities, including environmental liabilities, or with regard to divested assets or businesses, claims by purchasers to whom we have provided contractual indemnification. In addition, we may face difficulties in integrating the operations, technologies, products and personnel of any acquired assets or businesses.
Our technologies, systems and networks are subject to cybersecurity threats.
Our business is faced with growing cybersecurity threats as we increasingly rely on digital technologies across our business. Cybersecurity risks to our business, including our suppliers, third-party service providers, contractors, joint venture partners and external business partners, include but are not limited to:
• Unauthorized access to, or control of or disclosure of sensitive information about our business and our employees;• Compromise of our data or systems, including corruption, sabotage, encryption or acts that otherwise render our data or systems unusable (or those of third parties with whom we do business, including third-party cloud and information technology (IT) service providers);• Theft or manipulation of our proprietary information;
• Ransom;
• Extortion;
• Threats to the security of our facilities and infrastructure; and
• Cyber terrorism.In addition, we have exposure to cybersecurity risks where our data and proprietary information are collected, hosted, and/or processed by third-party cloud and service providers. In addition, many of our vendors, including suppliers that are closely integrated into our business, have been victims of cybersecurity attacks that have accessed and exfiltrated information from their systems. Our risks may be exacerbated by a delay or failure to detect a cybersecurity incident or to understand the full extent of such incident notwithstanding our risk management processes and controls. We face risks associated with new and ever-increasing phishing techniques, hidden malware, as well as risks associated with electronic data proliferation and technology digitization. We also face increased risk with the increased sophistication of generative artificial intelligence capabilities, which may improve or expand the existing capabilities of cybercriminals described above in a manner we cannot predict at this time.Our increasing reliance on IT in our production, distribution and marketing systems may allow cybersecurity threats to disrupt our oil and gas operations, both domestically and abroad.If our data, IT, operational technology (OT), including industrial control and supervisory control and data acquisition (SCADA) systems were to be breached, damaged or disrupted due to a cybersecurity incident or cyber-attack (directly, indirectly through third parties or through the IT networks, servers, software, or infrastructure on which they rely), we could be subject to serious negative consequences. These consequences could include physical damage to production, distribution or storage assets; delay or prevention of delivery to markets; disruption or prevention of accurate accounting for production and settlement of transactions; negative impacts on public health, safety, the environment, economic security, or national security; financial impacts; business interruption; reputational damage; loss of employee, supplier, contractor, partner and/or public trust; reimbursement or other costs; increased compliance costs; regulatory investigations; litigation exposure and legal liability or regulatory fines; penalties or other external intervention.
Although we have business continuity plans in place, our operations may be adversely affected by significant and widespread disruption to our systems and infrastructure that support our business. If we seek insurance against cybersecurity risks, it may be limited by the availability and increasing expense of sufficient coverage.
For additional information regarding our cybersecurity risk management, strategy and governance, see Item 1C. Cybersecurity .
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ConocoPhillips 2025 10-KTable of Contents
Item 7 · Management's Discussion & Analysis
+411 paragraphs −412 paragraphs ~411 changed
FY 2023-12-31 (earlier)
Item 7. Management’s Discussion and Analysis of Financial Condition and
Results of OperationsManagement’s Discussion and Analysis is the company’s analysis of its financial performance and of significant trends and uncertainties that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “ambition,” “anticipate,” “believe,” “budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 65 .The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss).
Business Environment and Executive OverviewConocoPhillips 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.OverviewAt ConocoPhillips, we anticipate that commodity prices will continue to be cyclical and volatile, and our view is that a successful business strategy in the E&P industry must be resilient in lower price environments while also retaining upside during periods of higher prices. As such, we are unhedged, remain committed to our disciplined investment framework and continually monitor market fundamentals, including the impacts associated with geopolitical tensions and conflicts, OPEC Plus supply updates, global demand for our products, oil and gas inventory levels, governmental policies, inflation and supply chain disruptions.
The macro-environment of the global energy industry, including the energy transition, continues to evolve. We believe ConocoPhillips will continue to play an essential role by executing on three objectives: responsibly meeting energy transition pathway demand, delivering competitive returns on and of capital and achieving our net-zero operational emissions ambition. We call this our Triple Mandate, and it represents our commitment to create long-term value for our stakeholders.
Our Triple Mandate and our foundational principles guide our differential value proposition to deliver competitive returns to stockholders through price cycles. Our foundational principles consist of maintaining balance sheet strength, providing peer-leading distributions, making disciplined investments, and demonstrating responsible and reliable ESG performance.
Total company production in 2023 was 1,826 MBOED, yielding cash provided by operating activities of $20 billion. We invested $11.2 billion into the business in the form of capital expenditures and investments and provided returns of capital to shareholders of approximately $11 billion through our ordinary dividend, share repurchases and our VROC. For 2023, we returned $2.6 billion from our ordinary dividend, which included an increase from 51 cents per share to 58 cents per share, effective in December. We also returned $3.0 billion to shareholders from the VROC in 2023. In total for 2023, we returned $5.4 billion to shareholders through share repurchases. As of December 31, 2023, we have repurchased $28.8 billion of the $45 billion authorized share repurchase program. In February 2024, we announced our 2024 planned return of capital to shareholders of $9 billion through our three-tier return of capital framework. We also declared a first quarter ordinary dividend of 58 cents per share and a VROC of 20 cents per share.
In March, the Department of Interior published its ROD approving our Willow project in Alaska, which adopted a plan consisting of three core pads. In December, following a Ninth Circuit Court of Appeals denial of a request for an injunction, we reached FID on the Willow project and began winter construction.
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34Management’s Discussion and Analysis
Table of ContentsIn October, we completed our acquisition of the remaining 50 percent working interest in Surmont, an asset in our Canada segment, for $2.7 billion of cash after customary adjustments. The transaction was funded by proceeds received via long-term debt offerings. This transaction includes a contingent payment arrangement of up to an additional $0.4 billion CAD (approximately $0.3 billion) over a five-year term. As the 100 percent owner and operator of Surmont, we will seek to optimize the asset while remaining on track to achieve our previously announced corporate emissions intensity objectives. S ee Note 3 .
In 2023, we took several steps to further our global LNG business. In March, we completed our acquisition of 30 percent equity interest in PALNG Phase 1. In June, we completed our acquisition of a 25 percent equity interest in NFS3 in Qatar. Additionally, in June, we signed a 20-year offtake agreement at the Saguaro LNG export facility on the west coast of Mexico, subject to Mexico Pacific reaching FID and other certain conditions precedent. Furthermore, in September, we signed a 15-year throughput agreement securing regasification capacity at the Gate LNG terminal in the Netherlands. See Note 3 .
In the second quarter of 2023, we completed a strategic debt refinancing that extends the weighted average maturity of our portfolio from 15 to 17 years and reduces near term debt maturities. See Note 9 .
In April, we announced that we are accelerating our operations GHG emissions intensity reduction target through 2030. We are now targeting a reduction in gross operated and net equity operational emissions intensity of 50-60 percent from 2016 levels by 2030, an improvement from the previously announced target of 40-50 percent. In December, we achieved the Gold Standard Pathway in the Oil and Gas Methane Partnership (OGMP) 2.0 Initiative. For more information on our commitment to ESG and the Plan, see "Contingencies—Company Response to Climate-Related Risks" section of Management's Discussion and Analysis of Financial Condition and Results of Operation .
Operationally, we remain focused on safely executing the business. Our Lower 48 segment achieved record production in 2023. Our international projects reached several key operational milestones, including first production ahead of schedule at several subsea projects in Norway and China, as well as the startup of the second phase of Montney’s central processing facility in Canada. Production for 2023 was 1,826 MBOED, representing an increase of 88 MBOED or 5 percent compared to 2022. After adjusting for closed acquisitions and dispositions, production increased by 73 MBOED or 4 percent.
Key Operating and Financial Summary
Significant items during 2023 and recent announcements included the following:
• Generated cash provided by operating activities of $20.0 billion;
• Distributed $11.0 billion to shareholders through a three-tier framework, including $5.6 billion through the ordinary dividend and VROC and $5.4 billion through share repurchases;
• Ended the year with cash, cash equivalents, and restricted cash of $5.9 billion and short-term investments of $1.0 billion;
• Delivered record full-year total and Lower 48 segment production of 1,826 MBOED and 1,067 MBOED, respectively;
• Acquired the remaining 50 percent working interest in Surmont for approximately $2.7 billion as well as future contingent payments of up to $0.4 billion CAD ($0.3 billion);
• Took FID on the Willow project;
• Progressed global LNG strategy through expansion in Qatar, FID at PALNG and regasification agreements in the Netherlands and offtake agreements in Mexico;
• Reached first production at several subsea tiebacks in Norway, Surmont Pad 267 in Canada and Bohai Phase 4B in China;
• Commenced startup at the second phase of Montney's central processing facility in Canada;
• Awarded the Gold Standard Pathway designation by OGMP 2.0; and
• Accelerated the company's GHG emissions-intensity reduction target through 2030 from 40-50 percent to 50-60 percent, using a 2016 baseline.
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ConocoPhillips 2023 10-KManagement’s Discussion and Analysis
Table of Contents
Business EnvironmentThe energy industry has historically been subject to volatility in commodity prices, which fluctuate with the global economy's supply and demand for energy. For example, WTI crude oil prices averaged $78 per barrel in 2023, compared with $94 per barrel in 2022. Our profitability, reinvestment of cash flows and distributions to shareholders are influenced by these fluctuations. Our Triple Mandate and foundational principles guide our differential value proposition to deliver competitive returns on and of capital to stockholders through price cycles. Our foundational principles consist of maintaining balance sheet strength, providing peer-leading distributions, making disciplined investments and demonstrating responsible and reliable ESG performance, all of which support strong financial returns and mitigate uncertainty associated with volatile commodity prices.
• Balance sheet strength. A strong balance sheet is a strategic asset that provides flexibility through price cycles. We strive to maintain our ‘A’-rating, as we did throughout 2023. In 2023, we initiated and completed a strategic debt refinancing to extend the weighted average maturity of our portfolio and reduced near-term debt maturities. In addition, we also funded the acquisition of the remaining 50 percent working interest in Surmont from the proceeds of new long-term debt issuances. We ended the year with cash and cash equivalents and restricted cash of $5.9 billion and short-term investments of $1.0 billion, maintaining balance sheet strength.
• Peer leading distributions. We believe in delivering value to our shareholders via our three-tiered return of capital framework, which consists of a growing, sustainable ordinary dividend, share repurchases and our VROC. This framework is how we plan to return greater than 30 percent of our net cash provided by operating activities to shareholders. In 2023, we returned $5.6 billion to shareholders through our ordinary dividend and VROC and $5.4 billion through share repurchases. Our combined dividends and share repurchases of $11 billion represented over 50 percent of our net cash provided by operating activities. In February 2024, we announced our 2024 planned return of capital to shareholders of $9 billion through our three-tier return of capital framework. See “Item 1A—Risk Factors Our ability to execute our capital return program is subject to certain considerations.”
• Disciplined investments. Our goal is to achieve strong free cash flow by exercising capital discipline, controlling our costs, and safely and reliably delivering production. We expect to make capital investments sufficient to at least sustain production throughout the price cycles. Free cash flow is defined as cash from operations net of capital expenditures and investments and provides funds that are available to return to shareholders, strengthen the balance sheet or reinvest back into the business for future cash flow expansion.
◦ Exercise capital discipline. We participate in a commodity price-driven and capital-intensive industry, with varying lead times from when an investment decision is made to when an asset is operational and generates cash flow. As a result, we must invest significant capital to develop newly discovered fields, maintain existing fields and construct pipelines and LNG facilities. We allocate capital across a geographically diverse, low cost of supply resource base, which combined with legacy assets results in low overall production decline. Cost of supply is the WTI equivalent price that generates a 10 percent after-tax return on a point-forward and fully burdened basis. Fully burdened basis includes capital infrastructure, foreign currency exchange rates, cost of carbon, price-related inflation and G&A. In setting our capital plans, we exercise a rigorous approach that evaluates projects using these cost of supply criteria, which we believe will lead to value maximization and cash flow expansion using an optimized investment pace, not production growth for growth’s sake. Our cash allocation priorities call for the investment of sufficient capital to sustain production and provide returns of capital to shareholders.
◦ Control our costs. Controlling our costs, without compromising safety or environmental stewardship, is a high priority. Using various methodologies, we monitor costs monthly, on an absolute-dollar basis and a per-unit basis and report to management. Managing costs is critical to maintaining a competitive position in our industry, particularly in a low commodity price environment, and positively impacts our ability to deliver strong cash from operations.
◦ Optimize our portfolio. We continue to evaluate our assets to determine whether they compete for capital within our portfolio and optimize as necessary, directing capital towards the most competitive investments and disposing of assets that do not compete.
In 2023, we completed the acquisition of the remaining 50 percent working interest in Surmont and completed our acquisitions of equity interests in both the PALNG and NFS3 LNG projects and signed both LNG offtake and regasification agreements. See Note 3 .
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36Management’s Discussion and Analysis
Table of Contents◦ Add to our proved reserve base. We primarily add to our proved reserve base in three ways:
▪ 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.
See "Item 1A—Risk Factors - Unless we successfully develop resources, the scope of our business will d ecline, resulting in an adverse impact to our busine ss."
• Environmental, Social and Governance performance. We seek to fulfill our mission of delivering energy to the world through an integrated management system that assesses sustainability-related business risks and opportunities as part of our decision-making process. Recognizing the importance of ESG performance to our stakeholders and company success, we have a governance structure that extends from the board of directors through to executive leadership and business unit managers.
In October 2020, we became the first U.S.-based oil and natural gas company to adopt a Paris-aligned climate risk framework that includes an ambition to achieve net-zero Scope 1 and 2 emissions on a gross operated and net equity basis by 2050. We believe that this framework, combined with our success in meeting the business objectives set by our Triple Mandate, represents the most effective way for us to sustainably contribute to society’s transition to a low-carbon economy. In 2023, we announced an acceleration of our operational GHG emissions intensity reduction target through 2030. In December, we achieved the Gold Standard Pathway in the OGMP 2.0 Initiative.
We believe that natural gas and oil will remain essential to the energy mix throughout the energy transition, and we also recognize the need for continuous reduction in the greenhouse gas intensity of production operations. The energy transition will likely be complex, evolving over multiple decades with many possible pathways and uncertainties. By following our Triple Mandate, we intend to meet this challenge in an economically viable, accountable and actionable way that creates long-term value for our stakeholders. For more information on our commitment to responsible and reliable ESG performance through the energy transition, see "Contingencies—Company Response to Climate-Related Risks" section of Management's Discussion and Analysis of Financial Condition and Results of Operation.
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ConocoPhillips 2023 10-KManagement’s Discussion and Analysis
Table of Contents
Commodity PricesOur earnings and operating cash flows generally correlate with crude oil and natural gas commodity prices. Commodity price levels are subject to factors external to the company and over which we have no control, including but not limited to global economic health, supply or demand disruptions or fears thereof caused by civil unrest, global pandemics, military conflicts, actions taken by OPEC Plus and other major oil producing countries, environmental laws, tax regulations, governmental policies and weather-related disruptions. The following graph depicts the average benchmark prices for WTI crude oil, Brent crude oil and U.S. Henry Hub natural gas since 2021:
Brent crude oil prices averaged $82.62 per barrel in 2023, a decrease of 18 percent compared with $101.19 per barrel in 2022. Similarly, average WTI crude oil prices decreased 18 percent from $94.23 per barrel in 2022 to $77.62 per barrel in 2023. Prices were lower through 2023 as rising Non-OPEC supplies and Russia's ability to redirect crude oil to destinations outside the EU more than offset OPEC Plus crude oil supply curbs.
Henry Hub natural gas prices decreased 59 percent from an average of $6.65 per MMBTU in 2022 to $2.74 per MMBTU in 2023. Natural gas prices decreased due to mild winter weather and U.S. domestic supply growth outpacing demand growth.
Our realized bitumen price decreased 24 percent from an average of $55.56 per barrel in 2022 to $42.15 per barrel in 2023. The decrease was largely driven by weakness in WTI, reflective of global markets adjusting to new trade dynamics and global crude oil demand concerns. We continue to optimize bitumen price realizations through optimizing diluent recovery unit operation, blending and transportation strategies.
Our worldwide annual average realized price decreased 27 percent from $79.82 per BOE in 2022 to $58.39 per BOE in 2023 primarily due to lower commodity prices.
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38Management’s Discussion and Analysis
Table of ContentsOutlookProduction and Capital
2024 capital expenditure guidance is $11.0 to $11.5 billion.
2024 production guidance is 1.91 to 1.95 MMBOED. First-quarter 2024 production is expected to be 1.88 to 1.92 MMBOED.Operating SegmentsWe manage our operations through six operating segments, which are primarily defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International.
Corporate and Other represents income and costs not directly associated with an operating segment, such as most interest income and expense; impacts from certain debt transactions; corporate overhead and certain technology activities, including licensing revenues; and unrealized holding gains or losses on equity securities. All cash and cash equivalents and short-term investments are included in Corporate and Other.Our key performance indicators, shown in the statistical tables provided at the beginning of the operating segment sections that follow, reflect results from our operations, including commodity prices and production.39
ConocoPhillips 2023 10-KResults of Operations Table of Contents
Results of OperationsThis section of the Form 10-K discusses year-to-year comparisons between 2023 and 2022. For discussion of year-to-year comparisons between 2022 and 2021, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our 2022 10-K.Consolidated ResultsA summary of the company’s net income (loss) by business segment follows:
Millions of Dollars
Years Ended December 31 2023 2022 2021
Alaska $ 1,778 2,352 1,386
Lower 48 6,461 11,015 4,932
Canada 402 714 458
Europe, Middle East and North Africa 1,189 2,244 1,167
Asia Pacific 1,961 2,736 453
Other International (13) (51) (107)
Corporate and Other (821) (330) (210)
Net income (loss) $ 10,957 18,680 8,079
Net Income (loss) decreased $7,723 million in 2023. Earnings were negatively impacted by:
• Lower realized commodity prices.
• Absence of a $462 million gain on disposition related to the divestiture of our Indonesia assets in the first quarter of 2022, contingent payments associated with a previous disposition in our Canada segment and lower contingent payments associated with a previous disposition in our Lower 48 segment. See Note 3 .
• Higher DD&A expenses primarily due to higher rates from reserve revisions resulting from higher costs as well as higher overall production volumes.
• Higher production and operating expenses due to increased well work activities and higher volumes, primarily in the Lower 48 segment.
• Absence of a $515 million tax benefit recognized in 2022 related to the closing of an IRS audit. See Note 17 .
• Lower equity in earnings of affiliates, primarily due to lower LNG sales prices.
• Absence of a gain of $251 million after-tax from the sale of our Cenovus Energy (CVE) common shares in 2022. See Note 5 .
• Foreign currency transaction losses of $89 million arising from forward contracts in support of our Surmont acquisition and lower foreign currency remeasurement gains resulting from the USD strengthening against the NOK. See Note 3 .
Earnings were positively impacted by:
• Higher sales volumes.
• Lower taxes other than income taxes primarily driven by lower commodity prices, partially offset by higher production volumes.
• Recognized foreign tax benefits. See Note 17 .
• Commercial performance and timing.
• Higher interest income and lower interest expense due to higher capitalized interest for longer term major projects.
• Lower exploration expenses primarily related to the absence of an impairment of certain aged, suspended wells in our Canada segment and lower dry hole expenses across our portfolio. See Note 6 .
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40
Results of Operations Table of Contents
Income Statement Analysis
Unless otherwise indicated, all results in Income Statement Analysis are before-tax.
Sales and other operating revenues decreased $22,353 million in 2023, primarily due to lower realized commodity prices partially offset by higher sales volumes.
Equity in earnings of affiliates decreased $361 million in 2023, primarily due to lower earnings driven by lower LNG and crude prices. See Note 3 .
Gain (loss) on dispositions decreased $849 million in 2023, primarily due to the absence of a gain of $534 million from the divestiture of our Indonesia assets, the absence of contingent payments associated with a previous disposition in our Canada segment and lower contingent payments associated with a previous disposition in our Lower 48 segment. See Note 3 .
Other Income decreased $19 million in 2023 primarily due to the absence of a gain of $251 million after-tax from the sale of our Cenovus Energy (CVE) common shares in 2022, largely offset by higher interest income.
Purchased commodities decreased $11,996 million in 2023, primarily due to lower prices across all commodities.
Production and operating expenses increased $687 million in 2023, due to increased well work activities and higher production volumes, primarily in the Lower 48 segment.
Exploration expenses decreased $166 million in 2023, primarily due to the absence of an impairment of certain aged, suspended wells in our Canada segment as well as lower dry hole expenses. See Note 6 .
DD&A increased $766 million in 2023 primarily due to higher rates from reserve revisions resulting from higher operating costs as well as higher overall production volumes primarily due to development in our Lower 48 segment.
Taxes other than income taxes decreased $1,290 million in 2023, caused primarily by lower commodity prices, partially offset by higher production volumes.
Foreign currency transaction (gain) loss for the year was impaired by $192 million, primarily as a result of losses of $112 million associated with forward contracts in support of our Surmont acquisition and lower foreign currency remeasurement gains resulting from the USD strengthening against the NOK. See Note 3 .
See Note 17 —Income Taxes for information regarding our income tax provision and effective tax rate.
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ConocoPhillips 2023 10-K
Results of Operations Table of ContentsSummary Operating Statistics2023 2022 2021Average Net Production
Crude oil (MBD)Consolidated Operations 923 885 816
Equity affiliates 13 13 13
Total crude oil 936 898 829Natural gas liquids (MBD)Consolidated Operations 279 244 134Equity affiliates 8 8 8Total natural gas liquids 287 252 142
Bitumen (MBD) 81 66 69Natural gas (MMCFD)Consolidated Operations 1,916 1,939 2,109
Equity affiliates 1,219 1,191 1,053
Total natural gas 3,135 3,130 3,162Total Production (MBOED)1,826 1,738 1,567Dollars Per Unit
Average Sales PricesCrude oil (per bbl)
Consolidated Operations $ 78.97 97.23 67.61
Equity affiliates 78.45 97.31 69.45
Total crude oil 78.96 97.23 67.64
Natural gas liquids (per bbl)
Consolidated Operations 22.12 35.67 31.04
Equity affiliates 47.09 61.22 54.16
Total natural gas liquids 22.82 36.50 32.45
Bitumen (per bbl) 42.15 55.56 37.52
Natural gas (per mcf)
Consolidated Operations 3.89 10.56 6.00
Equity affiliates 8.46 10.67 5.31
Total natural gas 5.69 10.60 5.77Millions of Dollars
Worldwide Exploration ExpensesGeneral and administrative; geological and geophysical, lease rental, and other $ 236 224 300
Leasehold impairment 53 89 10
Dry holes 109 251 34
Total Exploration Expenses $ 398 564 344
ConocoPhillips 2023 10-K
42Results of Operations Table of ContentsWe 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.
The increase in production during 2023 was partly offset by normal field decline.
After adjusting for closed acquisitions and dispositions, production increased by 73 MBOED or 4 percent.
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ConocoPhillips 2023 10-KResults of Operations Table of Contents
Segment Results
Unless otherwise indicated, discussion of Segment Results is after-tax.Alaska2023 2022 2021
Net Income (Loss) ($MM)
$ 1,778 2,352 1,386Average Net ProductionCrude oil (MBD) 173 177 178
Natural gas liquids (MBD) 16 17 16
Natural gas (MMCFD) 38 34 16Total Production (MBOED)195 200 197Average Sales PricesCrude 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.Net Income (Loss)Alaska reported earnings of $1,778 million in 2023, compared with earnings of $2,352 million in 2022. Earnings were negatively impacted by:
• Lower realized crude oil prices.
• Higher production and operating expenses due to higher well work and transportation related costs.
• Higher DD&A expenses due to higher rates primarily as a result of downward reserve revisions.
Earnings were positively impacted by lower taxes other than income taxes associated with lower realized crude oil prices.ProductionAverage production decreased 5 MBOED in 2023 compared with 2022, primarily due to normal field decline.
The production decrease was partly offset by new wells online at our Western North Slope and Greater Kuparuk Area assets.
Exploration Activity
In the first quarter of 2023, we drilled the Bear-1 exploration well which was determined to be a dry hole, increasing exploration expenses by approximately $31 million before-tax. The well, located south of the Kuparuk River Unit and east of the Colville River on state lands, is in an area that we are continuing to evaluate. See Note 6 .
Willow Update
In March 2023, the Department of Interior published its ROD approving our Willow project in Alaska, which adopted a plan consisting of three core pads. In December, following a Ninth Circuit Court of Appeals denial of a request for an injunction, we reached FID on the Willow project and began winter construction.
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44Results of Operations Table of Contents
Lower 482023 2022 2021
Net Income (Loss) ($MM)
$ 6,461 11,015 4,932Average Net ProductionCrude oil (MBD) 569 534 447
Natural gas liquids (MBD)* 256 221 110
Natural gas (MMCFD)* 1,457 1,402 1,340Total Production (MBOED)1,067 989 780Average Sales PricesCrude oil ($ per bbl) $ 76.19 94.46 66.12
Natural gas liquids ($ per bbl) 21.73 35.36 30.63
Natural gas ($ per mcf) 2.12 5.92 4.38
*Includes conversion of previously acquired Concho two-stream contracts to three-stream initiated in the fourth quarter of 2021.
The Lower 48 segment consists of operations located in the contiguous U.S. and the Gulf of Mexico and commercial operations. During 2023, the Lower 48 contributed 64 percent of our consolidated liquids production and 76 percent of our consolidated natural gas production.Net Income (Loss)Lower 48 reported earnings of $6,461 million in 2023, compared with earnings of $11,015 million in 2022. Earnings were negatively impacted by:
• Lower realized commodity prices.
• Higher DD&A expenses primarily due to higher rates from reserve revisions resulting from higher operating costs as well as higher production volumes.
• Higher production and operating expenses primarily due to higher production volumes and increased well work activity.
Earnings were positively impacted by:
• Higher sales volumes.
• Improved commercial performance and timing.
• Lower taxes other than income taxes driven by lower realized prices, partially offset by higher production volumes.ProductionTotal average production increased 78 MBOED in 2023 compared with 2022, primarily due to new wells online from our development programs in Delaware Basin, Midland Basin, Eagle Ford and Bakken.
These production increases were partly offset by normal field decline.
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ConocoPhillips 2023 10-KResults of Operations Table of Contents
Canada2023 2022 2021Net Income (Loss) ($MM)$ 402 714 458Average Net ProductionCrude oil (MBD) 9 6 8
Natural gas liquids (MBD) 3 3 4
Bitumen (MBD) 81 66 69
Natural gas (MMCFD) 65 61 80Total Production (MBOED)104 85 94Average Sales PricesCrude oil ($ per bbl) $ 66.19 79.94 56.38
Natural gas liquids ($ per bbl) 26.13 37.70 31.18
Bitumen ($ per bbl) 42.15 55.56 37.52
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.Net Income (Loss)Canada operations reported earnings of $402 million in 2023 compared with earnings of $714 million in 2022. Earnings were negatively impacted by:
• Lower realized commodity prices.
• Absence of contingent payments received associated with the prior sale of certain assets to CVE. The term of CVE contingent payments ended in the second quarter of 2022.
Earnings were positively impacted by:
• Higher sales volumes primarily related to our Surmont acquisition which closed in October 2023. See Note 3 .
• Absence of prior year exploration expenses related to the impairment of certain aged, suspended wells. See Note 6 .
• A $92 million tax benefit recognized upon the closing of a Canada Revenue Agency audit. See Note 17 .ProductionTotal average production increased 19 MBOED in 2023 compared with 2022. The production increase was primarily due to:
• Higher volumes due to our Surmont acquisition in the fourth quarter of 2023. See Note 3 .
• New wells online from our development program in the Montney.
These production increases were partly offset by normal field decline.
Surmont Acquisition
On October 4, 2023, we completed the acquisition of the remaining 50 percent working interest in Surmont. Total consideration was approximately $2.7 billion in cash after customary adjustments, as well as future contingent payments of up to approximately $0.4 billion CAD (approximately $0.3 billion). Production from the acquired interest averaged approximately 62 MBD of bitumen in the fourth quarter of 2023. See Note 3 .
ConocoPhillips 2023 10-K
46Results of Operations Table of Contents
Europe, Middle East and North Africa2023 2022 2021
Net Income (Loss) ($MM)
$ 1,189 2,244 1,167Consolidated Operations
Average Net ProductionCrude oil (MBD) 112 107 118
Natural gas liquids (MBD) 4 3 4
Natural gas (MMCFD) 308 328 313Total Production (MBOED)168 165 175Average Sales PricesCrude 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.Net Income (Loss)The Europe, Middle East and North Africa segment reported earnings of $1,189 million in 2023 compared with earnings of $2,244 million in 2022. Earnings were negatively impacted by:
• Lower realized commodity prices.
• Lower equity in earnings of affiliates primarily due to lower LNG sale prices.
• Lower commercial performance and timing.
• Lower sales volumes in Norway.
• Lower foreign exchange gains resulting from the USD strengthening against the NOK.Consolidated ProductionAverage consolidated production increased 3 MBOED in 2023, compared with 2022. The consolidated production increase was primarily due to:
• Higher production in 2023 from additional interest acquired in Libya's Waha Concession in the fourth quarter of 2022.
The production increase was partly offset by:
• Normal field decline in Norway.
• Higher downtime on partner-operated assets in Norway.
Qatar Interest
During 2022, we were awarded a 25 percent interest in NFS3, a new joint venture with QatarEnergy to participate in the NFS LNG project. Formation of NFS3 closed in June 2023. See Note 3 and Note 4 .
Exploration Activity
During 2023, we recorded $37 million before-tax as dry hole expense for the Norwegian Warka suspended discovery well on license PL1009 that was drilled in 2020.
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ConocoPhillips 2023 10-KResults of Operations Table of Contents
Asia Pacific2023 2022 2021
Net Income (Loss) ($MM)
$ 1,961 2,736 453Consolidated Operations
Average Net ProductionCrude oil (MBD) 60 61 65
Natural gas (MMCFD) 48 114 360Total Production (MBOED)68 80 125Average Sales PricesCrude oil ($ per bbl) $ 84.79 105.52 70.36
Natural gas ($ per mcf) 3.95 5.84 6.56
The Asia Pacific segment consists of operations in China, Malaysia, and Australia, and commercial operations in China, Singapore and Japan. During 2023, Asia Pacific contributed five percent of our consolidated liquids production and three percent of our consolidated natural gas production.Net Income (Loss)Asia Pacific reported earnings of $1,961 million in 2023, compared with $2,736 million in 2022. Earnings were negatively impacted by:
• Absence of an after-tax gain of $534 million associated with the divestiture of our Indonesia assets. See Note 3 .
• Lower realized commodity prices.
• Lower equity in earnings of affiliates resulting from lower LNG sales prices.
• Lower sales volumes.
Earnings were positively impacted by:
• Recognized tax benefits from the reversal of a tax reserve and deepwater tax incentives. See Note 17 .
• Lower taxes other than income taxes primarily due to lower realized commodity prices.Consolidated ProductionAverage consolidated production decreased 12 MBOED in 2023, compared with 2022. The decrease was primarily due to:
• Normal field decline.
• The divestiture of our Indonesia assets in the first quarter of 2022.
These production decreases were partly offset by development activity at Bohai Bay in China and new wells online in Malaysia.
Planned Acquisition Update
In March 2023, we announced that, subject to the closing of EIG's transaction with Origin Energy, we planned to take over operatorship of the upstream assets and purchase up to an additional 2.49 percent shareholding interest in APLNG. In December 2023, Origin Energy shareholders did not approve the transaction.
ConocoPhillips 2023 10-K
48Results of Operations Table of ContentsOther International
2023 2022 2021
Net Income (Loss) ($MM)
$ (13) (51) (107)
The Other International segment consists of activities associated with prior operations in other countries.
Earnings from our Other International operations improved $38 million in 2023, compared with 2022, primarily due to the absence of higher taxes related to legal settlements in 2022.Corporate and Other
Millions of Dollars2023 2022 2021
Net Income (Loss)
Net interest expense $ (360) (600) (801)
Corporate G&A expenses (357) (244) (317)
Technology (34) 32 25
Other income (expense) (70) 482 883
$ (821) (330) (210)
Net interest consists of interest and financing expense, net of interest income and capitalized interest. Net interest expense decreased $240 million in 2023, compared with 2022, primarily due to higher interest income in addition to lower interest expenses due to higher capitalized interest for longer term major projects. See Note 9 .
Corporate G&A expenses include compensation programs and staff costs. These expenses increased by $113 million in 2023 compared with 2022, primarily due to mark-to-market adjustments associated with certain compensation programs. See Note 16 .
Technology includes our investments in low-carbon technologies as well as other new technologies or businesses and licensing revenues. Other new technologies or businesses and LNG licensing activities are focused on both conventional and tight oil reservoirs, shale gas, oil sands, enhanced oil recovery as well as LNG.
Other income (expense) or "Other" includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, other costs not directly associated with an operating segment, gains or losses on early retirement of debt, holding gains or losses on equity securities and pension settlement expense. Earnings in “Other” decreased by $552 million in 2023 compared with 2022. This was primarily due to:
• Absence of a $474 million federal tax benefit. See Note 17 .
• Absence of a $251 million gain associated with our CVE common shares, which were fully divested in the first quarter of 2022. See Note 5 .
• Loss of $89 million associated with forward foreign exchange contracts to buy CAD, in support of our acquisition of additional working interest in Surmont. See Note 3 .
• Absence of a gain of $62 million associated with 2022 debt restructuring transactions. See Note 9 .
The decreases were offset by:
• Absence of a $101 million tax impact associated with the disposition of our Indonesia assets in the first quarter of 2022. See Note 3 .
• Absence of an $81 million impact from certain legal accruals.
Port Arthur LNG Acquisition
In March, we acquired a 30 percent direct equity holding in PALNG, a joint venture for the development of Phase 1 of the Port Arthur LNG project. In addition, we entered into a 20-year agreement to purchase 5 MTPA of LNG offtake at the start of Phase 1 and a natural gas supply management agreement, whereby we will manage the feedgas supply requirements for Phase 1. Currently we anticipate start up in 2027. See Note 3 .
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ConocoPhillips 2023 10-KCapital Resources and Liquidity
Table of Contents
Capital Resources and Liquidity
Financial Indicators
Millions of Dollars Except as Indicated2023 2022 2021
Net cash provided by operating activities $ 19,965 28,314 16,996
Cash and cash equivalents 5,635 6,458 5,028
Short-term investments 971 2,785 446
Short-term debt 1,074 417 1,200
Total debt 18,937 16,643 19,934
Total equity 49,279 48,003 45,406
Percent of total debt to capital* 28 % 26 31
Percent of floating-rate debt to total debt 2 % 2 4*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.Significant Changes in Capital
Operating ActivitiesCash 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.
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50Capital Resources and Liquidity
Table of ContentsThe 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 ActivitiesIn 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. S ee 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 .
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ConocoPhillips 2023 10-KCapital Resources and Liquidity
Table of Contents
Financing ActivitiesOur 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.
Shelf Registration
We have a universal shelf registration statement on file with the SEC under which we have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
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52Capital Resources and Liquidity
Table of ContentsCapital RequirementsFor 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. S e e 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.
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ConocoPhillips 2023 10-KCapital Resources and Liquidity
Table of Contents
Capital Expenditures and Investments
Millions of Dollars2023 2022 2021
Alaska $ 1,705 1,091 982
Lower 48 6,487 5,630 3,129
Canada 456 530 203
Europe, Middle East and North Africa 1,111 998 534
Asia Pacific 354 1,880 390
Other International — — 33
Corporate and Other 1,135 30 53
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:
• Appraisal and development activities in Alaska related to the Western North Slope and development activities in the Greater Kuparuk Area.
• Development and exploration activities in the Lower 48, primarily in the Delaware Basin, Eagle Ford, Midland Basin and Bakken.
• Appraisal and development activities at Montney as well as development and optimization of Surmont in Canada.
• Development activities across assets in Norway.
• Continued development activities in Malaysia and China.
• Capital primarily associated with our investments in PALNG, NFE4 and NFS3.
2024 Capital Budget
In February 2024, we announced our 2024 operating plan capital is expected to be between $11.0 to $11.5 billion. The plan includes funding for ongoing development drilling programs, major projects, exploration and appraisal activities and base maintenance.
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54Capital Resources and Liquidity
Table of Contents
Guarantor Summarized Financial Information
We have various cross guarantees among ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. Burlington Resources LLC is 100 percent owned by ConocoPhillips Company. ConocoPhillips and/or ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of Burlington Resources LLC with respect to its publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several.
The following tables present summarized financial information for the Obligor Group, as defined below:
• The Obligor Group will reflect guarantors and issuers of guaranteed securities consisting of ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC.
• Consolidating adjustments for elimination of investments in and transactions between the collective guarantors and issuers of guaranteed securities are reflected in the balances of the summarized financial information.
• Non-Obligated Subsidiaries are excluded from this presentation.
Transactions and balances reflecting activity between the Obligors and Non-Obligated Subsidiaries are presented separately below:
Summarized Income Statement Data
Millions of Dollars2023
Revenues and Other Income $ 37,992
Income (loss) before income taxes* 10,737
Net Income (Loss) 10,957
* Includes approximately $7.9 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.Summarized Balance Sheet Data
Millions of DollarsDecember 31, 2023
Current assets $ 8,008
Amounts due from Non-Obligated Subsidiaries, current 1,565
Noncurrent assets 91,155
Amounts due from Non-Obligated Subsidiaries, noncurrent 8,936
Current liabilities 7,337
Amounts due to Non-Obligated Subsidiaries, current 3,990
Noncurrent liabilities 49,105
Amounts due to Non-Obligated Subsidiaries, noncurrent 31,241
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ConocoPhillips 2023 10-K
Capital Resources and Liquidity
Table of ContentsContingenciesWe are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See “Critical Accounting Estimates” and Note 11 for information on contingencies.Legal and Tax MattersWe are subject to various lawsuits and claims, including but not limited to matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, climate change, personal injury, and property damage. Our primary exposures for such matters relate to alleged royalty and tax underpayments on certain federal, state and privately owned properties, claims of alleged environmental contamination and damages from historic operations, and climate change. We will continue to defend ourselves vigorously in these matters.
Our legal organization applies its knowledge, experience, and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required. See Note 17 .EnvironmentalWe are subject to the same numerous international, federal, state, and local environmental laws and regulations as other companies in our industry. The most significant of these environmental laws and regulations include, among others, the:• U.S. Federal Clean Air Act, which governs air emissions;
• U.S. Federal Clean Water Act, which governs discharges to water bodies;• European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH);• U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund), which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;
• U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage, and disposal of solid waste;• U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the U.S.;
• U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories with local emergency planning committees and response departments;• U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells;
• U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages; and• European Union Trading Directive resulting in European Emissions Trading Scheme.These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also establish standards and impose obligations for the remediation of releases of hazardous substances and hazardous wastes. In most cases, these regulations require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.
Many states and foreign countries where we operate also have or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.ConocoPhillips 2023 10-K
56Capital Resources and Liquidity
Table of ContentsThe ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards and water quality standards, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the U.S. and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the U.S. and Canada.
An example is the use of hydraulic fracturing, an essential completion technique that facilitates production of oil and natural gas otherwise trapped in lower permeability rock formations. A range of local, state, federal, or national laws and regulations currently govern hydraulic fracturing operations, with hydraulic fracturing currently prohibited in some jurisdictions. Although hydraulic fracturing has been conducted for many decades, potential new laws, regulations and permitting requirements from various state environmental agencies, and others could result in increased costs, operating restrictions, operational delays and/or limit the ability to develop oil and natural gas resources. Governmental restrictions on hydraulic fracturing could impact the overall profitability or viability of certain of our oil and natural gas investments. We have adopted operating principles that incorporate established industry standards designed to meet or exceed government requirements. Our practices continually evolve as technology improves and regulations change.
We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.
We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain waste attributable to our past operations. As of December 31, 2023, there were 15 sites around the U.S. in which we were identified as a potentially responsible party under CERCLA and comparable state laws.For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.Expensed environmental costs were $791 million in 2023 and are expected to be approximately $937 million and $946 million in 2024 and 2025, respectively. Capitalized environmental costs were $393 million in 2023 and are expected to be about $438 million and $450 million in 2024 and 2025, respectively.Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).
Many of these liabilities result from CERCLA, RCRA, and similar state or international laws that require us to undertake certain investigative and remedial activities at sites where we conduct or once conducted operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we identified that may require environmental remediation but which are not currently the subject of CERCLA, RCRA, or other agency enforcement activities. The laws that require or address environmental remediation may apply retroactively and regardless of fault, the legality of the original activities or the current ownership or control of sites. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA.57
ConocoPhillips 2023 10-K
Capital Resources and Liquidity
Table of ContentsRemediation 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 ChangeContinuing 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 21 st 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.
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Table of Contents• Governments and financial regulators are developing new reporting rules requiring increased disclosure around a range of sustainability topics. In March 2022 the U.S. SEC proposed rule changes that would require registrants to include certain climate-related disclosures in their registration statements and periodic reports; In January 2023 the EU finalized the Corporate Sustainability Reporting Directive that will require more detailed sustainability reporting; in June 2023 the International Sustainability Standards Board issued inaugural sustainability reporting standards; and in October 2023 in California multiple bills were signed into law requiring climate-related disclosures for companies that conduct business in the state. The patchwork of reporting standards that is developing may require significant increases in disclosures, which may be costly to implement.
• The U.S. Council on Environmental Quality is preparing to finalize revised regulations under the National Environmental Policy Act (NEPA Phase 2), along with corresponding Guidance on the Consideration of GHG Emissions and Climate Change, in early 2024. The new regulatory framework’s emphasis on avoiding and minimizing climate impacts increases uncertainty associated with the federal environmental review and permitting process for oil and gas activities.Compliance with changes in laws and regulations that create a GHG tax, emission trading scheme or GHG reduction policies could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also increase demand for less carbon intensive energy sources, including natural gas. The ultimate impact on our financial performance, either positive or negative, will depend on a number of factors, including but not limited to:
• Whether and to what extent legislation or regulation is enacted;
• The timing of the introduction of such legislation or regulation;
• The nature of the legislation (such as a cap and trade system or a tax on emissions) or regulation;
• The price placed on GHG emissions (either by the market or through a tax);• The GHG reductions required;• The price and availability of offsets;
• The amount and allocation of allowances;
• 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); and
• 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.Company Response to Climate-Related RisksIn 2020, we adopted a Paris-aligned climate-related risk framework with an ambition to reduce our operational (Scope 1 and 2) emissions to net-zero by 2050. The objective of our Climate Risk Strategy is to manage climate-related risk, optimize opportunities and equip the company to respond to changes in key uncertainties, including government policies around the world, technologies for emissions reduction, alternative energy technologies and changes in consumer trends. The strategy sets out our choices around portfolio composition, emissions reductions, targets and incentives, emissions-related technology development, and our climate-related policy and finance sector engagement.
An important component of our Climate Risk Strategy is the Plan for the Net-Zero Energy Transition (the 'Plan'). The Plan outlines how we intend to play a valued role in the energy transition by executing on our Triple Mandate to: reliably and responsibly meet energy transition pathway demand, deliver competitive returns on and of capital and achieve our net-zero operational emissions ambition. The Plan also outlines how we intend to apply our strategic capabilities and resources to meet the challenges posed by climate change in an economically viable, accountable and actionable way that balances the interests of our stakeholders.
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Table of ContentsKey elements of the Plan include:
• Maintaining strategic flexibility
◦ Building a resilient asset portfolio with a focus on low cost of supply and low GHG intensity to meet transition pathway energy demand.◦ Committing to capital discipline through use of a fully burdened cost of supply, including cost of carbon, as the basis for capital allocation.• Reducing Scope 1 and 2 emissions
◦ Setting targets for emissions over which we have ownership and control, with an ambition to become a net-zero company for Scope 1 and 2 emissions by 2050.
• Addressing Scope 3 emissions
◦ Advocating for a well-designed, economy-wide price on carbon and engaging in development of other policy and legislation to address end-use emissions.
◦ Working with our suppliers for alignment on GHG emissions reductions.
• Contributing to an orderly transition
◦ Building an attractive LNG portfolio.
◦ Evaluating potential investments in emerging energy transition and low-carbon technologies.
Our Plan does not include a Scope 3 (end-use) emissions target. We recognize that end-use emissions must be reduced to meet global climate objectives. However, it is our view that supply-side constraints through Scope 3 targets for North American and European upstream oil and gas producers would be counterproductive to climate goals. In the absence of policy measures that address global demand and with the shape and pace of technology and policy yet to be determined, setting and meeting Scope 3 targets would require a shift of production to other global operators that have established less ambitious targets or no targets to reduce their own operational emissions or do not have any other ambitions or plans to manage climate-related risks, potentially eroding energy security and affordability as well as undercutting global climate change objectives. This is why we have consistently taken a prominent role in advocating for a well-designed, economy wide price on carbon and engaged in development of other policies or legislation that could address end-use emissions from high-carbon intensity energy use. We have also expanded policy advocacy beyond carbon pricing to include regulatory action, such as support for the direct regulation of methane.
In support of addressing our Scope 1 and 2 emissions, in 2023, we made progress in several key areas.
• Continued to refine our Paris-aligned climate risk strategy.
• Accelerated our GHG intensity reduction target to 50-60 percent by 2030 from a 2016 baseline for both gross operated and net equity emissions.
• Achieved the Gold Standard Pathway in the OGMP 2.0 Initiative.
• Implemented our new near-zero 2030 methane emissions intensity target of approximately 1.5 kilogram carbon dioxide equivalent per BOE or of 0.15 percent of gas produced.
Our emissions reduction efforts and net-zero ambition are supported by our multi-disciplinary Low-Carbon Technologies organization. See Item 1A . Risk Factors — O ur ability to successfully execute on our energy transition plans is subject to a number of risks and uncertainties and may be costly to achieve.New Accounting StandardsFor discussion of new accounting standards, see Note 25 .
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Critical Accounting EstimatesThe 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.Oil and Gas Accounting
Accounting for oil and gas activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of G&G seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been recognized.
Property Acquisition Costs
For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For insignificant individual leasehold acquisition costs, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves, including estimates of future expirations, and pools that leasehold information with others in similar geographic areas. For prospects in areas with limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense. This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively.At year-end 2023, we held $4.4 billion of net capitalized unproved property costs which consisted primarily of individually significant and pooled leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells currently being drilled, suspended exploratory wells and capitalized interest. Of this amount, approximately $3.0 billion is concentrated in the Delaware and Midland Basins, where we have an ongoing significant and active development program. Outside of the Delaware and Midland Basins, the remaining $1.4 billion is primarily concentrated in Canada. Management periodically assesses our unproved property for impairment based on the results of exploration and drilling efforts and the outlook for commercialization.Exploratory CostsFor 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 .
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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.Business Combination—Valuation of Oil and Gas Properties
For business combinations, management applies the principles of acquisition accounting under FASB ASC Topic 805 – “Business Combinations” and allocates the purchase price to assets acquired and liabilities assumed, based on their estimated fair values as of the acquisition date. Estimating the fair values involves making various assumptions, of which the most significant assumptions relate to the fair values assigned to proved and unproved oil and gas properties. For significant business combinations, management generally utilizes a discounted cash flow approach, based on market participant assumptions, and considers engaging third party valuation experts in preparing fair value estimates.Significant inputs incorporated within the valuation include future commodity price assumptions and production profiles of reserve estimates, the pace of drilling plans, future operating and development costs, inflation rates, and discount rates using a market-based weighted average cost of capital determined at the time of the acquisition. When estimating the fair value of unproved properties, additional risk-weighting adjustments are applied to probable and possible reserves.
The assumptions and inputs incorporated within the fair value estimates are subject to considerable management judgement and are based on industry, market, and economic conditions prevalent at the time of the acquisition. Although we based these estimates on assumptions believed to be reasonable, these estimates are inherently unpredictable and uncertain and actual results could differ. See Note 3 .
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Impairments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If there is an indication the carrying amount of an asset may not be recovered, a recoverability test is performed using management’s assumptions for prices, volumes and future development plans. If the sum of the undiscounted cash flows before income-taxes is less than the carrying value of the asset group, the carrying value is written down to estimated fair value and reported as an impairment in the periods in which the determination is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for E&P assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates and prices believed to be consistent with those used by principal market participants, or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible.The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, commodity prices, operating costs and capital decisions, considering all available evidence at the date of review. Differing assumptions could affect the timing and the amount of an impairment in any period. See Note 6 and Note 7 .
Investments in nonconsolidated entities accounted for under the equity method are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred. Such evidence of a loss in value might include our inability to recover the carrying amount, the lack of sustained earnings capacity which would justify the current investment amount, or a current fair value less than the investment’s carrying amount. When such a condition is judgmentally determined to be other than temporary, an impairment charge is recognized for the difference between the investment’s carrying value and its estimated fair value. When determining whether a decline in value is other than temporary, management considers factors such as the length of time and extent of the decline, the investee’s financial condition and near-term prospects, and our ability and intention to retain our investment for a period that will be sufficient to allow for any anticipated recovery in the market value of the investment. Since quoted market prices are usually not available, the fair value is typically based on the present value of expected future cash flows using discount rates and prices believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate. Differing assumptions could affect the timing and the amount of an impairment of an investment in any period. See the “APLNG” section of Note 4 .Asset Retirement Obligations and Environmental CostsUnder various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and restore the land or seabed at the end of operations at operational sites. Our largest asset removal obligations involve plugging and abandonment of wells, removal and disposal of offshore oil and gas platforms around the world, as well as oil and gas production facilities and pipelines in Alaska. Fair value is estimated using a present value approach, incorporating assumptions about estimated amounts and timing of settlements and impacts of the use of technologies. Estimating future asset removal costs requires significant judgement. Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. The carrying value of our asset retirement obligation estimate is sensitive to inputs such as asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, which are all subject to change between the time of initial recognition of the liability and future settlement of our obligation.Normally, changes in asset removal obligations are reflected in the income statement as increases or decreases to DD&A over the remaining life of the assets. However, for assets at or nearing the end of their operations, as well as previously sold assets for which we retained the asset removal obligation, an increase in the asset removal obligation can result in an immediate charge to earnings, because any increase in PP&E due to the increased obligation would immediately be subject to impairment, due to the low fair value of these properties.In addition to asset removal obligations, under the above or similar contracts, permits and regulations, we have certain environmental-related projects. These are primarily related to remediation activities required by Canada and various states within the U.S. at exploration and production sites. Future environmental remediation costs are difficult to estimate because they are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. See Note 8 .
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Projected Benefit ObligationsThe actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates, and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations and company contribution requirements. Ultimately, we will be required to fund all vested benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Projected benefit obligations are particularly sensitive to the discount rate assumption. A 100 basis-point decrease in the discount rate assumption would increase projected benefit obligations by $600 million. Benefit expense is sensitive to the discount rate and return on plan assets assumptions. A 100 basis-point decrease in the discount rate assumption would increase annual benefit expense by $50 million, while a 100 basis-point decrease in the return on plan assets assumption would increase annual benefit expense by $40 million. In determining the discount rate, we use yields on high-quality fixed income investments matched to the estimated benefit cash flows of our plans. We are also exposed to the possibility that lump sum retirement benefits taken from pension plans during the year could exceed the total of service and interest components of annual pension expense and trigger accelerated recognition of a portion of unrecognized net actuarial losses and gains. These benefit payments are based on decisions by plan participants and are therefore difficult to predict. In the event there is a significant reduction in the expected years of future service of present employees or the elimination of the accrual of defined benefits for some or all of their future services for a significant number of employees, we could recognize a curtailment gain or loss. See Note 16 .ContingenciesA number of claims and lawsuits are made against the company arising in the ordinary course of business. Management exercises judgment related to accounting and disclosure of these claims which includes losses, damages, and underpayments associated with environmental remediation, tax, contracts, and other legal disputes. As we learn new facts concerning contingencies, we reassess our position both with respect to amounts recognized and disclosed considering changes to the probability of additional losses and potential exposure. However, actual losses can and do vary from estimates for a variety of reasons including legal, arbitration, or other third-party decisions; settlement discussions; evaluation of scope of damages; interpretation of regulatory or contractual terms; expected timing of future actions; and proportion of liability shared with other responsible parties. Estimated future costs related to contingencies are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes. For additional information on contingent liabilities, see the “Contingencies” section within “Capital Resources and Liquidity” and Note 11 .Income TaxesWe are subject to income taxation in numerous jurisdictions worldwide. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. In assessing the need for adjustments to existing valuation allowances, we consider all available positive and negative evidence. Positive evidence includes reversals of temporary differences, forecasts of future taxable income, assessment of future business assumptions and applicable tax planning strategies that are prudent and feasible. Negative evidence includes losses in recent years as well as the forecasts of future net income (loss) in the realizable period. In making our assessment regarding valuation allowances, we weight the evidence based on objectivity. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions and the assessment of the effects of foreign taxes on our U.S. federal income taxes (particularly as related to prevailing oil and gas prices). See Note 17 .
We regularly assess and, if required, establish accruals for uncertain tax positions that could result from assessments of additional tax by taxing jurisdictions in countries where we operate. We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. These accruals for uncertain tax positions are subject to a significant amount of judgment and are reviewed and adjusted on a periodic basis in light of changing facts and circumstances considering the progress of ongoing tax audits, court proceedings, changes in applicable tax laws, including tax case rulings and legislative guidance, or expiration of the applicable statute of limitations. See Note 17.
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Cautionary Statement for the Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995This 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.• Reductions in reserves replacement rates, whether as a result of the significant declines in commodity prices or otherwise.• Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.• 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 broader societal attention to and efforts to address climate change may impact our access to capital and insurance.
• Potential failures or delays in delivering on our current or future low-carbon strategy, including our inability to develop new technologies.
• The impact of public health crises, including pandemics (such as COVID-19) and epidemics, and any related company or government policies or actions.
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• 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.
• Volatility in the commodity futures markets.
• Changes in tax and other laws, regulations (including alternative energy mandates) or royalty rules applicable to our business.
• Competition and consolidation in the oil and gas E&P industry, including competition for personnel and equipment.
• Any limitations on our access to capital or increase in our cost of capital, including as a result of illiquidity or uncertainty in domestic or international financial markets or investment sentiment, including as a result of increased societal attention to and efforts to address climate change.
• Our inability to execute, or delays in the completion of, any asset dispositions or acquisitions we elect to pursue.
• Potential failure to obtain, or delays in obtaining, any necessary regulatory approvals for pending or future asset dispositions or acquisitions, or that such approvals may require modification to the terms of the transactions or the operation of our remaining business.
• Potential disruption of our operations as a result of pending or future asset dispositions or acquisitions, including the diversion of management time and attention.
• Our inability to deploy the net proceeds from any asset dispositions that are pending or that we elect to undertake in the future in the manner and timeframe we currently anticipate, if at all.
• The operation and financing of our joint ventures.• The ability of our customers and other contractual counterparties to satisfy their obligations to us, including our ability to collect payments when due from the government of Venezuela or PDVSA.• Our inability to realize anticipated cost savings and capital expenditure reductions.
• The inadequacy of storage capacity for our products, and ensuing curtailments, whether voluntary or involuntary, required to mitigate this physical constraint.
• The risk that we will be unable to retain and hire key personnel.• Uncertainty as to the long-term value of our common stock.• The factors generally described in Part I—Item 1A in this 2023 Annual Report on Form 10-K and any additional risks described in our other filings with the SEC.
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FY 2025-12-31 (later)
Item 7. Management’s Discussion and Analysis of Financial Condition and
Results of OperationsManagement’s Discussion and Analysis is the company’s analysis of its financial performance and of significant trends and uncertainties that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “ambition,” “anticipate,” “believe,” “budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 62 .The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss).
Business Environment and Executive OverviewConocoPhillips is one of the world’s leading E&P companies, based on both production and reserves, with operations and activities in 14 countries. Our diverse, low cost of supply portfolio includes resource-rich unconventional plays in North America; conventional assets in North America, Europe, Africa and Asia; global LNG developments; oil sands in Canada; and an inventory of global exploration prospects. Headquartered in Houston, Texas, at December 31, 2025, we employed approximately 9,900 people worldwide and had total assets of $122 billion.OverviewAt ConocoPhillips, we anticipate that commodity prices will continue to be cyclical and volatile, and our view is that a successful business strategy in the E&P industry must be resilient in lower price environments while also retaining upside during periods of higher prices. As such, we are unhedged, remain committed to our disciplined investment framework and continually monitor market fundamentals, including the impacts associated with geopolitical tensions and conflicts, global demand for our products, oil and gas inventory levels, governmental policies, inflation and supply chain disruptions.
Throughout 2025, the price of crude oil has been volatile due to multiple macroeconomic and geopolitical forces which slowed global oil demand growth concurrent with higher oil production from OPEC Plus and other major oil producing countries. We continue to closely monitor the macroeconomic environment, including any impacts from tariffs, and the ongoing market volatility in the energy landscape and across global markets for implications to our business, results of operations and financial condition.
As the global energy industry continues to evolve, we remain committed to creating long-term value for our stockholders. We believe ConocoPhillips plays an essential role in responsibly meeting the global demand for energy, while continuing to deliver competitive returns on and of capital and working to meet our previously established emissions-reduction targets. Our value proposition to deliver competitive returns to stockholders through price cycles is guided by our foundational principles, which consist of maintaining balance sheet strength, providing peer-leading distributions, making disciplined investments, and demonstrating responsible and reliable ESG performance.
Total company production in 2025 was 2,375 MBOED, yielding cash provided by operating activities of $19.8 billion. We invested $12.6 billion into the business in the form of capital expenditures and investments and provided returns of capital to shareholders of $9.0 billion through our ordinary dividend and share repurchases. In 2025, we returned $4.0 billion through the ordinary dividend, inclusive of an increase in December of eight percent to 84 cents per share. In addition, we returned $5.0 billion to shareholders through share repurchases. As of December 31, 2025, we have repurchased $39.3 billion of shares of our authorized share repurchase program since 2016. In February 2026, we declared a first-quarter ordinary dividend of 84 cents per share.
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ConocoPhillips 2025 10-KManagement’s Discussion and Analysis
Table of ContentsIn November 2024, we completed our acquisition of Marathon Oil. In the first half of 2025, we completed the asset integration of Marathon Oil and by year-end 2025 achieved more than $1 billion of synergies on a run-rate basis and approximately $1 billion of one-time benefits. These one-time benefits include $0.5 billion recognized previously upon close of the transaction related to the utilization of foreign tax credits, with the remainder related to cash tax benefits from net operating losses, most of which was recognized in 2025. See Note 3 .
Separately, in the second half of 2025, we announced incremental cost reductions and margin enhancements of more than $1 billion anticipated on a run-rate basis by year-end 2026. In late 2025, we initiated a restructuring, reducing our overall employee workforce, which in addition to lease operating cost improvements and opportunities in transportation and processing is expected to contribute approximately $0.8 billion in cost reductions. We anticipate the remaining approximately $0.2 billion to be achieved through margin expansion.
In August 2025, we announced a total disposition target of $5 billion by year-end 2026. We disposed of $3.2 billion of assets in 2025 and we expect to meet our $5 billion disposition target by year-end 2026. Completed dispositions to date include the Ursa and Europa fields and Ursa Oil Pipeline Company LLC for net proceeds of $0.7 billion, the Anadarko Basin for net proceeds of $1.2 billion and other noncore Lower 48 and Corporate assets for approximately $1.3 billion. See Note 3 .
As part of our LNG strategy to build a dynamic portfolio and expand our footprint across the value chain, we have various commercial LNG offtake agreements in North America totaling 10.2 MTPA with offtake commencing between 2026-2031. Furthermore, we currently have a total regasification capacity in Europe of approximately 6.7 MTPA. We continue to progress discussions across all major LNG producing and consuming regions and markets to further add high-quality positions to our portfolio.
Operationally, we remain focused on safely executing the business while also progressing key strategic initiatives. At Willow, we made significant progress and achieved critical milestones, successfully completing our largest winter season. In the Lower 48, we integrated Marathon Oil assets into our portfolio, focusing on operating and capital efficiencies. Internationally, we became the sole operator of the Kebabangan Cluster (KBBC) PSC in Malaysia in January 2025, extending the PSC to 2050 and making KBBC our first operated producing asset in Malaysia. In Canada, we achieved first oil at Surmont Pad 104W-A in December 2025. Additionally, our equity LNG projects continued to advance at NFE and NFS in Qatar and PALNG on the U.S. Gulf Coast.
The relevant provisions of the One Big Beautiful Bill Act (OBBBA), enacted on July 4, 2025, were implemented during the third quarter of 2025. While OBBBA did not have a material effect on our effective tax rate for the quarter, the changes introduced by the legislation impacted our current and deferred tax calculations, with approximately $0.4 billion cash tax benefit recognized in 2025.
Production for 2025 was 2,375 MBOED, representing an increase of 388 MBOED or 20 percent compared to 2024. After adjusting for closed acquisitions and dispositions, production increased by 57 MBOED or 2.5 percent.
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32Management’s Discussion and Analysis
Table of Contents
Business EnvironmentThe energy industry has historically been subject to volatility in commodity prices, which fluctuate with the global economy's supply and demand for energy. Our profitability, reserves base, reinvestment of cash flows and distributions to shareholders are influenced by these fluctuations. Our foundational principles guide our differential value proposition to deliver competitive returns on and of capital to stockholders through price cycles. Our foundational principles consist of maintaining balance sheet strength, providing peer-leading distributions, making disciplined investments and demonstrating responsible and reliable ESG performance, all of which support strong financial returns and mitigate uncertainty associated with volatile commodity prices.
Balance sheet strength. A strong balance sheet is a strategic asset that provides flexibility through price cycles. We strive to maintain our ‘A’-rating, as we did throughout 2025. In 2025, the company retired $0.7 billion principal amount of debt at maturity. We ended the year with cash and cash equivalents and restricted cash of $6.9 billion, short-term investments of $0.5 billion and long-term investments in debt securities of $1.1 billion, maintaining balance sheet strength.
Peer-leading distributions. We believe in delivering value to our shareholders via our return of capital framework, which consists of a growing, sustainable ordinary dividend and share repurchases. This framework is how we plan to return greater than 30 percent of our net cash provided by operating activities to shareholders. In 2025, we returned $4.0 billion to shareholders through our ordinary dividend and $5.0 billion through share repurchases. Our combined dividends and share repurchases of $9.0 billion represented 46 percent of our net cash provided by operating activities.
Disciplined investments. Our goal is to optimize free cash flow by exercising capital discipline, controlling our costs, and safely and reliably delivering production. We expect to make capital investments sufficient to at least sustain production throughout the price cycles. Free cash flow is defined as cash from operations net of capital expenditures and investments and provides funds that are available to return to shareholders, strengthen the balance sheet or reinvest back into the business for future cash flow expansion.
• Exercise capital discipline. Our global portfolio is deep, diverse and durable. As we consider our capital investment opportunities, we apply a rigorous framework that we believe allows for competitive free cash flow to be available to return to shareholders. We believe allocating capital based on low cost of supply resource base will result in higher returns and drive resiliency through low prices. We also balance our investments between short- and longer-cycle projects. For example, in 2025, we continued to invest in short-cycle projects in the Lower 48 segment, as well as longer-cycle projects such as Willow in Alaska. This capital allocation framework seeks to maximize free cash flow through price cycles. Cost of supply is the WTI equivalent price that generates a 10 percent after-tax return on a point-forward and fully burdened basis. Fully burdened basis includes capital infrastructure, foreign currency exchange rates, cost of carbon, price-related inflation and G&A.
• Control our costs. Controlling our costs, without compromising safety or environmental stewardship, is a high priority. Using various methodologies, we monitor costs monthly, on an absolute-dollar basis and a per-unit basis, and report to management. Managing costs is critical to maintaining a competitive position in our cyclical industry and positively impacts our ability to deliver strong cash from operations.
In the second half of 2025, we announced incremental cost reductions and margin enhancements of more than $1 billion anticipated on a run-rate basis by year-end 2026. In late 2025, we initiated a restructuring, reducing our overall employee workforce, which in addition to lease operating cost improvements and opportunities in transportation and processing, is expected to contribute approximately $0.8 billion in cost reductions. We anticipate the remaining approximately $0.2 billion to be achieved through margin expansion.
• Optimize our portfolio. We continually evaluate our assets to determine whether they compete for capital within our portfolio and optimize as necessary, directing capital towards the most competitive investments and disposing of assets that do not compete.
In 2025, we divested assets in Lower 48 including the Ursa and Europa fields and Ursa Oil Pipeline Company LLC, assets in the Anadarko basin and other noncore assets. See Note 3 .
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ConocoPhillips 2025 10-KManagement’s Discussion and Analysis
Table of Contents• Add to our proved reserve base. We primarily add to our proved reserve base in three ways:
• Acquire interests in existing or new fields.
• Apply new technologies and processes to improve recovery from existing fields.
• Successfully explore, develop and exploit new and existing fields.
Reserve replacement represents the net change in proved reserves, net of production, divided by our current year production. Our reserve replacement was 80 percent in 2025, reflecting a net decrease from dispositions in noncore assets in Lower 48 and lower prices, partially offset by development drilling activity and extensions and discoveries. Our organic reserve replacement, which excludes a net decrease of 165 MMBOE from sales and purchases, was 99 percent in 2025.
In the three years ended December 31, 2025, our reserve replacement was 145 percent. Our organic reserve replacement during the three years ended December 31, 2025, which excludes a net increase of 905 MMBOE related to sales and purchases, was 106 percent.
See "Supplementary Data - Oil and Gas Operations" for more information.
Environmental, Social and Governance performance. We are committed to the efficient and effective exploration and production of oil and natural gas. We seek to deliver energy to the world through an integrated management system that assesses sustainability-related business risks and opportunities as part of our decision-making process, and remain committed to our targets. Recognizing the importance of ESG performance to our stakeholders and company success, we have a governance structure that extends from the board of directors to executive leadership and business unit managers.
For more information on our commitment to responsible and reliable ESG performance, see "Contingencies—Company Response to Climate-Related Risks" section of Management's Discussion and Analysis of Financial Condition and Results of Operation.
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34Management’s Discussion and Analysis
Table of Contents
Commodity PricesCommodity prices and the associated realizations are the most significant factor impacting our profitability and related returns on and of capital to our shareholders. Dynamics that could influence world energy markets and commodity prices include, but are not limited to, global economic health, supply or demand disruptions or fears thereof caused by civil unrest, global pandemics, military conflicts, actions taken by OPEC Plus and other major oil producing countries, environmental laws, tariffs, governmental policies and weather-related disruptions. Our strategy is to create value through price cycles by delivering on the financial, operational and ESG priorities that underpin our value proposition.
Our earnings and operating cash flows generally correlate with price levels for crude oil and natural gas, which are subject to factors external to the company and over which we have no control. The following graph depicts the trend in average benchmark prices for WTI crude oil, Brent crude oil and U.S. Henry Hub natural gas since 2023.
The following table presents average prices for 2025 compared to 2024:
Industry Prices 2025 2024 Change
Brent ($ per BBL) $ 69.06 80.76 (14) %
WTI ($ per BBL) 64.81 75.72 (14) %
Henry Hub ($ per MMBTU) 3.43 2.27 51 %
Average Realized Prices
Bitumen realized price ($ per BBL) $ 40.74 47.92 (15) %
Total realized price ($ per BBL) $ 47.01 58.39 (19) %
Crude and bitumen prices were lower through 2025 as global oil supplies increased faster than global oil demand.
Natural gas prices increased due to stronger demand and lower inventory levels relative to 2024.
Our worldwide annual average realized price decrease was driven by lower crude and bitumen prices.
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ConocoPhillips 2025 10-KManagement’s Discussion and Analysis
Table of ContentsKey Operating and Financial Summary
Significant items during 2025 and recent announcements included the following:
• Reported fourth-quarter 2025 earnings per share of $1.17;
• Generated cash provided by operating activities of $19.8 billion;
• Distributed $9.0 billion to shareholders, including $5.0 billion through share repurchases and $4.0 billion through the ordinary dividend;
• Ended the year with cash, cash equivalents, restricted cash and short-term investments of $7.4 billion and long-term investments of $1.1 billion.
• Delivered full-year total company and Lower 48 production of 2,375 MBOED and 1,484 MBOED, respectively;
• Completed the integration of Marathon Oil and doubled synergy capture to more than $1 billion on a run-rate basis in 2025; achieved an additional ~$1 billion of one-time benefits;
• On track to achieve incremental cost reductions and margin enhancements of more than $1 billion on a run-rate basis by year-end 2026;
• Closed $3.2 billion in dispositions in 2025 and on track to meet $5 billion total disposition target by year-end 2026;
• Continued to advance Willow project in Alaska and equity LNG projects at NFE and NFS in Qatar and PALNG on the U.S. Gulf Coast; all projects remain on schedule with NFE startup expected in the second half of 2026;
• Achieved Lower 48 drilling and completion efficiency improvements of more than 15% year over year;
• Advanced commercial LNG strategy by placing initial 5 MTPA of PALNG Phase 1 offtake; secured additional offtake of 5 MTPA to bring total commercial offtake portfolio to 10 MTPA;
• Signed an agreement to extend the Waha Concession in Libya through 2050, with new fiscal terms, subject to normal regulatory approvals; and
• Achieved first oil at Surmont Pad 104W-A in the fourth quarter, ahead of schedule.OutlookCapital, Production and DD&A
Guidance for 2026 includes capital expenditures of approximately $12 billion.
Production guidance is 2.33 to 2.36 MMBOED. First-quarter 2026 production is expected to be 2.30 to 2.34 MMBOED, inclusive of weather-related downtime.
DD&A is expected to be $11.7 to $11.9 billion.Operating SegmentsWe manage our operations through five operating segments, which are primarily defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; and Asia Pacific. Effective in the fourth quarter of 2025, we determined that our former Other International operating segment, which consisted of activities associated with prior operations in other countries, was no longer an operating segment. Residual results are aggregated into Corporate and Other. Our historical operating segment reporting has been recast to reflect this change.
Our combined Corporate and Other represents income and costs not directly associated with an operating segment, such as most interest income and expense; impacts from certain debt transactions; corporate overhead and certain technology activities, including licensing revenues; and unrealized holding gains or losses on equity securities. All cash and cash equivalents and short-term investments are included in Corporate and Other.Our key performance indicators, shown in the statistical tables provided at the beginning of the operating segment sections that follow, reflect results from our operations, including commodity prices and production.ConocoPhillips 2025 10-K
36Results of Operations Table of Contents
Results of OperationsThis section of the Form 10-K discusses year-to-year comparisons between 2025 and 2024. For discussion of year-to-year comparisons between 2024 and 2023, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our 2024 10-K.Consolidated ResultsSummary Operating Statistics2025 2024 2023Average Net Production
Crude oil (MBD)Consolidated operations 1,133 969 923
Equity affiliates 12 13 13
Total crude oil 1,145 982 936Natural gas liquids (MBD)Consolidated operations 411 304 279Equity affiliates 8 8 8Total natural gas liquids 419 312 287
Bitumen (MBD) 133 122 81Natural gas (MMCFD)Consolidated operations 2,859 2,200 1,916
Equity affiliates 1,206 1,233 1,219
Total natural gas 4,065 3,433 3,135Total Production (MBOED)2,375 1,987 1,826
Total Production (MMBOE)
867 727 666Dollars Per Unit
Average Sales PricesCrude oil (per BBL)
Consolidated operations $ 65.58 76.74 78.97
Equity affiliates 68.94 76.76 78.45
Total crude oil 65.62 76.74 78.96
Natural gas liquids (per BBL)
Consolidated operations 20.59 22.43 22.12
Equity affiliates 46.20 51.53 47.09
Total natural gas liquids 21.07 23.19 22.82
Bitumen (per BBL) 40.74 47.92 42.15
Natural gas (per MCF)
Consolidated operations 3.40 2.61 3.89
Equity affiliates 6.83 8.22 8.46
Total natural gas 4.44 4.69 5.69
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ConocoPhillips 2025 10-K
Results of Operations Table of ContentsMillions of Dollars
Worldwide Exploration ExpensesGeneral and administrative; geological and geophysical, lease rental, and other $ 226 309 236
Leasehold impairment 91 6 53
Dry holes 90 40 109
Total Exploration Expenses $ 407 355 398
Total Company Production
We explore for, produce, transport and market crude oil, bitumen, natural gas, NGLs and LNG on a worldwide basis. At December 31, 2025, our operations were producing in the U.S., Norway, Canada, Australia, China, Malaysia, Qatar, Libya and Equatorial Guinea.
Total production of 2,375 MBOED increased 388 MBOED or 20 percent in 2025 compared with 2024. Production increases include:
• New wells online in the Lower 48, Canada, Australia, Norway, Alaska, Libya, China and Malaysia.
• Our acquisition of Marathon Oil in the fourth quarter of 2024.
The increase in production during 2025 was partly offset by normal field decline.
After adjusting for closed acquisitions and dispositions, production increased by 57 MBOED or 2.5 percent.
ConocoPhillips 2025 10-K
38Results of Operations Table of ContentsIncome Statement Analysis
Unless otherwise indicated, all results in Income Statement Analysis are before-tax.
Below is select financial data provided on a consolidated basis. The full income statement can be found in Item 8. Financial Statements and Supplementary Data .
Millions of Dollars
Years Ended December 31
2025 2024 2023
Sales and other operating revenues $ 58,944 54,745 56,141
Equity in earnings of affiliates 1,335 1,705 1,720
Gain (loss) on dispositions 731 51 228
Purchased commodities 22,325 20,012 21,975
Production and operating expenses 10,331 8,751 7,693
Selling, general and administrative expenses 893 1,158 705
Depreciation, depletion and amortization 11,500 9,599 8,270
Other expenses 20 181 2
Income tax provision (benefit) 4,668 4,427 5,331
Sales and other operating revenues increased $4,199 million in 2025, primarily due to higher volumes of $6,197 million, inclusive of sales volumes from our acquisition of Marathon Oil and higher realized gas prices of $824 million and the timing of sales as compared to 2024. These increases were partially offset by lower realized crude and bitumen prices of $4,615 million and $349 million, respectively. See Note 3 .
Equity in earnings of affiliates decreased $370 million in 2025, primarily due to lower earnings driven by lower LNG and crude prices.
Gain (loss) on dispositions increased $680 million in 2025, primarily due to gains associated with the divestitures of the Ursa and Europa fields and Ursa Oil Pipeline Company LLC and other noncore assets in our Lower 48 segment. See Note 3 .
Purchased commodities increased $2,313 million in 2025, primarily due to higher purchased volumes associated with our acquisition of Marathon Oil, higher natural gas prices and higher purchased crude volumes, partly offset by lower crude prices. See Note 3
Production and operating expenses increased $1,580 million in 2025, primarily due to impacts from our acquisition of Marathon Oil in the fourth quarter of 2024 and $216 million of severance costs related to a restructuring. See Note 3 and See Note 14 .
Selling, general and administrative expenses decreased $265 million in 2025, primarily due to the absence of transaction expenses of $545 million associated with our acquisition of Marathon Oil in 2024, partially offset by severance costs related to a restructuring in 2025. See Note 3 and See Note 14 .
DD&A increased $1,901 million in 2025 primarily due to impacts from our acquisition of Marathon Oil in the fourth quarter of 2024 and higher production volumes. See Note 3 .
Other expenses decreased $161 million primarily related to the absence of a loss of $173 million associated with the extinguishment of debt in the fourth quarter of 2024. See Note 7 .
See Note 15 —Income Taxes for information regarding our income tax provision and effective tax rate.
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ConocoPhillips 2025 10-KResults of Operations Table of Contents
Segment Results
Unless otherwise indicated, discussion of Segment Results is after-tax.A summary of the company’s net income (loss) by business segment follows:
Millions of Dollars
Years Ended December 31 2025 2024 2023
Alaska $ 730 1,326 1,778
Lower 48 5,264 5,175 6,461
Canada 741 712 402
Europe, Middle East and North Africa 1,224 1,189 1,189
Asia Pacific 1,167 1,724 1,961
Segments Total 9,126 10,126 11,791
Corporate and Other (1,138) (881) (834)
Net income (loss) $ 7,988 9,245 10,957
For further discussion of segment results, see the following pages.
ConocoPhillips 2025 10-K
40
Results of Operations Table of ContentsAlaska2025 2024 2023
Select financial data by segment before-tax ($MM)
Sales and other operating revenues ($MM) $ 5,638 6,553 7,098
Production and operating expenses ($MM) 2,158 1,951 1,829
Depreciation, depletion and amortization ($MM) 1,399 1,299 1,061
Taxes other than income taxes ($MM) 438 470 497
Net income (loss) ($MM)
$ 730 1,326 1,778Average Net ProductionCrude oil (MBD) 177 173 173
Natural gas liquids (MBD) 15 15 16
Natural gas (MMCFD) 41 39 38Total Production (MBOED)199 194 195
Total Production (MMBOE)
73 71 71Average Sales PricesCrude oil ($ per BBL) $ 71.79 81.73 83.05
Natural gas ($ per MCF) 3.81 3.90 4.47
The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. In 2025, Alaska contributed 12 percent of our consolidated liquids production and one percent of our consolidated natural gas production.Net Income (Loss)Alaska reported earnings of $730 million in 2025, compared with earnings of $1,326 million in 2024.
Decreases to earnings included lower revenues resulting from lower commodity prices of $509 million, partly offset by higher produced volumes of $78 million. Additional decreases to earnings included higher production and operating expenses of $151 million, driven by higher lease operating expenses and well work activity and severance costs related to a restructuring, and higher DD&A of $73 million, primarily driven by higher rates. See Note 14 .ProductionAverage production increased five MBOED in 2025 compared with 2024, primarily due to new wells online and less downtime.
The production increase was partly offset by normal field decline.
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ConocoPhillips 2025 10-KResults of Operations Table of Contents
Lower 482025 2024 2023
Select financial data by segment before-tax ($MM)
Sales and other operating revenues ($MM) $ 41,395 37,026 38,237
Production and operating expenses ($MM) 5,856 4,751 4,199
Depreciation, depletion and amortization ($MM) 8,121 6,442 5,722
Taxes other than income taxes ($MM) 1,506 1,378 1,352
Net income (loss) ($MM)
$ 5,264 5,175 6,461Average Net ProductionCrude oil (MBD) 749 602 569
Natural gas liquids (MBD) 382 279 256
Natural gas (MMCFD) 2,119 1,625 1,457Total Production (MBOED)1,484 1,152 1,067
Total Production (MMBOE)
542 422 389Average Sales PricesCrude oil ($ per BBL) $ 63.18 74.17 76.19
Natural gas liquids ($ per BBL) 20.64 22.02 21.73
Natural gas ($ per MCF) 1.74 0.87 2.12
The Lower 48 segment consists of operations located in the contiguous U.S. and related commercial operations. During 2025, the Lower 48 contributed 67 percent of our consolidated liquids production and 74 percent of our consolidated natural gas production.Net Income (Loss)Lower 48 reported earnings of $5,264 million in 2025, compared with earnings of $5,175 million in 2024.
Increases to earnings included higher revenues resulting from higher volumes of $3,890 million, inclusive of volumes from our acquisition of Marathon Oil, partly offset by lower commodity prices of $1,999 million, driven by lower crude prices. Additional increases included higher gains on dispositions of $494 million, primarily associated with the divestitures of the Ursa and Europa fields and Ursa Oil Pipeline Company LLC, and other noncore assets.
Decreases to earnings included higher DD&A of $1,330 million and higher production and operating expenses of $875 million, primarily driven by impacts from our acquisition of Marathon Oil. See Note 3 .ProductionTotal average production increased 332 MBOED in 2025 compared with 2024, primarily due to new wells online from our development programs in the Delaware Basin, Eagle Ford, Bakken and Midland Basin and the impact from our acquisition of Marathon Oil. See Note 3 .
Production increases were partly offset by normal field decline.
Dispositions
In 2025, we completed multiple divestitures, including the Ursa and Europa fields and Ursa Oil Pipeline Company LLC for net proceeds of $699 million, the Anadarko Basin for net proceeds of $1.2 billion and other noncore assets for $1.1 billion. Production from these assets averaged approximately 33 MBOED in 2024. See Note 3 .
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42Results of Operations Table of Contents
Canada2025 2024 2023
Select financial data by segment before-tax ($MM)
Sales and other operating revenues ($MM) $ 3,625 3,514 3,006
Production and operating expenses ($MM) 833 902 619
Depreciation, depletion and amortization ($MM) 556 639 420
Taxes other than income taxes ($MM) 27 31 26Net Income (Loss) ($MM)$ 741 712 402Average Net ProductionCrude oil (MBD) 17 17 9
Natural gas liquids (MBD) 6 6 3
Bitumen (MBD) 133 122 81
Natural gas (MMCFD) 125 115 65Total Production (MBOED)177 164 104
Total Production (MMBOE)
65 60 38Average Sales PricesCrude oil ($ per BBL) $ 55.35 64.47 66.19
Natural gas liquids ($ per BBL) 22.54 29.59 26.13
Bitumen ($ per BBL) 40.74 47.92 42.15
Natural gas ($ per MCF)* 1.02 0.54 1.80*Average sales prices include unutilized transportation costs.The Canada segment operations include the Surmont oil sands development in Alberta, the Montney unconventional play in British Columbia and commercial operations. In 2025, Canada contributed nine percent of our consolidated liquids production and five percent of our consolidated natural gas production.Net Income (Loss)Canada reported earnings of $741 million in 2025 compared with earnings of $712 million in 2024.
Increases to earnings included higher revenues resulting from higher volumes of $142 million and the timing of sales as compared with 2024 partly offset by lower commodity prices of $303 million. Increases to earnings included lower DD&A of $63 million driven by year-end 2024 upward reserve revisions and higher other income of $62 million primarily from a change in fair value measurement associated with the Surmont contingent consideration arrangement. Additional increases to earnings included lower production and operating expenses of $52 million driven by the absence of prior-year planned turnaround activity at Surmont. See Note 11 .ProductionTotal average production increased 13 MBOED in 2025 compared with 2024. Increases to production resulted from new wells online in the Montney and Surmont and the absence of prior-year planned turnaround activity at Surmont.
Production increases were partly offset by normal field decline.
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ConocoPhillips 2025 10-KResults of Operations Table of Contents
Europe, Middle East and North Africa2025 2024 2023
Select financial data by segment before-tax ($MM)
Sales and other operating revenues ($MM) $ 6,484 5,788 5,854
Production and operating expenses ($MM) 962 671 593
Depreciation, depletion and amortization ($MM) 912 761 587
Taxes other than income taxes ($MM) 46 41 39
Net income (loss) ($MM)
$ 1,224 1,189 1,189Consolidated Operations
Average Net ProductionCrude oil (MBD) 131 118 112
Natural gas liquids (MBD) 8 4 4
Natural gas (MMCFD) 511 371 308Total Production (MBOED)224 184 168
Total Production (MMBOE)
82 67 61Average Sales PricesCrude oil ($ per BBL) $ 68.95 80.92 83.96
Natural gas liquids ($ per BBL) 16.53 40.29 41.13
Natural gas ($ per MCF) 10.87 10.70 12.68
The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian sector of the North Sea, the Norwegian Sea, Qatar, Libya, Equatorial Guinea and commercial and terminalling operations in the U.K. In 2025, our Europe, Middle East and North Africa operations contributed eight percent of our consolidated liquids production and 18 percent of our consolidated natural gas production.Net Income (Loss)The Europe, Middle East and North Africa segment reported earnings of $1,224 million in 2025 compared with earnings of $1,189 million in 2024.
Earnings in 2025 included higher revenues resulting from higher volumes of $296 million, including volumes from our Equatorial Guinea assets from the acquisition of Marathon Oil, partly offset by lower overall realized commodity prices of $185 million, driven by lower crude prices. See Note 3 .
Decreases to earnings included higher production and operating expenses of $88 million, primarily from our acquisition of Marathon Oil. See Note 3 .Consolidated ProductionAverage consolidated production increased 40 MBOED in 2025, compared with 2024. The consolidated production increase was primarily due to the impact from assets acquired from Marathon Oil as well as new wells online in Norway and Libya. See Note 3 .
The production increase was partly offset by normal field decline.
ConocoPhillips 2025 10-K
44Results of Operations Table of Contents
Asia Pacific2025 2024 2023
Select financial data by segment before-tax ($MM)
Sales and other operating revenues ($MM) $ 1,770 1,847 1,913
Production and operating expenses ($MM) 367 384 391
Depreciation, depletion and amortization ($MM) 460 425 455
Taxes other than income taxes ($MM) 57 109 117
Net income (loss) ($MM)
$ 1,167 1,724 1,961Consolidated Operations
Average Net ProductionCrude oil (MBD) 59 59 60
Natural gas (MMCFD) 63 50 48Total Production (MBOED)70 67 68
Total Production (MMBOE)
26 25 25Average Sales PricesCrude oil ($ per BBL) $ 71.05 82.42 84.79
Natural gas ($ per MCF) 3.59 3.74 3.95
The Asia Pacific segment consists of operations in China, Malaysia, and Australia, and commercial operations in China, Singapore and Japan. During 2025, Asia Pacific contributed four percent of our consolidated liquids production and two percent of our consolidated natural gas production.Net Income (Loss)Asia Pacific reported earnings of $1,167 million in 2025, compared with $1,724 million in 2024.
Decreases to earnings included lower revenues resulting from lower commodity prices of $206 million. Additional decreases to earnings included lower earnings from equity affiliates of $271 million, primarily due to lower LNG sales prices and higher exploration expenses of $64 million, primarily driven by dry hole expenses associated with certain wells in Malaysia and Australia.Consolidated ProductionAverage consolidated production increased three MBOED in 2025, compared with 2024. Increases to production were primarily due to development activity in Bohai Bay in China and Gumusut in Malaysia.
Production increases were partly offset by normal field decline.
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ConocoPhillips 2025 10-KResults of Operations Table of ContentsCorporate and Other
Millions of Dollars2025 2024 2023
Net income (loss)
Net interest expense $ (494) (379) (360)
Corporate G&A expenses (486) (716) (357)
Technology (144) (137) (34)
Other income (expense) (14) 352 (70)
$ (1,138) (880) (821)
Net interest expense consists of interest and debt expense, net of interest income and capitalized interest. Net interest expense increased in 2025 due to higher interest expense driven by debt assumed from our acquisition of Marathon Oil. See Note 3 and Note 7 .
Corporate G&A expenses include compensation programs and staff costs. These expenses decreased by $230 million in 2025 compared with 2024, primarily due to the absence of transaction expenses of $432 million associated with our acquisition of Marathon Oil in 2024, partially offset by severance costs related to a restructuring in 2025. See Note 3 and Note 14 .
Technology includes our investments in low-carbon technology opportunities as well as other new technologies or businesses and licensing revenues. Other new technologies or businesses and LNG licensing activities are focused on both conventional and tight oil reservoirs, shale gas, oil sands, enhanced oil recovery as well as LNG.
Other income (expense) or "Other" includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, other costs not directly associated with an operating segment, gains or losses on early retirement of debt, holding gains or losses on equity securities and pension settlement expense. Earnings in “Other” decreased by $366 million in 2025 compared with 2024. This was primarily due to the absence of a tax benefit of $455 million as a result of the acquisition of Marathon Oil in 2024 and the subsequent utilization of foreign tax credits. The earnings decrease was partly offset by an increase due to the absence of a loss of $147 million associated with the extinguishment of debt in the fourth quarter of 2024. See Note 3, Note 7 and Note 15 .
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Capital Resources and Liquidity
Financial Indicators
Millions of Dollars Except as Indicated2025 2024 2023
Net cash provided by operating activities $ 19,796 20,124 19,965
Cash and cash equivalents 6,497 5,607 5,635
Short-term investments 484 507 971
Short-term debt 1,020 1,035 1,074
Total debt 23,444 24,324 18,937
Total equity 64,487 64,796 49,279
Percent of total debt to capital* 27 % 27 28
Percent of floating-rate debt to total debt 1 % 1 2
Balance Sheet related line items are shown as of December 31st.*Capital includes total debt and total equity.To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, including cash generated from operating activities, our commercial paper and credit facility programs and our ability to sell securities using our shelf registration statement. In 2025, the primary uses of our available cash were $12.6 billion to support our ongoing capital expenditures and investments program; $5.0 billion to repurchase common stock; $4.0 billion to pay the ordinary dividend; and $0.9 billion to retire debt, partly offset by proceeds from asset sales of $3.2 billion. In 2025, cash and cash equivalents increased by $0.9 billion to $6.5 billion. See Note 3 and Not e 7 .
At December 31, 2025, we had cash and cash equivalents of $6.5 billion, short-term investments of $0.5 billion, and available borrowing capacity under our credit facility of $5.5 billion, totaling approximately $12.5 billion of liquidity. In addition, we have long-term investments in debt securities of $1.1 billion. We believe current cash balances and cash generated by operations, together with access to external sources of funds as described below in the “Significant Changes in Capital” section, will be sufficient to meet our funding requirements in the near- and long-term, including our capital spending program, capital return program and required debt payments.Significant Changes in Capital
Operating ActivitiesCash provided by operating activities in 2025 totaled $19.8 billion, compared with $20.1 billion for 2024, and $20.0 billion for 2023. The decrease in 2025 compared to 2024 resulted from lower commodity prices, mostly offset by operations from the 2024 Marathon Oil acquisition. See Note 3 .
The increase in cash provided by operating activities in 2024 compared to 2023 is due to increased production primarily from Canada and the Lower 48, including the Surmont 50 percent working interest acquired in the fourth quarter of 2023 and our acquisition of Marathon Oil in late 2024. The increase in production was partly offset by lower commodity prices and lower distributions from equity affiliates. See Note 3 .
Our short- and long-term operating cash flows are highly dependent on the prices for crude oil, bitumen, natural gas, LNG and NGLs. Prices and margins in our industry have historically been volatile, driven by market conditions beyond our control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.
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Table of ContentsThe level of absolute production volumes, as well as the product and location mix, is another significant factor impacting our cash flows. Full-year production averaged 2,375 MBOED in 2025, an increase of 388 MBOED or 20 percent compared to 2024. First-quarter 2026 production is expected to be 2.30 MMBOED to 2.34 MMBOED. Future production is subject to numerous uncertainties, including, among others, the volatile crude oil and natural gas price environment, which may impact investment decisions; the effects of price changes on production sharing and variable-royalty contracts; acquisition and disposition of fields; field production decline rates; new technologies; operating efficiencies; timing of startups and major turnarounds; political instability; weather-related disruptions; and the addition of proved reserves through exploratory success and their timely and cost-effective development. While we actively monitor and manage these factors, changes in production levels can cause variability in cash flows, although we generally experience less variability in our cash flows due to changes in production levels than due to changes in commodity prices.Investing ActivitiesIn 2025, we invested $12.6 billion in capital expenditures and investments, $0.5 billion of which was primarily payments towards our equity investments in LNG projects, including NFE4, NFS3 and PALNG, while the remainder funded our operating capital program. Capital expenditures invested in 2024 and 2023 were $12.1 billion and $11.2 billion, respectively. See the “Capital Expenditures and Investments” section.
In August 2025, we announced a total disposition target of $5 billion by year-end 2026. We disposed of $3.2 billion of assets in 2025 and we expect to meet our $5 billion disposition target by year-end 2026. See Note 3.
Proceeds from asset sales were $3.2 billion in 2025 compared with $0.3 billion in 2024 and $0.6 billion in 2023. In 2025, we sold Lower 48 assets in the Anadarko basin for net proceeds of $1.2 billion and our interest in the Ursa and Europa fields, and Ursa Oil Pipeline Company LLC for net proceeds of $0.7 billion. Additionally, we sold other noncore Lower 48 and Corporate assets for approximately $1.3 billion . See Note 3.
In the fourth quarter of 2024, after exercising our preferential rights, we completed an acquisition that increased our working interest by approximately five percent in the Kuparuk River Unit and approximately 0.4 percent in the Prudhoe Bay Unit in Alaska from Chevron U.S.A. Inc. and Union Oil Company of California for $296 million, before customary adjustments. See Note 3.
In October 2023, we acquired the remaining 50 percent working interest in Surmont from TotalEnergies EP Canada Ltd. for approximately $2.7 billion of cash after customary adjustments. We funded this transaction by issuing new long-term debt. See Note 3 and Note 7.
We invest in short-term and long-term investments as part of our cash investment strategy, the primary objective of which is to protect principal, maintain liquidity and provide yield and total returns; these investments include time deposits, commercial paper, as well as debt securities classified as available for sale. Funds needed for short-term investments to support our operating plan and provide resiliency to react to short-term price volatility are invested in highly liquid instruments with maturities of less than one year. Funds we consider available to maintain resiliency in longer term price downturns and to capture opportunities outside a given operating plan are invested in highly liquid instruments with maturities of greater than one year. See Note 10 and Note 17.
Investing activities in 2025 included net purchases of $55 million of investments. We had net sales of $502 million of short-term investments and net purchases of $557 million of long-term investments. See Note 17.
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Financing ActivitiesOur debt balance at December 31, 2025 was $23.4 billion compared with $24.3 billion at December 31, 2024. The current portion of debt, including payments for finance leases, is $1.0 billion.
In 2025, the company retired $0.7 billion principal amount of debt at maturity, consisting of $0.2 billion of our 3.35% Notes, $0.4 billion of our 2.4% Notes and $0.1 billion of our 8.2% Debentures.
In November 2024, we acquired Marathon Oil. At closing, the acquisition was valued at $16.5 billion and was allocated to assets acquired and liabilities assumed. ConocoPhillips common stock was issued and exchanged for outstanding Marathon Oil shares. With the acquisition, we also assumed Marathon Oil's debt of approximately $4.6 billion. See Note 3 and Note 7.
In 2024, the company retired $726 million principal amount of Notes at maturity consisting of $265 million of our 3.35% Notes and $461 million of our 2.125% Notes. In addition, we completed concurrent debt transactions consisting of new long-term debt issuances of $5.2 billion; a $4.1 billion repurchase of certain existing Marathon Oil and ConocoPhillips debt (with priority for Marathon Oil debt assumed); a non-cash obligor exchange offer to retire $0.9 billion of Marathon Oil debt in exchange for new ConocoPhillips debt; and remarketing of $0.4 billion in available municipal bonds. The debt transactions simplified our capital structure, extended the debt portfolio's weighted average maturity, lowered its weighted average coupon and reduced near-term maturities. See Note 7.
In 2023, we issued $2.7 billion principal amount of new debt to fund our acquisition of the remaining 50 percent working interest in Surmont and completed refinancing transactions consisting of $1.1 billion in tender offers to repurchase existing debt with cash and a $1.1 billion new debt issuance to fund the repurchases, extending the weighted average maturity of our portfolio from 15 to 17 years and reducing near-term debt maturities. See Note 7.
In February 2025, we refinanced our revolving credit facility maintaining a total aggregate principal amount of $5.5 billion and extended the expiration to February 2030. Our revolving credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as support for our commercial paper program. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or any of its consolidated subsidiaries. The amount of the facility is not subject to redetermination prior to its expiration date.Credit facility borrowings may bear interest at a margin above the Secured Overnight Financing Rate (SOFR). The agreement calls for commitment fees on available, but unused, amounts. The agreement also contains early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.The revolving credit facility supports ConocoPhillips Company’s ability to issue up to $5.5 billion of commercial paper, which is primarily a funding source for short-term working capital needs. Commercial paper maturities are generally limited to 90 days. With no commercial paper outstanding and no direct borrowings or letters of credit, we had access to $5.5 billion in available borrowing capacity under our revolving credit facility at December 31, 2025 .
In November 2025, Fitch affirmed our long-term credit rating. The current credit ratings on our long-term debt are:• Fitch: “A” with a “stable” outlook
• S&P: “A-” with a “stable” outlook• Moody's: “A2 " with a “stable " outlook
See Note 7 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.49
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Table of ContentsCertain of our project-related contracts, commercial contracts and derivative instruments contain provisions requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters of credit as collateral. At December 31, 2025 and 2024, we had direct bank letters of credit of $331 million and $278 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business. In the event of a credit rating downgrade, we may be required to post additional letters of credit.
Shelf Registration
We have a universal shelf registration statement on file with the SEC under which we have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.Capital RequirementsFor information about our capital expenditures and investments, see the “Capital Expenditures and Investments” section. For information about our debt balances and related debt financing transactions, see the "Significant Changes in Capital - Financing Activities" section.
We believe in delivering value to our shareholders through our return of capital framework. The framework is structured to deliver a compelling, growing ordinary dividend and through-cycle share repurchases. We anticipate returning greater than 30 percent of cash from operating activities through cycles. Our 2025 total capital returned was $9.0 billion.
Consistent with our commitment to deliver value to shareholders, for the full year of 2025, we paid ordinary dividends of $3.18 per common share. In 2024 we paid ordinary dividends of $2.52 and VROC payments of $0.60 per common share and in 2023 we paid ordinary dividends of $2.11 and VROC payments of $2.50 per common share. In February 2026, we declared a first-quarter ordinary dividend of $0.84 per common share payable March 2, 2026, to shareholders of record on February 18, 2026.
Our Board may determine not to pay a dividend in a quarter or may cease declaring a dividend at any time.
In late 2016, we initiated our current share repurchase program. In October 2024, our Board of Directors approved an increase from our prior authorization of $45 billion by a total of the lesser of $20 billion or the number of shares issued in our acquisition of Marathon Oil, such that the company is not to exceed $65 billion in aggregate repurchases. Share repurchases were $5.0 billion, $5.5 billion, and $5.4 billion in 2025, 2024, and 2023, respectively. As of December 31, 2025, share repurchases since the inception of our current program totaled 486.1 million shares for $39.3 billion since 2016. 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, 2025, in addition to the priorities described above, we have contractual obligations to purchase goods and services of approximately $45.0 billion. We expect to fulfill $5.0 billion of these obligations in 2026 with the remainder over the next 25 years. A substantial amount of LNG offtake and other product purchases are expected to be offset in the same or approximately same periods by cash received from the related sales transactions. These figures exclude purchase commitments for jointly owned fields and facilities where we are not the operator.
The following table summarizes our aggregate future contractual purchase obligations as of December 31, 2025:
Millions of Dollars
2025
LNG offtake, regasification and related vessels $ 29,722
Other capacity obligations 10,890
Other product purchases 3,094
Other obligations 1,271
Total $ 44,977
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Capital Expenditures and Investments
Millions of Dollars2025 2024 2023
Alaska $ 3,607 3,194 1,705
Lower 48 6,702 6,510 6,487
Canada 593 551 456
Europe, Middle East and North Africa 1,194 1,021 1,111
Asia Pacific 342 370 354
Segments Total 12,438 11,646 10,113
Corporate and Other 115 472 1,135
Capital Program* $ 12,553 $ 12,118 $ 11,248* Excludes capital related to acquisitions of businesses, net of cash acquired.Our capital expenditures and investments for the three-year period ended December 31, 2025, totaled $35.9 billion. The 2025 capital expenditures and investments supported key operating activities and acquisitions, primarily:
• Appraisal and development activities in Alaska related to the Western North Slope, inclusive of Willow, and development activities in the Greater Kuparuk Area.
• Development activities in the Lower 48, primarily in the Delaware Basin, Eagle Ford, Midland Basin and Bakken.
• Appraisal and development activities in the Montney as well as development and optimization of Surmont in Canada.
• Development and appraisal activities across assets in Norway and development activities in Libya.
• Continued development activities in China.
• Investments in NFE4, NFS3 and PALNG.
2026 Capital Budget
In February 2026, we announced our 2026 operating plan capital is expected to be approximately $12 billion. The plan includes funding for ongoing development drilling programs, major projects, exploration and appraisal activities and base maintenance.
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Guarantor Summarized Financial Information
We have various cross guarantees among ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. Burlington Resources LLC is 100 percent owned by ConocoPhillips Company. ConocoPhillips and/or ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of Burlington Resources LLC with respect to its publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several.
The following tables present summarized financial information for the Obligor Group, as defined below:
• The Obligor Group will reflect guarantors and issuers of guaranteed securities consisting of ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC.
• Consolidating adjustments for elimination of investments in and transactions between the collective guarantors and issuers of guaranteed securities are reflected in the balances of the summarized financial information.
• Non-Obligated Subsidiaries are excluded from this presentation.
Transactions and balances reflecting activity between the Obligors and Non-Obligated Subsidiaries are presented separately below:
Summarized Income Statement Data
Millions of Dollars2025
Revenues and Other Income $ 38,564
Income (loss) before income taxes* 7,316
Net income (loss) 7,988
* Includes approximately $11.6 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.Summarized Balance Sheet Data
Millions of DollarsDecember 31, 2025
Current assets $ 8,206
Amounts due from Non-Obligated Subsidiaries, current 855
Noncurrent assets 130,320
Amounts due from Non-Obligated Subsidiaries, noncurrent 11,231
Current liabilities 4,947
Amounts due to Non-Obligated Subsidiaries, current 1,244
Noncurrent liabilities 74,824
Amounts due to Non-Obligated Subsidiaries, noncurrent 52,813ContingenciesWe are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See “Critical Accounting Estimates” and Note 9 for information on contingencies.Legal and Tax MattersWe are subject to various lawsuits and claims, including but not limited to matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, climate change, personal injury and property damage. Our primary exposures for such matters relate to alleged royalty and tax underpayments on certain federal, state and privately owned properties, claims of alleged environmental contamination and damages from historic operations and climate change. We will continue to defend ourselves vigorously in these matters.
Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process
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facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required. See Note 15 .EnvironmentalWe are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. The most significant of these environmental laws and regulations include, among others, the:• U.S. Federal Clean Air Act, which governs air emissions;
• U.S. Federal Clean Water Act, which governs discharges to water bodies;• EU Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals;• U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund), which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;
• U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage, and disposal of solid waste;• U.S. Federal Oil Pollution Act of 1990, under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the U.S.;
• U.S. Federal Emergency Planning and Community Right-to-Know Act, which requires facilities to report toxic chemical inventories with local emergency planning committees and response departments;• U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells;
• U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages; and• EU Trading Directive resulting in EU Emissions Trading Scheme (EU ETS).These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also establish standards and impose obligations for the remediation of releases of hazardous substances and hazardous wastes. In most cases, these regulations require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.
Many states and foreign countries where we operate also have or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards and water quality standards, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the U.S. and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the U.S. and Canada.
An example is the use of hydraulic fracturing, an essential completion technique that facilitates production of oil and natural gas otherwise trapped in lower permeability rock formations. A range of local, state, federal, or national laws and regulations currently govern hydraulic fracturing operations, with hydraulic fracturing currently prohibited in some jurisdictions. Although hydraulic fracturing has been conducted for many decades, potential new laws, regulations and permitting requirements from various state environmental agencies, and others could result in increased costs, operating restrictions, operational delays and/or limit the ability to develop oil and natural gas resources. Governmental restrictions on hydraulic fracturing could impact the overall profitability or viability of certain of our oil and natural gas investments. We have adopted operating principles that incorporate established industry standards that are designed to meet government requirements. Our practices continually evolve as technology improves and regulations change.
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Table of ContentsWe also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their equivalents in their respective jurisdictions. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.
We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain waste attributable to our past operations. As of December 31, 2025, there were 20 sites around the U.S. in which we were identified as a potentially responsible party under CERCLA and comparable state laws.For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.Expensed environmental costs were $834 million in 2025 and are expected to be approximately $1.0 billion in each of 2026 and 2027. Capitalized environmental costs were $669 million in 2025 and are expected to be about $750 million and $550 million in 2026 and 2027, respectively.Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).
Many of these liabilities result from CERCLA, RCRA, and similar state or international laws that require us to undertake certain investigative and remedial activities at sites where we conduct or once conducted operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we identified that may require environmental remediation but which are not currently the subject of CERCLA, RCRA, or other agency enforcement activities. The laws that require or address environmental remediation may apply retroactively and regardless of fault, the legality of the original activities or the current ownership or control of sites. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA.Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.At December 31, 2025, our balance sheet included total accrued environmental costs of $220 million, compared with $206 million at December 31, 2024, for remediation activities in the U.S. and Canada. We expect to incur a substantial amount of these expenditures within the next 30 years.Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect upon our results of operations or financial position as a result of compliance with current environmental laws and regulations.See Item 1A. Risk Factors—We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations and Note 9 for information on environmental litigation.
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Table of ContentsClimate ChangeContinuing 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 laws apply or could apply in countries where we have interests or may have interests in the future. Additionally, some laws have been rescinded or delayed, creating policy swings that result in compliance uncertainty. 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 operational results and financial condition. Examples of legislation and precursors for possible regulation that do or could affect our operations include:
Emissions trading schemes.
• EU ETS is the program through which many of the EU member states aim to reduce emissions. Our cost of compliance with the EU ETS in 2025 was approximately $21 million (net share before-tax).
• The U.K. Emissions Trading Scheme (U.K. ETS) is the program with which the U.K. has replaced the EU ETS. Our cost of compliance with the U.K. ETS in 2025 was approximately $2.2 million (net share before-tax).
GHG regulations for emissions reductions.
• The Alberta Technology Innovation and Emissions Reduction (TIER) regulation requires any existing facility with emissions equal to or greater than 100,000 metric tonnes of carbon dioxide, or equivalent, per year to meet a facility benchmark intensity. There was no cost of compliance related to this regulation in 2025, as our Surmont asset outperformed its target benchmark intensity over the full year reporting period.
• As of April 2024, the British Columbia Output Based Pricing System (BC OBPS) regulation requires facilities or linear operations (such as oil and gas gathering systems) with emissions equal to or greater than 10,000 metric tonnes of carbon dioxide or equivalent per year to remit payments on the difference between actual emissions and allowable emissions based on product and activity benchmarks. The benchmarks and guidance for these emissions have yet to be finalized, and compliance payments for 2025 are not due until later in 2026. Based on interim benchmarks, our BC OBPS obligation is expected to total a maximum of $12.3 million (net share before-tax) for Montney in 2025.
• In 2024, the EU passed regulation on the reduction of methane emissions in the energy sector that will apply a methane limit on oil and gas imports to the EU, as well as mandate the monitoring, reporting, verification and reduction of methane emissions.
• Our APLNG assets in Australia are subject to the Safeguard Mechanism, enacted through the National Greenhouse and Energy Reporting Act 2007. In the previous Australian financial year of July 1, 2024, to June 30, 2025, our operated downstream APLNG facility was in excess of its baseline emissions, while the upstream partner-operated facilities were below their baseline emissions. As there was a surplus of eligible carbon units across the joint venture, there was no expense incurred by ConocoPhillips for the 2025 Australian financial year.
• In 2024 the U.S. EPA published final rulemaking for New Source Performance Standards (OOOOb) and Emissions Guidelines (OOOOc). Implementing this regulation across our U.S. portfolio will result in additional compliance costs.
Carbon taxes in certain jurisdictions.
• Effective April 1, 2025, the Canadian federal government set the consumer carbon price to zero and no longer requires a consumer carbon tax going forward. This is separate from the obligated industrial carbon pricing schemes of Alberta TIER and BC OBPS, which remain in place. Our operations outside of industrial carbon pricing schemes were minimal at Surmont for the first quarter of 2025, and no Federal Fuel charges were incurred at Montney in 2025.
• Our cost of compliance with Norwegian carbon legislation in 2025 was approximately $42 million (net share before-tax).
Other environmental regulations.
• The White House Council on Environmental Quality (CEQ) issued final National Environmental Policy Act implementation regulations (NEPA Phase 2) in 2024. Since then, the DC Circuit Court has suggested that CEQ lacks authority to adopt any binding regulations, introducing potential uncertainty into the regulatory process.
• Climate Superfund laws. In 2024, New York and Vermont passed legislation seeking to hold certain energy companies financially responsible for state climate change mitigation and adaptation measures, following the “polluter pays” model of existing Superfund laws. This responsibility may include paying into a fund for infrastructure repairs and recovery from extreme weather events that would otherwise be covered by the government. While only two U.S. states have enacted such laws to date, it is likely that more states will consider a similar approach. Compliance with such legislation may expose us to significant additional liabilities.
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Table of Contents• Climate Private Action laws. In 2025, California, New Hampshire, and Oregon introduced bills seeking to create a private right of action for individuals to bring strict liability claims for alleged damages related to climate change impacts (including non-economic, actual and punitive damages). These bills also authorize insurance companies to pursue subrogation claims to recover damages for amounts paid to insureds for climate change impacts.
Non-regulatory initiatives or agreements.
• The Global Methane Pledge (GMP) was launched at COP26 by the EU and the U.S., a global initiative to reduce global methane emissions by at least 30 percent from 2020 levels by 2030.
• The agreement reached in Paris in December 2015 at the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change set out a process for achieving global emissions reductions. Accordingly, parties to the Paris Agreement have set targets to reduce emissions by 2030. While the current administration has officially withdrawn the U.S. from the Paris Agreement, some U.S. states have indicated that they plan to remain committed to the goals of the agreement.
Regulated sustainability disclosures.
Governments and financial regulators are developing new reporting rules requiring increased disclosure around a range of sustainability topics. The patchwork of reporting standards that is developing may require significant increases in disclosures, which may be costly to implement. In June 2023 the International Sustainability Standards Board issued inaugural sustainability reporting standards; in October 2023 in California multiple bills were signed into law requiring climate-related disclosures for companies that conduct business in the state; in September 2024, the Australian Government passed legislation which mandated a new standard for climate-related disclosures; and in the EU, the Corporate Sustainability Reporting Directive is expected to be finalized in 2026.Compliance with changes in laws and regulations that create a GHG tax, emission trading scheme or GHG reduction policies could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also increase demand for less carbon intensive energy sources, including natural gas. The ultimate impact on our financial performance, either positive or negative, will depend on a number of factors, including but not limited to:
• Whether and to what extent legislation or regulation is enacted;
• The timing of the introduction of such legislation or regulation;
• The nature of the legislation (such as a cap and trade system or a tax on emissions) or regulation;
• The price placed on GHG emissions (either by the market or through a tax);• The GHG emissions reductions required;• The price and availability of offsets;
• The amount and allocation of allowances;
• Technological and scientific developments leading to new products or services;
• Any potential significant physical effects of climate change (such as increased severe weather events, changes in sea levels and changes in temperature); and
• 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 9 for information on climate change litigation.Company Response to Climate-Related RisksThe objective of our Climate-related Risk Strategy is to manage climate-related risk, optimize opportunities and equip the company to respond to changes in key uncertainties, including government policies around the world, emissions reduction technologies, alternative energy technologies and changes in consumer trends. The strategy guides our choices around portfolio composition, emissions reductions, targets, incentives, emissions-related technology development, and our climate-related policy and finance sector engagement.
Our Climate-related Risk Strategy is intended to enable us to responsibly meet the global demand for energy, deliver competitive returns on and of capital and work to meet our operational emissions-reduction targets. First, meeting global energy demand requires a focus on delivering production that will best compete in any energy demand scenario. This production will be delivered from resources with a competitive cost of supply and low operational GHG intensity, as well as portfolio diversity by market and asset type. Next, our focus is on delivering superior returns through the cycles based on our foundational principles of balance sheet strength, peer-leading distributions and disciplined investments. Finally,
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Table of Contentsto drive accountability for the emissions that are within our ownership, we are progressing toward our Scope 1 and Scope 2 emissions intensity targets.
Key elements of the Climate-related Risk Strategy include:
• Strategic flexibility and portfolio composition
◦ Building a resilient asset portfolio with a focus on low cost of supply and low operational GHG intensity to meet global energy demand.◦ Committing to capital discipline through use of a fully burdened cost of supply, including cost of carbon, as the basis for capital allocation.◦ Testing our portfolio against future energy demand scenarios through a comprehensive scenario planning process that helps us assess the resilience of our corporate strategy to climate risk.
• Scope 1 and 2 GHG emissions targets and reductions
◦ Setting targets for emissions over which we have ownership and control.
◦ Reducing emissions through the marginal abatement cost curve process.
• LNG and technology
◦ Building an attractive LNG portfolio as an important component of responsibly meeting global energy demand due to LNG's opportunity to displace higher-emissions fuels such as coal for electricity generation.
◦ Evaluating potential investments in emerging alternative energy sources and low-carbon technologies.
• External engagement
◦ Supporting a well-designed, economy-wide price on carbon and development of other policy and legislation to address end-use emissions.
◦ Working with our suppliers and commercial partners to understand our emissions along the value chain.
Our Climate-related Risk Strategy does not include a Scope 3 emissions target. We recognize that end-use emissions must be reduced to meet global climate objectives. However, it is our view that supply-side constraints through Scope 3 targets for North American and European upstream oil and gas producers would be counterproductive to climate goals. In the absence of policy measures that address global demand, Scope 3 targets would shift production to other global operators, potentially eroding energy security and increasing emissions. This is why we have consistently supported a well-designed, economy wide price on carbon as well as the development of other policies or legislation that could address end-use emissions. We have also supported policy interests beyond carbon pricing to include energy efficiency, end-use emissions policy and regulatory action, such as support for the direct federal regulation of methane.
In support of addressing our Scope 1 and 2 emissions, we have made recent progress in several key areas.
• Completed our 2025 scope 1 and 2 emissions reduction projects within the allotted capital and cost budget. These projects will support our GHG emissions intensity reduction target of 50-60 percent by 2030 from a 2016 baseline for both gross operated and net equity emissions.
• Achieved the Gold Standard Reporting for emissions reporting in the Oil and Gas Methane Partnership 2.0 Initiative for the second consecutive year.
• Achieved our target of zero routine flaring by the end of 2025 for heritage ConocoPhillips assets by taking all economically viable steps to eliminate routine flaring in accordance with the World Bank Zero Routine Flaring Initiative.
• Introduced a new commitment to maintain flaring intensity of less than 0.75 percent of gas produced at operated assets, to be implemented in 2026.
See Item 1A. Risk Factors—Our ability to successfully execute on our plans to reduce our operational GHG emissions intensity is subject to a number of risks and uncertainties, and such reductions may be costly and challenging to achieve.New Accounting StandardsFor discussion of new accounting standards, see Note 23 .
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Critical Accounting EstimatesThe 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 significant 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.Oil and Gas Accounting
Accounting for oil and gas activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of G&G seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been recognized.
Property Acquisition Costs
For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For insignificant individual leasehold acquisition costs, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves, including estimates of future expirations, and pools that leasehold information with others in similar geographic areas. For prospects in areas with limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense. This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively.At year-end 2025, we held $10.0 billion of net capitalized unproved property costs. These capitalized costs consist primarily of individually significant and pooled leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells currently being drilled, suspended exploratory wells and capitalized interest. Of this amount, approximately $8.7 billion is concentrated in the Lower 48 Basins, primarily the Delaware, Eagle Ford and Bakken Basins, where we have an ongoing significant and active development program. Outside of the Lower 48 Basins, the remaining $1.3 billion is primarily concentrated in Canada. Management periodically assesses our unproved property for impairment based on the results of exploration and drilling efforts and the outlook for commercialization.Exploratory CostsFor exploratory wells, drilling costs are temporarily capitalized, or “suspended,” on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to justify development. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. The accounting notion of “sufficient progress” is a judgmental area, but the accounting rules do prohibit continued capitalization of suspended well costs on the expectation future market conditions will improve or new technologies will be found that would make the development economically profitable. Often, the ability to move into the development phase and record proved reserves is dependent on obtaining permits and government or coventurer approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits and believe they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves.
At year-end 2025, total suspended well costs were $243 million, compared with $196 million at year-end 2024. For additional information on suspended wells, including an aging analysis, see Note 5 .
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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 2025, the net book value of productive PP&E subject to a unit-of-production calculation was approximately $80 billion and the DD&A recorded on these assets in 2025 was approximately $11.2 billion. The estimated proved developed reserves for our consolidated operations were 4.5 billion BOE at the end of 2024 and 4.2 billion BOE at the end of 2025. 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 2025 would have increased by an estimated $1,250 million.Business Combination—Valuation of Oil and Gas Properties
For business combinations, management applies the principles of acquisition accounting under FASB ASC Topic 805 – “Business Combinations” and allocates the purchase price to assets acquired and liabilities assumed, based on their estimated fair values as of the acquisition date. Estimating the fair values involves making various assumptions, of which the most significant assumptions relate to the fair values assigned to proved and unproved oil and gas properties. For significant business combinations, management generally utilizes a discounted cash flow approach, based on market participant assumptions, and considers engaging third party valuation experts in preparing fair value estimates.Significant inputs incorporated within the valuation include future commodity price assumptions and production profiles of reserve estimates, future operating and development costs, inflation rates, and discount rates using a market-based weighted average cost of capital determined at the time of the acquisition. When estimating the fair value of unproved properties, additional risk-weighting adjustments are applied to probable and possible reserves.
The assumptions and inputs incorporated within the fair value estimates are subject to considerable management judgment and are based on industry, market and economic conditions prevalent at the time of the acquisition. Although we based these estimates on assumptions believed to be reasonable, these estimates are inherently unpredictable and uncertain and actual results could differ. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate is recorded. Subsequent to the acquisition date, and not later than one year from the acquisition date, we record any material adjustments to the initial estimate based on new information obtained that would have existed as of the date of the acquisition. Any adjustment that arises from information obtained that did not exist as of the date of acquisition is recorded in the period the adjustment arises. See Note 3 .
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Impairments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If there is an indication the carrying amount of an asset may not be recovered, a recoverability test is performed using management’s assumptions for prices, volumes and future development plans. If the sum of the undiscounted cash flows before income-taxes is less than the carrying value of the asset group, the carrying value is written down to estimated fair value and reported as an impairment in the periods in which the determination is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for E&P assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates and prices believed to be consistent with those used by principal market participants, or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible.The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, commodity prices, operating costs and capital decisions, considering all available evidence at the date of review. Differing assumptions could affect the timing and the amount of an impairment in any period.
Investments in nonconsolidated entities accounted for under the equity method are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred. Such evidence of a loss in value might include our inability to recover the carrying amount, the lack of sustained earnings capacity which would justify the current investment amount, or a current fair value less than the investment’s carrying amount. When such a condition is judgmentally determined to be other than temporary, an impairment charge is recognized for the difference between the investment’s carrying value and its estimated fair value. When determining whether a decline in value is other than temporary, management considers factors such as the length of time and extent of the decline, the investee’s financial condition and near-term prospects and our ability and intention to retain our investment for a period that will be sufficient to allow for any anticipated recovery in the market value of the investment. Since quoted market prices are usually not available, the fair value is typically based on the present value of expected future cash flows using discount rates and prices believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate. Differing assumptions could affect the timing and the amount of an impairment of an investment in any period.Asset Retirement Obligations and Environmental CostsUnder various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and restore the land or seabed at the end of operations at operational sites. Our largest asset removal obligations involve plugging and abandonment of wells, removal and disposal of offshore oil and gas platforms around the world, as well as oil and gas production facilities and pipelines in Alaska. Fair value is estimated using a present value approach, incorporating assumptions about estimated amounts and timing of settlements and impacts of the use of technologies. Estimating future asset removal costs requires significant judgment. Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. The carrying value of our asset retirement obligation estimate is sensitive to inputs such as asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, which are all subject to change between the time of initial recognition of the liability and future settlement of our obligation.Normally, changes in asset removal obligations are reflected in the income statement as increases or decreases to DD&A over the remaining life of the assets. However, for assets at or nearing the end of their operations, as well as previously sold assets for which we retained the asset removal obligation, an increase in the asset removal obligation can result in an immediate charge to earnings, because any increase in PP&E due to the increased obligation would immediately be subject to impairment, due to the low fair value of these properties.In addition to asset removal obligations, under the above or similar contracts, permits and regulations, we have certain environmental-related projects. These are primarily related to remediation activities required by Canada and various states within the U.S. at exploration and production sites. Future environmental remediation costs are difficult to estimate because they are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. See Note 6 .
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Projected Benefit ObligationsThe actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations and company contribution requirements. Ultimately, we will be required to fund all vested benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Projected benefit obligations are particularly sensitive to the discount rate assumption. A 100 basis-point decrease in the discount rate assumption would increase projected benefit obligations by $500 million. Benefit expense is sensitive to the discount rate and return on plan assets assumptions. A 100 basis-point decrease in the discount rate assumption would increase annual benefit expense by $50 million, while a 100 basis-point decrease in the return on plan assets assumption would increase annual benefit expense by $50 million. In determining the discount rate, we use yields on high-quality fixed income investments matched to the estimated benefit cash flows of our plans. We are also exposed to the possibility that lump sum retirement benefits taken from pension plans during the year could exceed the total of service and interest components of annual pension expense and trigger accelerated recognition of a portion of unrecognized net actuarial losses and gains. These benefit payments are based on decisions by plan participants and are therefore difficult to predict. In the event there is a significant reduction in the expected years of future service of present employees or the elimination of the accrual of defined benefits for some or all of their future services for a significant number of employees, we could recognize a curtailment gain or loss. See Note 14 .ContingenciesA number of claims and lawsuits are made against the company arising in the ordinary course of business. Management exercises judgment related to accounting and disclosure of these claims which includes losses, damages and underpayments associated with environmental remediation, tax, contracts and other legal disputes. As we learn new facts concerning contingencies, we reassess our position both with respect to amounts recognized and disclosed considering changes to the probability of additional losses and potential exposure; however, actual losses can and do vary from estimates for a variety of reasons including legal, arbitration or other third-party decisions; settlement discussions; evaluation of scope of damages; interpretation of regulatory or contractual terms; expected timing of future actions; and proportion of liability shared with other responsible parties. Estimated future costs related to contingencies are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes. For additional information on contingent liabilities, see the “Contingencies” section within “Capital Resources and Liquidity” and Note 9 .Income TaxesWe are subject to income taxation in numerous jurisdictions worldwide. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. In assessing the need for adjustments to existing valuation allowances, we consider all available positive and negative evidence. Positive evidence includes reversals of temporary differences, forecasts of future taxable income, assessment of future business assumptions and applicable tax planning strategies that are prudent and feasible. Negative evidence includes losses in recent years as well as the forecasts of future net income (loss) in the realizable period. In making our assessment regarding valuation allowances, we weigh the evidence based on objectivity. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions and the assessment of the effects of foreign taxes on our U.S. federal income taxes (particularly as related to prevailing oil and gas prices). See Note 15 .
We regularly assess and, if required, establish accruals for uncertain tax positions that could result from assessments of additional tax by taxing jurisdictions in countries where we operate. We recognize a tax benefit from an uncertain tax position when it is more likely than not the position will be sustained upon examination, based on the technical merits of the position. These accruals for uncertain tax positions are subject to a significant amount of judgment and are reviewed and adjusted on a periodic basis in light of changing facts and circumstances considering the progress of ongoing tax audits, court proceedings, changes in applicable tax laws, including tax case rulings and legislative guidance, or expiration of the applicable statute of limitations. See Note 15.
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Cautionary Statement for the Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, costs and plans, objectives of management for future operations, are forward-looking statements. Examples of forward-looking statements contained in this report include our expected production growth and outlook on the business environment generally, our expected capital budget and capital expenditures, and discussions concerning development or replacement of reserves and future dividends. You can often identify our forward-looking statements by the words “ ambition ,” “ anticipate ,” “ believe ,” “ budget ,” “ continue ,” “ could ,” “ effort ,” “ estimate ,” “ expect ,” “ forecast ,” “ goal ,” “ guidance ,” “ intend ,” “ may ,” “ objective ,” “ outlook ,” “ plan ,” “ potential ,” “ predict ,” “ projection ,” “ seek ,” “ should ,” “ target ,” “ will ,” “ would ” and similar expressions.
We based our forward-looking statements on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect or inaccurate, and involve risks and uncertainties we cannot predict. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors and uncertainties, including, but not limited to, the following:
• Effects of volatile commodity prices, including prolonged periods of low commodity prices, which may adversely impact our operating results and our ability to execute on our strategy and could result in recognition of impairment charges on our long-lived assets, leaseholds and nonconsolidated equity investments.
• Global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and gas, including changes as a result of any ongoing military conflict and the global response to such conflict; geopolitical tensions; security threats on facilities and infrastructure; global health crises; the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC and other producing countries; or the resulting company or third-party actions in response to such changes.• The potential for insufficient liquidity or other factors, such as those described herein, that could impact our ability to repurchase shares and declare and pay dividends, whether fixed or variable.
• Potential failures or delays in achieving expected reserve or production levels from existing and future oil and gas developments, including due to operating hazards, drilling risks and the inherent uncertainties in predicting reserves and reservoir performance.• Reductions in our reserve replacement rates, whether as a result of significant declines in commodity prices or otherwise.• Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.• Failure to progress or complete announced and future development plans related to constructing, modifying or operating E&P and LNG facilities, or unexpected changes in costs, inflationary pressures or technical equipment related to such plans.
• Significant operational or investment changes imposed by legislative and regulatory initiatives and international agreements addressing environmental concerns, including initiatives addressing the impact of global climate change, such as limiting or reducing GHG emissions; regulations concerning hydraulic fracturing, methane emissions, flaring or water disposal; and prohibitions on commodity exports.
• Broader societal attention to and efforts to address climate change may cause substantial investment in and increased adoption of competing or alternative energy sources.
• Risks, uncertainties and high costs that may prevent us from successfully executing on our Climate-related Risk Strategy.
• Lack or inadequacy of, or disruptions in, reliable transportation for our crude oil, bitumen, natural gas, LNG and NGLs.• Inability to timely obtain or maintain permits, including those necessary for construction, drilling and/or development, or inability to make capital expenditures required to maintain compliance with any necessary permits or applicable laws or regulations.• Potential disruption or interruption of our operations and any resulting consequences due to accidents; extraordinary weather events; supply chain disruptions; civil unrest; political events; war; terrorism; cybersecurity threats or information technology failures, constraints or disruptions.
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• Liability for remedial actions, including removal and reclamation obligations, under existing or future environmental regulations and litigation.
• Liability resulting from pending or future litigation or our failure to comply with applicable laws and regulations.
• General domestic and international economic, political and diplomatic developments, including deterioration of international trade relationships; the imposition of trade restrictions or tariffs relating to commodities and material or products (such as aluminum and steel) used in the operation of our business; expropriation of assets; changes in governmental policies relating to commodity pricing, including the imposition of price caps; sanctions; or other adverse regulations or taxation policies.
• Competition and consolidation in the oil and gas E&P industry, including competition for sources of supply, services, personnel and equipment.
• Any limitations on our access to capital or increase in our cost of capital or insurance, including as a result of illiquidity, changes or uncertainty in domestic or international financial markets, foreign currency exchange rate fluctuations or investment sentiment.
• Challenges or delays to our execution of, or successful implementation of any future asset dispositions or acquisitions we elect to pursue; potential disruption of our operations, including the diversion of management time and attention; our inability to realize anticipated cost savings or capital expenditure reductions; difficulties integrating acquired businesses and technologies; or other unanticipated changes.
• Our inability to deploy the net proceeds from any asset dispositions that are pending or that we elect to undertake in the future in the manner and timeframe we anticipate, if at all.
• The operation, financing and management of risks of our joint ventures.• The ability of our customers and other contractual counterparties to satisfy their obligations to us, including our ability to collect payments when due from the government of Venezuela or PDVSA.• Uncertainty as to the long-term value of our common stock.• The factors generally described in Part I—Item 1A in this 2025 Annual Report on Form 10-K and any additional risks described in our other filings with the SEC.
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