EXXON MOBIL CORP (XOM)

CIK: 0000034088. SIC: 2911 Petroleum Refining. Latest 10-K as of: 2026-02-18.

SIC breadcrumb: Manufacturing > Petroleum Refining And Related Industries > SIC 2911 Petroleum Refining

SEC company page: https://www.sec.gov/edgar/browse/?CIK=34088. Latest filing source: 0000034088-26-000045.

Selected Fundamentals

Metric	Value	Unit	FY	Filed
Revenue	276,692,000,000	USD	2021	2022-02-23
Net income	28,844,000,000	USD	2025	2026-02-18
Assets	448,980,000,000	USD	2025	2026-02-18

Macro Cross-References

CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
UNRATE - Unemployment Rate
FEDFUNDS - Federal Funds Effective Rate
CES0500000003 - Average Hourly Earnings of All Employees, Total Private
DFEDTARU - Federal Funds Target Range - Upper Limit
DFEDTARL - Federal Funds Target Range - Lower Limit
DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
PCEPI - Personal Consumption Expenditures: Chain-type Price Index
PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
PPIACO - Producer Price Index by Commodity: All Commodities
T10YIE - 10-Year Breakeven Inflation Rate
U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
PAYEMS - All Employees, Total Nonfarm
CIVPART - Labor Force Participation Rate
EMRATIO - Employment-Population Ratio
UNEMPLOY - Unemployed
CE16OV - Employment Level
ICSA - Initial Claims
JTSJOL - Job Openings: Total Nonfarm
JTSQUR - Quits: Total Nonfarm
GDPC1 - Real Gross Domestic Product
A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
INDPRO - Industrial Production: Total Index
TCU - Capacity Utilization: Total Index
HOUST - New Privately-Owned Housing Units Started: Total Units
PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
RSAFS - Advance Retail Sales: Retail Trade
PCE - Personal Consumption Expenditures
DSPIC96 - Real Disposable Personal Income
PSAVERT - Personal Saving Rate
M2SL - M2
BOPGSTB - U.S. International Trade in Goods and Services: Balance

Latest 10-K MD&A

Extracted from a later financial-section MD&A body after the formal Item 7 span was a short reference. Confidence: high. Filing date: 2026-02-18. Report date: 2025-12-31.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FORWARD-LOOKING STATEMENTS

Statements related to future events; projections; descriptions of strategic, operating, and financial plans and objectives; statements of future ambitions and plans; future earnings power; potential addressable markets; and other statements of future events or conditions are forward-looking statements. Similarly, discussion of roadmaps or future plans related to carbon capture, transportation and storage, hydrogen and ammonia, lower-emission fuels, direct air capture, ProxximaTM resin systems, carbon materials, low-carbon data centers, lithium, and other future plans to reduce emissions and emissions intensity of ExxonMobil, its affiliates, and third parties are dependent on future market factors, such as continued technological progress, stable policy support, and timely rule-making and permitting, and represent forward-looking statements.

Actual future results, including financial and operating performance; potential earnings, cash flow, dividends or shareholder returns, including the timing and amounts of share repurchases; total capital expenditures and mix, including allocations of capital to low-carbon and other new investments; realization and maintenance of structural cost reductions and efficiency gains, including the ability to offset inflationary pressure; plans to reduce future emissions and emissions intensity, including ambitions to reach Scope 1 and Scope 2 net zero from operated assets by 2050, to reach Scope 1 and 2 net zero in integrated Upstream Permian Basin unconventional operated assets by 2035, to eliminate routine flaring in-line with World Bank Zero Routine Flaring, to reach near-zero methane emissions from operated assets and other methane initiatives, and to meet ExxonMobil’s emission reduction plans and goals, divestment and start-up plans, and associated project plans as well as technology advances, including the timing and outcome of projects to capture, transport and store CO2, produce hydrogen and ammonia, produce lower-emission fuels, produce ProxximaTM resin systems, produce carbon materials, produce lithium, and use plastic waste as feedstock for advanced recycling; future debt levels and credit ratings; business and project plans, timing, costs, capacities and profitability; resource recoveries and production rates; and planned Denbury and Pioneer integrated benefits, could differ materially due to a number of factors.

These include global or regional changes or imbalances in the supply and demand for oil, natural gas, petrochemicals, and feedstocks and other market factors; economic conditions and seasonal fluctuations that impact prices, differentials, and volume/mix for our products; developments or changes in local, national, or international laws, regulations, taxes, trade sanctions, trade tariffs, or policies affecting our business, such as government policies supporting lower-carbon and new market investment opportunities, the punitive European taxes on the oil and gas sector and unequal support for different technological methods of emissions reduction or evolving, ambiguous, and unharmonized voluntary and mandatory standards or extraterritorial laws and regulations imposed by various jurisdictions related to sustainability and greenhouse gas reporting; timely granting of governmental permits, licenses, and certifications; uncertain impacts of deregulation on the legal and regulatory environment; changes in interest and exchange rates; variable impacts of trading activities on our margins and results each quarter; actions of co-venturers or partners, competitors, and commercial counterparties, including suppliers and customers; government actions in pursuit of national energy and security policies and priorities affecting our business; the outcome of commercial negotiations, including final agreed terms and conditions; the outcome of competitive bidding and project awards; the ability to access debt markets on favorable terms or at all; the occurrence, pace, rate of recovery and effects of public health crises; adoption of regulatory incentives consistent with law; reservoir performance and optimization, including variability and timing factors applicable to unconventional resources, the success of new unconventional technologies, and the ability of new technologies to improve recovery relative to competitors; the level, outcome, and timing of exploration and development projects and decisions to invest in future reserves and resources; timely completion of construction projects and commencement of start-up operations, including reliance on third-party suppliers and service providers; final management approval of future projects and any changes in the scope, terms, costs, or assumptions of such projects as approved; the actions of governments, non-governmental organizations, or other actors against our core business activities and acquisitions, divestitures or financing opportunities; war, civil unrest, armed hostilities, attacks against the Company or industry, and other geopolitical or security disturbances, including disruption of land or sea transportation routes or distribution or shipping channels; decoupling of economies, disruption, realignment, or breaking of current or historical trade or military alliances or global trade or supply chain networks; escalating geopolitical volatility, including regime changes; expropriations, seizures, or capacity, insurance, shipping, import or export limitations imposed directly or indirectly by governments or laws; opportunities for potential acquisitions, investments or divestments and satisfaction of applicable conditions to closing, including timely regulatory approvals; the capture of efficiencies within and between business lines and the ability to maintain near-term cost reductions as ongoing efficiencies without impairing our competitive positioning; unforeseen technical or operating disruptions or difficulties and unplanned maintenance; the development and competitiveness of alternative energy and emission reduction technologies; consumer preferences including willingness and ability to pay for reduced emission products; the results of research programs and the ability to bring new technologies to commercial scale on a cost-competitive basis; and other factors discussed under Item 1A.

Forward-looking and other statements regarding environmental and other sustainability efforts and aspirations are not an indication that these statements are material to investors or require disclosure in our filing with the SEC or any other regulatory authority. In addition, historical, current, and forward-looking environmental and other sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future, including future rule-making.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Energy demand models are forward-looking by nature and aim to replicate system dynamics of the global energy system, requiring simplifications. The reference to any scenario in this report, including any potential net-zero scenarios, does not imply ExxonMobil views any particular scenario as likely to occur. In addition, energy demand scenarios require assumptions on a variety of parameters. As such, the outcome of any given scenario using an energy demand model comes with a high degree of uncertainty. Third-party scenarios discussed in this report reflect the modeling assumptions and outputs of their respective authors, not ExxonMobil, and their use by ExxonMobil is not an endorsement by ExxonMobil of their underlying assumptions, likelihood, or probability. Investment decisions are made on the basis of ExxonMobil’s separate planning process. Any use of the modeling of a third-party organization within this report does not constitute or imply an endorsement by ExxonMobil of any or all of the positions or activities of such organization.

Actions needed to advance ExxonMobil’s 2030 greenhouse gas emission-reductions plans are incorporated into its medium-term business plans, which are updated annually. The reference case for planning beyond 2030 is based on ExxonMobil’s Global Outlook (Outlook) research and publication. The Outlook is reflective of the existing global policy environment and an assumption of increasing policy stringency and technology improvement to 2050. Current trends for policy stringency and development of lower-emission solutions are not yet on a pathway to achieve net-zero by 2050. As such, the Outlook does not project the degree of required future policy and technology advancement and deployment for the world, or ExxonMobil, to meet net zero by 2050. As future policies and technology advancements emerge, they will be incorporated into the Outlook, and ExxonMobil’s business plans will be updated accordingly. References to projects or opportunities may not reflect investment decisions made by ExxonMobil or its affiliates. Individual projects or opportunities may advance based on a number of factors, including availability of stable and supportive policy, permitting, technological advancement for cost-effective abatement, insights from the Corporate planning process, and alignment with our partners and other stakeholders. Capital investment guidance in lower-emission investments is based on our Corporate Plan; however, actual investment levels will be subject to the availability of the opportunity set, public policy support, and focused on returns.

The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports.

OVERVIEW

The following discussion and analysis of ExxonMobil’s financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Exxon Mobil Corporation. The Corporation’s accounting and financial reporting fairly reflect its integrated business model involving exploration for, and production of, crude oil and natural gas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals, and a wide variety of specialty products; and pursuit of lower-emission and other new business opportunities, including carbon capture and storage, hydrogen and ammonia, lower-emission fuels, ProxximaTM resin systems, carbon materials, low-carbon data centers, and lithium. ExxonMobil's reportable segments are Upstream, Energy Products, Chemical Products, and Specialty Products. Where applicable, ExxonMobil voluntarily discloses additional U.S., non-U.S., and regional splits to help investors better understand the Company's operations.

The Company is organized along three businesses – Upstream, Product Solutions, and Low Carbon Solutions, aligning along market-focused value chains. Product Solutions consists of Energy Products, Chemical Products, and Specialty Products. Low Carbon Solutions is included in Corporate and Financing as the business continues to mature through commercialization and deployment of technology. The businesses are supported by centralized service-delivery groups, including Global Projects, Technology and Engineering, Global Operations, Sustainability, Global Trading, Supply Chain, and Global Business Solutions.

ExxonMobil, with its resource base, financial strength, disciplined investment approach, and technology portfolio, is well-positioned to participate in substantial investments to develop new supplies of reliable and affordable lower-emission energy and other critical products. The Company’s integrated business model, with significant investments in the Upstream, Energy Products, Chemical Products, and Specialty Products segments and Low Carbon Solutions businesses, generally reduces the Corporation’s risk from changes in commodity prices. While commodity prices depend on supply and demand and may be volatile on a short-term basis, ExxonMobil’s investment decisions are grounded on fundamentals reflected in our long-term business outlook, and use a disciplined approach in selecting and pursuing the most attractive investment opportunities which target a low cost of supply to ensure long-term competitiveness. The annual Corporate Plan process establishes the economic assumptions used for evaluating investments and sets operating and capital objectives. The Global Outlook (Outlook), developed annually, is the foundation for the Corporate Plan assumptions. Price ranges for crude oil and natural gas, including price differentials, refinery and chemical margins, volumes, development and operating costs, including greenhouse gas emissions pricing, and foreign currency exchange rates are part of the Corporate Plan assumptions developed annually. Corporate Plan volume projections are based on individual field production profiles, which are also updated at least annually. Major investment opportunities are evaluated over a range of potential market conditions. All major investments are reappraised to ensure we learn from our decisions, and the development and execution of the project. Lessons learned are incorporated in future projects.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

BUSINESS ENVIRONMENT

Long-Term Business Outlook

ExxonMobil’s business planning is underpinned by a deep understanding of long-term market fundamentals. These fundamentals include supply and demand trends; the scale and variety of energy needs worldwide; capability, practicality, and affordability of energy alternatives, including lower-carbon solutions; greenhouse gas emission-reduction technologies; and relevant government policies. The Outlook considers these fundamentals to form the basis for the Company’s long-term business planning, investment decisions, and research programs. The Outlook reflects the Company’s view of global energy demand and supply through 2050. It is a projection based on current trends in technology, government policies, consumer preferences, geopolitics, and economic development.

In addition, ExxonMobil considers a range of scenarios, including remote scenarios, to help inform perspective of the future and enhance strategic thinking over time. Included in the range of these scenarios are the Intergovernmental Panel on Climate Change (IPCC) Likely Below 2°C scenarios and three scenarios from the International Energy Agency (IEA): IEA Stated Policies Scenario (STEPS; 2025 World Energy Outlook (WEO)), which reflects a sector-by-sector assessment of current policy in place and those announced by governments; IEA Announced Pledges Scenario (APS; 2024 WEO), which reflects aspirational government targets met on time and in full; and IEA Net Zero Emissions by 2050 Scenario (NZE; 2025 WEO), which the IEA describes as highly ambitious and challenging, acknowledging that society is not currently on the IEA NZE pathway. No single transition pathway can be reasonably predicted, given the wide range of uncertainties. Key unknowns include yet-to-be-developed or changes in developed government policies, market conditions, and advances in technology that may influence the cost, pace, and potential availability of certain pathways. Scenarios that employ a full complement of technology options are likely to provide the most economically efficient pathways.

Using our own experts and third-party sources, we monitor a variety of signposts that may indicate a potential shift in the energy transition. For example, the regional pace of the transition could be influenced by the cost of new technologies compared to existing or alternative energy sources. To effectively evaluate the pace of change, ExxonMobil uses many scenarios to help identify signposts that provide leading indicators of future developments and allow for timely adjustments to future versions of the Outlook.

Developing countries projected to drive energy demand growth

Primary energy - Quadrillion Btu

Source: ExxonMobil 2025 Global Outlook

By 2050, the world’s population is projected to be around 9.7 billion people, or nearly 2 billion more than in 2024. Coincident with this population increase, the Outlook projects worldwide economic growth to average approximately 2.5 percent per year, with economic output nearly doubling by 2050 compared to 2024. As economies and populations grow, and as living standards improve for billions of people, the need for energy is expected to continue to rise. Even with significant efficiency gains, global energy demand is projected to rise by over 10 percent from 2024 to 2050. This increase in energy demand is expected to be driven by developing countries (i.e., those that are not member nations of the Organization for Economic Co-operation and Development (OECD)). By contrast, energy use in developed nations is expected to decline by more than 10 percent as efficiency improves.

As expanding prosperity drives global energy demand higher, increasing use of energy-efficient technologies and practices as well as lower-emission products will continue to help significantly reduce energy consumption and CO2 emissions per unit of economic output over time. Substantial efficiency gains are likely in all key aspects of the world’s economy through 2050, affecting energy requirements for power generation, transportation, industrial applications, and residential and commercial needs.

Under our Outlook, global electricity demand is expected to increase more than 70 percent from 2024 to 2050, with developing countries likely to account for approximately 80 percent of the increase. Consistent with this projection, power generation is expected to remain the largest and fastest growing major segment of global primary energy demand, supported by a wide variety of energy sources. The share of coal-fired generation is expected to decline substantially to approximately 15 percent of the world’s electricity in 2050, versus approximately 35 percent in 2024, in part due to policies to improve air quality as well as reduce greenhouse gas emissions to address risks related to climate change. From 2024 to 2050, the amount of electricity supplied using natural gas, nuclear power, and renewables is expected to more than double, accounting for the entire growth in electricity supplies and offsetting the reduction of coal. Electricity from wind and solar is expected to increase nearly 400 percent, helping total renewables (including other sources, e.g., hydropower) to account for approximately 90 percent of the increase in electricity supplies through 2050. Total renewables are expected to reach over 50 percent of global electricity supplies by 2050. Natural gas and nuclear are expected to be about 20 percent and 10 percent, respectively, of global electricity supplies by 2050. Supplies of electricity by energy type will reflect significant differences across regions reflecting a wide range of factors, including the cost and availability of various energy supplies and policy developments.

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Energy for transportation - including cars, trucks, ships, trains, and airplanes - is expected to increase by nearly 25 percent from 2024 to 2050. Transportation energy demand is expected to account for over 50 percent of the growth in liquid fuels demand worldwide over this period. Light-duty vehicle demand for liquid fuels is projected to have peaked this decade, and then decline to levels seen in the early-2010s by 2050, as the impact of better fuel economy and significant growth in electric cars, led by China, Europe, and the United States, work to offset growth in the worldwide car fleet of about 60 percent. By 2050, light-duty vehicles are expected to account for around 20 percent of global liquid fuels demand. During the same time period, nearly all the world’s commercial transportation fleets are expected to continue to run on liquid fuels, including biofuels, which are expected to be widely available and offer practical advantages in providing a large quantity of energy in small volumes.

Almost half of the world’s energy use is dedicated to industrial activity. As the global middle class continues to grow, demand for durable products, appliances, and consumable goods will increase. Industry uses energy products both as a fuel and as a feedstock for chemicals, asphalt, lubricants, waxes, and other specialty products. The Outlook anticipates technology advances, as well as the increasing shift toward cleaner forms of energy, such as electricity and natural gas, with coal declining. Demand for oil will continue to grow as a feedstock for industry.

As populations grow and prosperity rises, more energy will be needed to power homes, offices, schools, shopping centers, hospitals, et cetera Combined residential and commercial energy demand is projected to rise by around 15 percent through 2050. Led by the growing economies of developing nations, average worldwide household electricity use is expected to rise more than 60 percent between 2024 and 2050.

Liquid fuels provide the largest share of global energy supplies today reflecting broad-based availability, affordability, ease of transportation, and fitness as a practical solution to meet a wide variety of needs. By 2050, global demand for liquid fuels is projected to grow to nearly 115 million oil-equivalent barrels per day, an increase of about 10 percent from 2024. The non-OECD share of global liquid fuels demand is expected to increase to about 70 percent by 2050, as liquid fuels demand in the OECD is expected to decline by more than 25 percent. Much of the global liquid fuels demand today is met by crude production from conventional sources; these supplies will remain important, and significant development activity is expected to offset much of the natural declines from these fields. At the same time, a variety of supply sources - including tight oil, deepwater, oil sands, natural gas liquids, and biofuels - are expected to grow to help meet rising demand. Timely investments will remain critical to meeting global needs with reliable and affordable supplies.

Natural gas is a lower-emission, versatile, and practical fuel for a wide variety of applications. Global natural gas demand is expected to rise nearly 20 percent from 2024 to 2050, with approximately 70 percent of that increase coming from the Asia Pacific region. Significant growth in supplies of unconventional gas - the natural gas found in shale and other tight rock formations - will help meet these needs. In total, over 40 percent of the growth in natural gas supplies is expected to come from unconventional sources. At the same time, conventionally-produced natural gas is likely to remain the cornerstone of global supply, meeting around two-thirds of worldwide demand in 2050. LNG trade will expand significantly, meeting about 75 percent of the increase in global demand growth, with much of this supply expected to help meet rising demand in the Asia Pacific region.

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Oil and natural gas projected to play a critical role in the global energy mix

Primary energy - Quadrillion Btu

Percent of primary energy

Source: ExxonMobil 2025 Global Outlook

* Electricity and hydrogen are secondary energies derived from the primary energies shown.

**Includes biomass, biofuels, hydropower, and geothermal.

The world’s energy mix is highly diverse and will remain so through 2050. Oil is expected to continue as the largest source of energy with its share remaining close to 30 percent in 2050. Coal and natural gas are the next largest sources of energy today, with the share of natural gas growing to more than 25 percent by 2050, while the share of coal falls to about half that of natural gas. Nuclear power is projected to grow, as many nations are likely to expand nuclear capacity to address rising electricity needs as well as energy security and environmental issues. Total renewable energy is expected to exceed 20 percent of global energy by 2050, with other renewables (e.g., biomass, hydropower, geothermal) contributing a combined share of more than 10 percent. Total energy supplied from wind and solar is expected to increase rapidly, growing nearly 350 percent from 2024 to 2050, when they are projected to be greater than 10 percent of the world energy mix.

Decarbonization of industrial activities will require a suite of lower-carbon technologies supported by stable policies. Lower-emission fuels, hydrogen-based fuels, and carbon capture and storage are three key lower-carbon solutions needed to support a lower-emission future, in addition to wind and solar. Along with electrification, lower-emission fuels are expected to play an important role in decarbonization of the transportation sector, particularly in hard-to-decarbonize areas, such as aviation. Hydrogen will be a key enabler replacing traditional furnace fuel to decarbonize the industrial sector. Hydrogen and hydrogen-based fuels like ammonia are also expected to make inroads into commercial transportation as technology improves to lower its cost and policy develops to support the needed infrastructure development. Carbon capture and storage on its own, or in combination with hydrogen production, is among the few proven technologies that could enable CO2 emission reductions from high-emitting and hard-to-decarbonize sectors such as power generation and heavy industries, including manufacturing, refining, and petrochemicals.

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Significant oil and natural gas investment needed to meet projected global demand

Projected global oil supply and demand

Projected global natural gas supply and demand

Million barrels per day

Billion cubic feet per day

Excludes biofuels; IEA STEPS and IEA NZE Source: IEA WEO 2025; IEA APS Source: IEA WEO 2024; Global Outlook Source: ExxonMobil 2025 Global Outlook; IPCC Likely Below 2°C Average Source: IPCC AR6 Scenarios Database hosted by IIASA release 1.0 average IPCC C3:311 "Likely below 2°C" scenarios used; decline rates based on 10-yr Compound Annual Grown Rate (CAGR)

Excludes flaring; IEA STEPS and IEA NZE Source: IEA WEO 2025; IEA APS Source: IEA WEO 2024; Global Outlook Source: ExxonMobil 2025 Global Outlook; IPCC Likely Below 2°C Average Source: IPCC AR6 Scenarios Database hosted by IIASA release 1.0 average IPCC C3: 311 "Likely below 2°C" scenarios used; decline rates based on 10-yr CAGR

Our Outlook projects that oil demand will remain above 100 million barrels per day to 2050. Even under the average of IPCC Likely Below 2°C scenarios, oil demand still comes to 65 million barrels per day in 2050 – about two thirds of current consumption.

Our Outlook shows oil production declines at a rate of about 15 percent per year. At that rate, in the absence of continued investment, by 2030 oil supplies would fall from 100 million barrels per day to less than 30 million barrels, more than 70 million barrels per day short of what is needed to meet demand. Limiting investment to only existing fields would slow the decline to about 4 percent; however, this would still be well below the oil demand in the average of IPCC Likely Below 2°C scenarios.

To meet projected demand, the Corporation anticipates that the world’s available oil and gas resource base will grow, not only from new discoveries, but also from increases in previously discovered fields. Technology will underpin these increases. The investments to develop and supply resources to meet global demand through 2050 will be significant and would be needed to meet even rapidly declining demand for oil and gas envisioned in aggressive decarbonization scenarios.

International accords and underlying regional and national regulations covering greenhouse gas emissions continue to evolve with uncertain timing and outcome, making it difficult to predict their business impact. For many years, the Corporation has taken into account policies established to reduce energy-related greenhouse gas emissions in its long-term Outlook. The climate accord reached at the 2015 Conference of the Parties (COP 21) in Paris set many new goals, and many related policies are still emerging. Our Outlook reflects an environment with increasingly stringent climate policies and seeks to identify potential impacts of these climate-related government policies, which often target specific sectors. For purposes of the Outlook, a proxy cost on energy-related CO2 emissions is assumed, based on regional considerations and relative levels of economic development, and by 2050, reaches up to $150 per metric ton for OECD nations and up to $100 per metric ton for non-OECD nations. As people and nations look for ways to reduce risks of global climate change, they will continue to need practical solutions that do not jeopardize the affordability or reliability of the energy they need. The Corporation continues to monitor the updates to the Nationally Determined Contributions (NDCs) that are submitted by nations that are signatories to the Paris Agreement, as well as other policy developments in light of net-zero ambitions formulated by some nations.

The information provided in the Outlook includes ExxonMobil’s internal estimates and projections based upon internal data and analyses as well as publicly available information from external sources including the International Energy Agency.

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Progress Reducing Emissions

The Corporation’s strategy seeks to maximize the advantages of our scale, business integration, leading technology, execution excellence, and our people to build globally competitive businesses that lead industry in earnings and cash flow growth across a range of future scenarios. We strive to play a leading role, regardless of how an energy transition unfolds. Across our portfolio of opportunities, we retain investment flexibility to maximize shareholder value. In 2022, we announced our ambition to achieve net-zero Scope 1 and 2 greenhouse gas emissions in our operated assets by 2050, with advancements in technology and clear, consistent, stable, and effective government policies. Society's progress continues to lag in these areas. Without supportive policies and the innovations they drive, net zero 2050 will remain out of reach — for society and ExxonMobil. Our net-zero ambition is backed by a comprehensive approach centered on detailed emission-reduction roadmaps for our major operated assets that were completed in 2022. The roadmaps build on the Company’s 2030 emission-intensity reduction plans. We continue to update the roadmaps, including to account for portfolio changes, to reflect technology and policy, and to account for the many potential pathways and pace of an energy transition. Our plans include reaching net-zero Scope 1 and 2 emissions in our integrated Permian Basin operated assets by 2035, including Pioneer assets acquired in 2024. By 2030, we plan to reduce emissions in our combined Permian operations by more than the equivalent of achieving net-zero Scope 1 and 2 emissions in our operated heritage ExxonMobil assets.

Compared to 2016 levels, our 2030 plans are expected to drive the following reductions:

•20-30 percent reduction in corporate-wide greenhouse gas intensity;

•70-80 percent reduction in corporate-wide methane intensity;

•40-50 percent reduction in upstream greenhouse gas intensity; and

•60-70 percent reduction in corporate-wide flaring intensity.

As of year-end 2025, we are exceeding our 2030 plans across the portfolio, having already achieved our plans for reducing Corporate greenhouse gas and flaring intensity. We expect to reach the plan for methane intensity reductions later this year.

Our emission-reduction plans and 2050 net-zero ambition cover Scope 1 and 2 emissions from assets we operate.

The Corporation plans to continue to pursue advantaged growth opportunities and lower-emission investments. These investments are targeted at reducing emissions in the Company’s operations as well as reducing the emissions of other companies. At this early stage, stable and supportive policy remains critical to enable emissions reductions, advance technology, and drive scale to improve costs.

ExxonMobil’s Low Carbon Solutions business is working with the Product Solutions and Upstream businesses to grow a pipeline of emission-reduction opportunities in carbon capture and storage, hydrogen and ammonia, lower-emission fuels, ProxximaTM resin systems, carbon materials, and low-carbon data centers, as well as lithium to supply the global battery and electric vehicle markets. Our customers, many governments, and strategic partners recognize our combination of experience, skills, and capabilities that have the potential to help reduce emissions for ourselves and others. For example, on the U.S. Gulf Coast, we see an opportunity to grow a carbon capture and storage business that will enable industrial customers to reduce their emissions. Stable policy support, along with technology advancements and the development of market-driven mechanisms, will continue to be important to the development and deployment of lower-emission solutions.

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Recent Business Environment

During 2025, the price of crude oil remained near the middle of the pre-COVID 10-year range (2010-2019) as global markets remained broadly balanced. Record crude demand was met by increasing industry supply, resulting in modestly lower prices. Natural gas prices rose to the top end of the 10-year range due to robust demand. Industry refining margins improved in 2025, supported by record full-year demand and an increase in supply disruptions driving higher margins. Despite record demand, global oversupply resulted in Chemical margins remaining at bottom-of-cycle.

During 2025, the U.S. announced a variety of trade-related actions, including the imposition of tariffs on imports from several countries. In response, many countries announced their own retaliatory tariffs. Despite the current uncertainty as to what effects these actions will ultimately have on the Corporation, our suppliers and our customers, as well as on the overall macroeconomic environment, we do not anticipate any material near-term financial impacts.

The Corporation closely monitors market trends and works to mitigate both operating and capital cost impacts in all price environments. Strategic changes implemented over the past several years enabled the Corporation to capture $15.1 billion of structural cost savings(1) versus 2019, including $3 billion of savings during 2025, through increased operational efficiencies, workforce reductions, divestment-related reductions, and other cost-saving measures. The Company sees additional opportunities in areas such as centralization of activities, system implementations, continued improvement of maintenance and turnarounds, and simplified business processes. These savings are key drivers to reduce our structural costs by $20 billion between 2019 and 2030, thereby improving the earnings power of the Corporation.

(1) Refer to Frequently Used Terms for definition of structural cost savings.

Transportation of Kazakhstan Production

The Corporation holds a 25 percent interest in Tengizchevroil, LLP (TCO), which operates the Tengiz and Korolev oil fields in Kazakhstan, and a 16.8 percent working interest in the Kashagan field in Kazakhstan. Oil production from those operations is exported primarily through the Caspian Pipeline Consortium (CPC), in which the Corporation holds a 7.5 percent interest. CPC traverses parts of Kazakhstan and Russia to tanker-loading facilities on the Russian coast of the Black Sea. In the event geopolitical issues escalate in the region, including ongoing military conflict, it is possible that the transportation of Kazakhstan oil through the CPC pipeline could be disrupted, curtailed, temporarily suspended, or otherwise restricted. In such a case, the Corporation could experience a loss of cash flows of uncertain duration from its operations in Kazakhstan. For reference, after-tax earnings related to the Corporation’s interests in Kazakhstan in 2025 were approximately $1.1 billion, and its share of combined oil and gas production was approximately 320 thousand oil-equivalent barrels per day.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

BUSINESS RESULTS

Upstream

ExxonMobil has a diverse growth portfolio of exploration and development opportunities, which allows the Corporation to be selective in our investments, maximizing shareholder value, and mitigating political and technical risks. ExxonMobil’s competitive strengths enable the Upstream’s business strategy, which is focused on developing an industry-leading portfolio underpinned by advantaged growth projects, applying ExxonMobil’s technology to enhance value and improve development efficiency, and leveraging the unique capabilities of the Company's Global Projects organization to deliver projects on time and in line with budgets.

The Upstream capital program is focused on low cost-of-supply opportunities. ExxonMobil has a strong pipeline of development projects, including continued growth in Guyana and the Permian Basin, as well as LNG expansion opportunities in Qatar, Mozambique, Papua New Guinea, and the United States. In 2025, Upstream production averaged 4.7 million oil-equivalent barrels per day (Moebd), our highest production in over 40 years. As future development projects and drilling activities bring new production online, the Corporation expects a shift in the geographic mix and in the type of opportunities from which volumes are produced. Based on the current investment plans, the proportion of oil-equivalent production from the Americas is generally expected to increase over the next several years. Currently about two thirds of the Corporation's global production comes from Permian, Guyana, and LNG resources. This proportion is generally expected to grow.

The Corporation anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes typically vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, the impact of fiscal and commercial terms, asset sales, weather events, price effects on production sharing contracts, changes in the amount and timing of capital investments that may vary depending on the oil and gas price environment, international trade patterns and relations, and other factors described in Item 1A.

In 2025, crude prices remained within the 10-year historical range (2010-2019), while robust demand helped to move natural gas price above the top of the 10-year range. ExxonMobil believes prices over the long term will continue to be driven by market supply and demand, with the demand side largely being a function of general economic activities, levels of prosperity, technology advances, consumer preference, and government policies. On the supply side, prices may be significantly impacted by political events, the actions of OPEC or OPEC+ and other large government resource owners, alternative energy sources, and other factors.

Key Recent Events

Guyana: Liza Destiny, Liza Unity and Prosperity floating production, storage and offloading (FPSO) vessels continued to produce above investment basis capacity in 2025. Yellowtail entered service in August and progressed to ramp up throughout the fourth quarter achieving an average gross production of 240 kbd. The combined gross production from the four operating vessels exceeded 870 kbd in the fourth quarter of 2025. With start-up of a fourth vessel, Guyana achieved record annual production in 2025 of 715 kbd. Uaru, and Whiptail, the fifth and sixth developments on the Stabroek Block, respectively, are progressing on schedule and each has an investment basis capacity of approximately 250 kbd. In September 2025, ExxonMobil made a final investment decision for the Hammerhead development, after receiving the required regulatory approvals from the government of Guyana; Hammerhead is anticipated to come online in 2029. We anticipate eight FPSO vessels will be in operation on the Stabroek Block by year-end 2030.

Permian: ExxonMobil delivered strong and efficient growth in Permian production volumes in 2025. Total production volumes averaged a record 1.6 Moebd in 2025, approximately 0.4 Moebd higher than the previous year. ExxonMobil operations continue to deliver industry-leading capital efficiency and cost performance by leveraging scale, integration, and technology. Examples include deploying ExxonMobil cube design and proprietary lightweight proppant as well as leading capabilities and technology in drilling and completions. ExxonMobil expects to increase production in the Permian Basin to approximately 2.5 Moebd by 2030. ExxonMobil remains on track to achieve Scope 1 and 2 net zero greenhouse gas emissions in the integrated Permian Basin operated assets by 2035.

LNG: ExxonMobil continued work on LNG growth projects in 2025. In Papua New Guinea (PNG), the Papua LNG project has been optimizing the development plan and enhancing project cost competitiveness. Force majeure was lifted in Mozambique, as the Rovuma LNG project continues with the front-end engineering and design stage, in support of a final investment decision in 2026 to develop the Area 4 offshore gas resources. Mechanical completion was achieved for the Golden Pass LNG project, with expected first LNG production in the first quarter of 2026.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Upstream Financial Results

(millions of dollars)

2025

2024

2023

Earnings (loss) (U.S. GAAP)

United States

5,063

6,426

4,202

Non-U.S.

16,291

18,964

17,106

Total

21,354

25,390

21,308

Identified Items (1)

United States

(471)

(360)

(1,489)

Non-U.S.

(422)

575

(812)

Total

(893)

215

(2,301)

Earnings (loss) excluding Identified Items (1) (Non-GAAP)

United States

5,534

6,786

5,691

Non-U.S.

16,713

18,389

17,918

Total

22,247

25,175

23,609

2025 Upstream Earnings Driver Analysis (1)

(millions of dollars)

Price – Lower realizations decreased earnings by $6.1 billion, primarily driven by lower crude prices as record demand was more than offset by increased industry supply.

Advantaged Volume Growth – Increased earnings by $1.9 billion, mainly driven by record production in Permian and Guyana.

Base Volume – Decreased earnings by $0.7 billion as a result of non-strategic asset divestments.

Structural Cost Savings (1) – Increased earnings by $1.4 billion.

Expenses – Decreased earnings by $0.6 billion, primarily higher depreciation from the Tengiz expansion.

Other – Increased earnings by $0.6 billion, mainly driven by favorable tax and foreign exchange impacts.

Timing Effects – Favorable timing effects from derivatives mark-to-market impacts increased earnings by $0.6 billion.

Identified Items (1) – 2024 $0.2 billion gain mainly due to Argentina divestment, partly offset by Nigeria divestment and U.S. impairment; 2025 $(0.9) billion loss mainly due to asset impairments.

(1) Refer to Frequently Used Terms for definition of Structural Cost Savings, Identified Items, and Earnings (loss) excluding Identified Items.

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2024 Upstream Earnings Driver Analysis (1)

(millions of dollars)

Price – Price impacts decreased earnings by $1.3 billion, driven by lower gas realizations.

Advantaged Volume Growth – Higher volumes from advantaged assets increased earnings by $3.8 billion, as a result of record production in Permian, driven by the Pioneer acquisition and growth in the heritage Permian (2), and record production in Guyana driven by the Prosperity FPSO start-up.

Base Volume – Divestments of non-strategic assets and entitlements decreased earnings by $0.8 billion.

Structural Cost Savings (1) – Increased earnings by $0.8 billion.

Expenses – Higher expenses decreased earnings by $1.4 billion, primarily from higher depreciation (non-cash).

Other – All other items increased earnings by $0.1 billion, mainly driven by favorable impacts from divestments, partially offset by unfavorable tax and foreign exchange impacts.

Timing Effects – Less unfavorable timing effects from derivatives mark-to-market impacts increased earnings by $0.3 billion.

Identified Items (1) – 2023 $(2.3) billion loss primarily due to the impairment of the idled Santa Ynez Unit assets and associated facilities in California; 2024 $0.2 billion gain mainly due to Argentina divestment, partly offset by Nigeria divestment and U.S. impairment.

(1) Refer to Frequently Used Terms for definition of Structural Cost Savings, Identified Items, and Earnings (loss) excluding Identified Items.

(2) Heritage Permian Basin assets exclude assets acquired as part of the acquisition of Pioneer that closed May 3, 2024.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Upstream Operational Results

2025

2024

2023

Net production of crude oil, natural gas liquids, bitumen and synthetic oil

(thousands of barrels daily)

United States

1,522

1,248

803

Canada/Other Americas

835

784

664

Europe

Africa

142

209

221

Asia

800

713

721

Australia/Oceania

Worldwide

3,329

2,987

2,449

Net natural gas production available for sale

(millions of cubic feet daily)

United States

3,364

2,887

2,311

Canada/Other Americas

101

Europe

299

352

414

Africa

114

152

125

Asia

3,354

3,322

3,490

Australia/Oceania

1,283

1,264

1,298

Worldwide

8,442

8,078

7,734

Oil-equivalent production (1)

(thousands of oil-equivalent barrels daily)

4,736

4,333

3,738

(1) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.

Upstream Additional Information

(thousands of barrels daily)

2025

2024

Volumes Reconciliation (Oil-equivalent production) (1)

Prior Year

4,333

3,738

Entitlements - Net Interest

(33)

(13)

Entitlements - Price / Spend / Other

(23)

Government Mandates

(1)

Divestments

(133)

(63)

Growth / Other

525

685

Current Year

4,736

4,333

(1) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.

2025 versus 2024

2025 production of 4.7 million oil-equivalent barrels per day increased 403 thousand barrels per day from 2024. Permian reached 1.6 million net oil-equivalent barrels per day and Guyana production exceeded 700 thousand gross oil-equivalent barrels per day, more than offsetting impacts from divestments and entitlements. Excluding the impacts from entitlements, divestments, and government-mandated curtailments, net production grew by 525 thousand oil-equivalent barrels per day.

2024 versus 2023

2024 production of 4.3 million oil-equivalent barrels per day increased 595 thousand barrels per day from 2023. Permian and Guyana production grew by 680 thousand oil-equivalent barrels per day, more than offsetting impacts from divestments and entitlements. Excluding the impacts from entitlements, divestments, and government-mandated curtailments, net production grew by 685 thousand oil-equivalent barrels per day.

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Listed below are descriptions of ExxonMobil’s volumes reconciliation drivers, which are provided to facilitate understanding of the terms.

Entitlements - Net Interest are changes to ExxonMobil’s share of production volumes caused by non-operational changes to volume-determining drivers. These drivers consist of net interest changes specified in Production Sharing Contracts (PSCs), which typically occur when cumulative investment returns or production volumes achieve defined thresholds, changes in equity upon achieving pay-out in partner investment carry situations, equity redeterminations as specified in venture agreements, or as a result of the termination or expiry of a concession. Once a net interest change has occurred, it typically will not be reversed by subsequent events, such as lower crude oil prices.

Entitlements - Price, Spend and Other are changes to ExxonMobil’s share of production volumes resulting from temporary changes to non-operational volume-determining drivers. These drivers include changes in oil and gas prices or spending levels from one period to another. According to the terms of contractual arrangements or government royalty regimes, price or spending variability can increase or decrease royalty burdens and/or volumes attributable to ExxonMobil. For example, at higher prices, fewer barrels are required for ExxonMobil to recover its costs. These effects generally vary from period to period with field spending patterns or market prices for oil and natural gas. Such drivers can also include other temporary changes in net interest as dictated by specific provisions in production agreements.

Government Mandates are changes to ExxonMobil's sustainable production levels as a result of production limits or sanctions imposed by governments.

Divestments are reductions in ExxonMobil’s production arising from commercial arrangements to fully or partially reduce equity in a field or asset in exchange for financial or other economic consideration.

Growth and Other drivers comprise all other operational and non-operational drivers not covered by the above definitions that may affect volumes attributable to ExxonMobil. Such drivers include, but are not limited to, production enhancements from project and work program activities, acquisitions including additions from asset exchanges, downtime, market demand, natural field decline, and any fiscal or commercial terms that do not affect entitlements.

Energy Products

ExxonMobil's Energy Products is one of the largest, most integrated businesses of its kind among international oil companies, with significant representation across the entire fuels value chain, including refining, logistics, trading, and marketing. This segment includes the fuels, aromatics, and NGL value chains, as well as catalysts and licensing.

With the largest refining footprint among international oil companies, ExxonMobil’s Energy Products earnings are closely tied to industry refining margins. Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery pays for its raw materials and the market prices for the products produced. Crude oil and many products are widely traded with published prices, including those quoted on multiple exchanges around the world (e.g., New York Mercantile Exchange and Intercontinental Exchange). Prices for these commodities are determined by the global marketplace and are influenced by many factors, including global and regional supply/demand balances, inventory levels, industry refinery operations, import/export balances, currency fluctuations, seasonal demand, weather, and geopolitical considerations. While industry refining margins significantly impact Energy Products earnings, strong operational performance, product mix optimization, and disciplined cost control are also critical to strong financial performance.

In 2025, refining margins increased from the prior year on record demand, but remained within the 10-year historical range (2010-2019). Refining margins are expected to remain volatile with changes in global factors, including geopolitical developments; demand growth; recession fears; inventory levels; and refining capacity utilization, additions, and rationalizations.

Key Recent Events

Strathcona Renewable Diesel project: Started up the project at the Strathcona refinery, which is designed to use low-carbon hydrogen, locally-sourced and grown feedstocks, and our proprietary catalyst to produce renewable diesel.

Fawley Hydrofiner project: Started up the project at the Fawley site to increase production of ultra-low sulfur diesel and reduce production of other products, including high-sulfur distillates.

France divestment: In November 2025, ExxonMobil completed the divestments of Esso Société Anonyme Française SA and ExxonMobil Chemical France SAS, including the refinery and related assets.

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Energy Products Financial Results

(millions of dollars)

2025

2024

2023

Earnings (loss) (U.S. GAAP)

United States

2,992

2,099

6,123

Non-U.S.

4,431

1,934

6,019

Total

7,423

4,033

12,142

Identified Items (1)

United States

(118)

(34)

192

Non-U.S.

601

113

(48)

Total

483

144

Earnings (loss) excluding Identified Items (1) (Non-GAAP)

United States

3,110

2,133

5,931

Non-U.S.

3,830

1,821

6,067

Total

6,940

3,954

11,998

Due to rounding, numbers presented may not add up precisely to the totals indicated.

2025 Energy Products Earnings Driver Analysis (1)

(millions of dollars)

Margin – Increased earnings by $1.8 billion, mainly driven by robust demand and supply disruptions.

Advantaged Volume Growth – Higher volumes from advantaged projects growth increased earnings by $0.2 billion.

Base Volume – Higher volumes driven by lower scheduled maintenance increased earnings by $0.4 billion.

Structural Cost Savings (1) – Increased earnings by $0.6 billion.

Expenses – Decreased earnings by $0.5 billion, mainly driven by growth projects.

Other – Increased earnings by $0.2 billion mainly from favorable year-end inventory effects.

Timing Effects – Favorable timing effects from derivatives mark-to-market impacts increased earnings by $0.4 billion.

Identified Items (1) – 2024 $0.1 billion gain; 2025 $0.5 billion gain mainly driven by asset sales.

(1) Refer to Frequently Used Terms for definition of Structural Cost Savings, Identified Items, and Earnings (loss) excluding Identified Items.

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2024 Energy Products Earnings Driver Analysis (1)

(millions of dollars)

Margin – Significantly weaker industry refining margins decreased earnings by $6.3 billion. Margins declined from historically high levels as increased supply from industry capacity additions outpaced record global demand.

Advantaged Volume Growth – Higher volumes from advantaged projects, increased earnings by $0.1 billion.

Base Volume – Lower base volumes decreased earnings by $1.2 billion driven by scheduled maintenance and divestments.

Structural Cost Savings (1) – Increased earnings by $0.6 billion.

Expenses – Higher expenses related to scheduled turnarounds and maintenance, and advantaged project spend decreased earnings by $1.0 billion.

Other – All other items, mainly unfavorable tax and forex impacts, decreased earnings by $0.3 billion.

Timing Effects – Decreased earnings by $10 million.

Identified Items (1) – 2023 $0.1 billion gain driven by favorable tax effects partially offset by additional European taxes on the energy sector; 2024 $0.1 billion gain.

(1) Refer to Frequently Used Terms for definition of Structural Cost Savings, Identified Items, and Earnings (loss) excluding Identified Items.

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Energy Products Operational Results

(thousands of barrels daily)

2025

2024

2023

Refinery throughput

United States

1,927

1,865

1,848

Canada

402

399

407

Europe

1,002

1,039

1,166

Asia Pacific

460

432

498

Other

188

165

149

Worldwide

3,979

3,900

4,068

Energy Products sales (1)

United States

2,852

2,722

2,633

Non-U.S.

2,740

2,696

2,828

Worldwide

5,593

5,418

5,461

Gasoline, naphthas

2,290

2,251

2,288

Heating oils, kerosene, diesel

1,791

1,769

1,795

Aviation fuels

383

355

336

Heavy fuels

220

200

214

Other energy products

910

844

829

Worldwide

5,593

5,418

5,461

(1) Data reported net of purchases/sales contracts with the same counterparty.

Due to rounding, numbers presented may not add up precisely to the totals indicated.

Chemical Products

ExxonMobil is a leading global manufacturer and marketer of petrochemicals that support modern living. Chemical Products help meet society’s essential needs by providing a wide range of innovative products efficiently and responsibly. The Company is uniquely positioned with a combination of industry-leading scale, integration, and proprietary technology, which are fundamental to producing affordable products that are more sustainable, use less material, save energy, and reduce waste. These competitive advantages are underpinned by operational excellence, advantaged investments, and cost discipline. This segment includes olefins, polyolefins, and intermediates.

Over the long term, worldwide demand for chemicals is expected to grow faster than the overall economy, driven by global population growth, an expanding middle class, and improving living standards. Chemical Products integration with refineries, performance product mix, and project execution capability improves returns on investments across a range of market environments.

In 2025, chemical industry margins remained deeply bottom-of-cycle, below the 10-year historical range (2010-2019), as capacity additions have far exceeded demand growth. The Company optimized production across our global footprint to profitably meet customer demand. Our earnings benefited from solid reliability, record high-value products sales, and a large North American footprint where low ethane prices continue to provide a feed advantage.

Key Recent Events

China Chemical Complex: Started up a petrochemical complex in the Dayawan Petrochemical Industrial Park in Huizhou, Guangdong Province, which is a significant step in growing our global manufacturing footprint and is the first 100 percent foreign-owned petrochemical complex built in China. The facility, which focuses on producing our unique high-performance polyethylene and polypropylene products, is equipped with three polyethylene and two polypropylene production lines for a combined capacity of over 2.5 million metric tons per year. This capacity will more efficiently serve China’s large and evolving domestic demand, which is currently being met with imports.

Advanced Recycling: ExxonMobil is combining proprietary technology and advantaged integrated sites to process hard-to-recycle plastic waste back into raw materials to produce valuable new products. In 2025, the Company added two new advanced recycling units to the Baytown facility, tripling capacity at the site, and representing one of the largest advanced recycling facilities in North America. Additional units are being assessed as the Company aims to reach a global recycling capacity of 1 billion pounds per year to help reduce plastic waste.

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Chemical Products Financial Results

(millions of dollars)

2025

2024

2023

Earnings (loss) (U.S. GAAP)

United States

903

1,627

1,626

Non-U.S.

(103)

950

Total

800

2,577

1,637

Identified Items (1)

United States

(80)

(43)

Non-U.S.

(190)

(52)

(420)

Total

(270)

(95)

(388)

Earnings (loss) excluding Identified Items (1) (Non-GAAP)

United States

983

1,670

1,594

Non-U.S.

1,002

431

Total

1,070

2,672

2,025

2025 Chemical Products Earnings Driver Analysis (1)

(millions of dollars)

Margin – Decreased earnings by $1.8 billion, as oversupply resulted in margins at bottom-of-cycle market conditions.

Advantaged Volume Growth – New projects increased earnings by $0.2 billion driven by high-value product sales.

Base Volume – Increased earnings by $0.1 billion.

Structural Cost Savings (1) – Increased earnings by $0.2 billion.

Expenses – Higher advantaged project spend, including China Chemical Complex ramp-up, decreased earnings by $0.5 billion.

Other – Increased earnings by $0.2 billion.

Identified Items (1) – 2024 $(0.1) billion loss driven by impairments; 2025 $(0.3) billion loss driven by impairments.

(1) Refer to Frequently Used Terms for definition of Structural Cost Savings, Identified Items, and Earnings (loss) excluding Identified Items.

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2024 Chemical Products Earnings Driver Analysis (1)

(millions of dollars)

Margin – Improved company margins on North American ethane feed advantage and improved product realizations increased earnings by $0.9 billion, despite continued bottom-of-cycle market conditions.

Advantaged Volume Growth – Record high-value product sales increased earnings by $0.4 billion.

Base Volume – Portfolio optimization and product sales mix decreased earnings by $0.3 billion.

Structural Cost Savings (1) – Increased earnings by $0.2 billion.

Expenses – Higher advantaged projects spend and inflation effects decreased earnings by $0.5 billion.

Other – All other items decreased earnings by $0.1 billion.

Identified Items (1) – 2023 $(0.4) billion loss was primarily driven by impairments; 2024 $(0.1) billion loss driven by impairments.

(1) Refer to Frequently Used Terms for definition of Structural Cost Savings, Identified Items, and Earnings (loss) excluding Identified Items.

Chemical Products Operational Results

(thousands of metric tons)

2025

2024

2023

Chemical Products sales (2)

United States

6,977

7,038

6,779

Non-U.S.

14,326

12,354

12,603

Worldwide

21,303

19,392

19,382

(2) Data reported net of purchases/sales contracts with the same counterparty.

Due to rounding, numbers presented may not add up precisely to the totals indicated.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Specialty Products

ExxonMobil Specialty Products is a combination of business units that manufacture and market a range of performance products, including high-quality lubricants, basestocks, waxes, synthetics, elastomers, and resins. Leveraging ExxonMobil’s proprietary technologies, Specialty Products focuses on providing performance products that help customers improve efficiency in the transportation and industrial sectors.

Specialty Products is well-positioned to help meet the demand for premium lubricant products through advantaged projects that leverage ExxonMobil's integration, technology, and world-class brands, such as Mobil 1TM.

In 2025, Specialty Products continued to deliver strong earnings from our portfolio of high-value products and brand market position.

Key Recent Events

Singapore Resid Upgrade project: This project started up in 2025, leveraging two proprietary technologies to upgrade fuel oil to Group II lubricant basestock and diesel. It further strengthens ExxonMobil’s position as the largest basestock producer in the world and introduces a first-of-its-kind basestock, EHC 340 MAXTM, with superior performance attributes, to the market.

ProxximaTM Resin Systems: ExxonMobil's advanced polyolefin thermoset resin uses components of gasoline and catalyst technology to create a material that is lighter, stronger, and more durable than conventional products, providing alternatives for the construction, coatings, and transportation industries. These systems are designed to drive product substitutions in existing markets and enable expansion into new applications like structural composites and steel substitutes. In 2025, ExxonMobil more than tripled ProxximaTM resin blending capacity with plans to grow production to 200,000 tons per year by 2030.

Carbon Materials venture: ExxonMobil is growing its carbon materials venture by applying proprietary process technology to capture attractive opportunities in the battery anode market. The Company has developed an advanced coke product by converting low-value, bottom-of-the-barrel molecules that can deliver a higher performance differentiated graphite. These carbon materials enable batteries that can provide up to 30 percent higher available capacity, 30 percent faster charging time, and extended battery life. In 2025, ExxonMobil acquired key technology and assets from Superior Graphite. This acquisition, which complements ExxonMobil's process technology and expertise, enables a faster scale-up and a swifter entry into the battery anode market with our differentiated graphite product.

Specialty Products Financial Results

(millions of dollars)

2025

2024

2023

Earnings (loss) (U.S. GAAP)

United States

1,200

1,576

1,536

Non-U.S.

1,657

1,476

1,178

Total

2,857

3,052

2,714

Identified Items (1)

United States

(4)

Non-U.S.

(12)

(9)

(105)

Total

—

(13)

(93)

Earnings (loss) excluding Identified Items (1) (Non-GAAP)

United States

1,188

1,580

1,524

Non-U.S.

1,669

1,485

1,283

Total

2,857

3,065

2,807

(1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items.

Due to rounding, numbers presented may not add up precisely to the totals indicated.

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2025 Specialty Products Earnings Driver Analysis (1)

(millions of dollars)

Margin – Increased earnings by $40 million.

Advantaged Volume Growth – Increased earnings by $0.1 billion.

Base Volume – Decreased earnings by $20 million.

Structural Cost Savings (1) – Increased earnings by $0.1 billion.

Expenses – Higher expenses to develop markets for carbon materials and ProxximaTM resins decreased earnings by $0.2 billion.

Other – Decreased earnings by $0.2 billion, mainly from unfavorable foreign exchange effects.

Identified Items (1) – 2024 $(13) million loss.

(1) Refer to Frequently Used Terms for definition of Structural Cost Savings, Identified Items, and Earnings (loss) excluding Identified Items.

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2024 Specialty Products Earnings Driver Analysis (1)

(millions of dollars)

Margin – Stronger basestocks and finished lubes margins increased earnings by $0.6 billion.

Advantaged Volume Growth – High-value product volume growth increased earnings by $0.1 billion.

Base Volume – Decreased earnings by $10 million.

Structural Cost Savings (1) – Increased earnings by $0.1 billion.

Expenses – Higher expenses including new product development costs, decreased earnings by $0.3 billion.

Other – All other items decreased earnings by $0.2 billion, mainly unfavorable foreign exchange effects and absence of prior year favorable year-end inventory effects.

Identified Items (1) – 2023 $(93) million loss from impairments; 2024 $(13) million loss.

(1) Refer to Frequently Used Terms for definition of Structural Cost Savings, Identified Items, and Earnings (loss) excluding Identified Items.

Specialty Products Operational Results

(thousands of metric tons)

2025

2024

2023

Specialty Products sales (2)

United States

1,894

1,922

1,962

Non-U.S.

5,897

5,745

5,635

Worldwide

7,791

7,666

7,597

(2) Data reported net of purchases/sales contracts with the same counterparty.

Due to rounding, numbers presented may not add up precisely to the totals indicated.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Corporate and Financing

Corporate and Financing is comprised of corporate activities that support ExxonMobil's operating segments and Low Carbon Solutions business. Corporate activities include general administrative support functions, financing, and insurance activities. Low Carbon Solutions activities will be included in Corporate and Financing until the business is established with a material level of assets and revenue.

Corporate and Financing Financial Results

(millions of dollars)

2025

2024

2023

Earnings (loss) (U.S. GAAP)

(3,590)

(1,372)

(1,791)

Identified Items (1)

(585)

Earnings (loss) excluding Identified Items (1) (Non-GAAP)

(3,005)

(1,402)

(1,867)

(1) Refer to Frequently Used Terms for definition of Identified Items and Earnings (loss) excluding Identified Items.

2025

Corporate and Financing expenses were $3.6 billion in 2025 compared to $1.4 billion in 2024, with the increase mainly due to higher financing costs.

2024

Corporate and Financing expenses were $1.4 billion in 2024 compared to $1.8 billion in 2023, with the decrease mainly due to lower financing costs.

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LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

(millions of dollars)

2025

2024

2023

Net cash provided by/(used in)

Operating activities

51,970

55,022

55,369

Investing activities

(25,927)

(19,938)

(19,274)

Financing activities

(39,081)

(42,789)

(34,297)

Effect of exchange rate changes

532

(676)

105

Increase/(decrease) in cash and cash equivalents

(12,506)

(8,381)

1,903

Total cash and cash equivalents (December 31)

10,681

23,187

31,568

Total cash and cash equivalents were $10.7 billion at the end of 2025, down $12.5 billion from the prior year. The major sources of funds in 2025 were net income including noncontrolling interests of $29.8 billion, the adjustment for the noncash provision of $26.0 billion for depreciation and depletion, proceeds from asset sales of $3.2 billion, and other investing activities of $3.4 billion. The major uses of funds included spending for additions to property, plant, and equipment of $28.4 billion; dividends to shareholders of $17.2 billion; the purchase of ExxonMobil stock of $20.3 billion; additional investments and advances of $4.1 billion; and a change in working capital of $7.7 billion.

Total cash and cash equivalents were $23.2 billion at the end of 2024, down $8.4 billion from the prior year. The major sources of funds in 2024 were net income including noncontrolling interests of $35.1 billion, the adjustment for the noncash provision of $23.4 billion for depreciation and depletion, proceeds from asset sales of $5.0 billion, and other investing activities of $1.9 billion, and cash acquired from mergers and acquisitions of $0.8 billion. The major uses of funds included spending for additions to property, plant, and equipment of $24.3 billion; dividends to shareholders of $16.7 billion; the purchase of ExxonMobil stock of $19.6 billion; debt repayment of $5.9 billion; additional investments and advances of $3.3 billion; and a change in working capital of $1.8 billion.

The Corporation has access to significant capacity of long-term and short-term liquidity. Internally generated funds are expected to cover the majority of financial requirements, supplemented by long-term and short-term debt. Commercial paper is used to balance short-term liquidity requirements and is reflected in "Notes and loans payable" on the Consolidated Balance Sheet, with changes in outstanding commercial paper between periods included in the Consolidated Statement of Cash Flows. On December 31, 2025, the Corporation had undrawn short-term committed lines of credit of $7.3 billion and undrawn long-term lines of credit of $1.0 billion. In the fourth quarter of 2025, the Corporation established a 364-day revolving credit facility of $7.0 billion to provide short-term borrowing capacity for general corporate purposes.

To support cash flows in future periods, the Corporation will need to continually find or acquire and develop new fields, and continue to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production. After a period of production at plateau rates, it is the nature of oil and gas fields to eventually produce at declining rates for the remainder of their economic life. Decline rates can vary widely by individual field due to a number of factors, including, but not limited to, the type of reservoir, fluid properties, recovery mechanisms, work activity, and age of the field. In particular, the Corporation’s key tight-oil plays have higher initial decline rates which tend to moderate over time. Furthermore, the Corporation’s net interest in production for individual fields can vary with price and the impact of fiscal and commercial terms.

The Corporation has long been successful at mitigating the effects of natural field decline through disciplined investments in quality opportunities and project execution. The Corporation anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, the impact of fiscal and commercial terms, asset sales, weather events, price effects on production sharing contracts, changes in the amount and timing of investments that may vary depending on the oil and gas price environment, and international trade patterns and relations. The Corporation’s cash flows are also highly dependent on crude oil and natural gas prices. Please refer to Item 1A for a more complete discussion of risks.

The Corporation’s financial strength enables it to make large, long-term capital expenditures. Cash Capex in 2025 was $29.0 billion, including $2.6 billion of acquisitions, reflecting the Corporation’s continued active investment program.

Upstream spending of $24.7 billion in 2025 was up $4.4 billion from 2024, reflecting higher spend in the U.S. Permian Basin which included the full-year impact from the Pioneer acquisition. Development projects typically take several years from the time of recording proved undeveloped reserves to the start of production and can exceed five years for large and complex projects. The percentage of proved developed reserves was 64 percent of total proved reserves at year-end 2025 and has been over 60 percent for the last ten years.

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Capital investments in the three Product Solutions businesses totaled $3.7 billion in 2025, a decrease of $0.8 billion from 2024, reflecting lower global project spending. Other spend of $0.6 billion primarily reflects investments in the Low Carbon Solutions business.

The Corporation plans to invest in the range of $27 billion to $29 billion in 2026. The investment range for 2026 excludes advances and collections not related to capital expenditures or equity investments, for example, supply and marketing related advances and associated collections. Included in the 2026 capital spend range is $8.5 billion of firm capital commitments. An additional $8.0 billion of firm capital commitments have been made for years 2027 and beyond. Actual spending could vary depending on the progress of individual projects and property acquisitions. The Corporation has a large and diverse portfolio of development projects and exploration opportunities, which helps mitigate the overall political and technical risks of the Corporation’s Upstream segment and associated cash flow. Further, due to its financial strength and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Corporation’s liquidity or ability to generate sufficient cash flows for operations and its fixed commitments.

The Corporation, as part of its ongoing asset management program, continues to evaluate its mix of assets for potential upgrade. Because of the ongoing nature of this program, dispositions will continue to be made from time to time which will result in either gains or losses. Additionally, the Corporation continues to evaluate opportunities to enhance its business portfolio through acquisitions of assets or companies and enters into such transactions from time to time. Key criteria for evaluating acquisitions include strategic fit, cost and other synergies, potential for future growth, low cost of supply, and attractive valuations. Acquisitions may be made with cash, shares of the Corporation’s common stock, or both.

Cash Flow from Operating Activities

2025

Cash provided by operating activities totaled $52.0 billion in 2025, $3.1 billion lower than 2024. The major source of funds was net income including noncontrolling interests of $29.8 billion, a decrease of $5.3 billion. The noncash provision for depreciation and depletion was $26.0 billion, up $2.6 billion from the prior year. The adjustment for the net gain on asset sales was $1.1 billion, a decrease of $0.1 billion. The adjustment for dividends received less than equity in current earnings of equity companies was an increase of $3.0 billion, compared to an increase of $0.2 billion in 2024. Changes in operational working capital, excluding cash and debt, decreased cash in 2025 by $7.7 billion.

2024

Cash provided by operating activities totaled $55.0 billion in 2024, $0.3 billion lower than 2023. The major source of funds was net income including noncontrolling interests of $35.1 billion, a decrease of $2.3 billion. The noncash provision for depreciation and depletion was $23.4 billion, up $2.8 billion from the prior year. The adjustment for the net gain on asset sales was $1.2 billion, an increase of $0.7 billion. The adjustment for dividends received less than equity in current earnings of equity companies was an increase of $0.2 billion, compared to an increase of $0.5 billion in 2023. Changes in operational working capital, excluding cash and debt, decreased cash in 2024 by $1.8 billion.

Cash Flow from Investing Activities

2025

Cash used in investing activities netted to $25.9 billion in 2025, $6.0 billion higher than 2024. Spending for property, plant, and equipment of $28.4 billion increased $4.1 billion from 2024. Proceeds from asset sales and returns of investments of $3.2 billion compared to $5.0 billion in 2024. Additional investments and advances were $0.8 billion higher in 2025, while proceeds from other investing activities including collection of advances increased by $1.5 billion.

2024

Cash used in investing activities netted to $19.9 billion in 2024, $0.7 billion higher than 2023. Spending for property, plant, and equipment of $24.3 billion increased $2.4 billion from 2023. Proceeds from asset sales and returns of investments of $5.0 billion compared to $4.1 billion in 2023. Additional investments and advances were $0.3 billion higher in 2024, while proceeds from other investing activities including collection of advances increased by $0.4 billion.

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Cash Flow from Financing Activities

2025

Cash used in financing activities was $39.1 billion in 2025, $3.7 billion lower than 2024. Dividend payments on common shares increased to $4.00 per share from $3.84 per share and totaled $17.2 billion.

During 2025, the Corporation continued its share repurchase program, including the purchase of 180.1 million shares at a book value of $20 billion in 2025. In its 2025 Corporate Plan Update released December 9, 2025, the Corporation stated that it is expected to continue its share repurchase program with a $20 billion repurchase pace per year through 2026, assuming reasonable market conditions. The stock repurchase program does not obligate the Company to acquire any particular amount of common stock, and it may be discontinued or resumed at any time. The timing and amount of shares actually purchased in the future will depend on market, business, and other factors.

2024

Cash used in financing activities was $42.8 billion in 2024, $8.5 billion higher than 2023. Dividend payments on common shares increased to $3.84 per share from $3.68 per share and totaled $16.7 billion. During 2024, the Corporation utilized cash to repay debt of $5.9 billion.

During 2024, the Corporation continued its share repurchase program, including the purchase of 167 million shares at a book value of $19.1 billion in 2024.

Contractual Obligations

The Corporation has contractual obligations involving commitments to third parties that impact its liquidity and capital resource needs. These contractual obligations are primarily for leases, debt, asset retirement obligations, pension and other postretirement benefits, take-or-pay and unconditional purchase obligations, and firm capital commitments. See Notes 4, 9, 12, and 13 for information related to pensions, asset retirement obligations, long-term debt, and leases, respectively.

In addition, the Corporation also enters into commodity purchase obligations (volumetric commitments with no fixed or minimum price) which are resold shortly after purchase, either in an active, highly liquid market, or under long-term, unconditional sales contracts with similar pricing terms. Examples include long-term, noncancelable LNG and natural gas purchase commitments and commitments to purchase refinery products at market prices. These commitments are not meaningful in assessing liquidity and cash flow because the purchases will be offset in the same periods by cash received from the related sales transactions.

Take-or-pay obligations are noncancelable, long-term commitments for goods and services. Unconditional purchase obligations are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services. These obligations mainly pertain to pipeline, manufacturing supply, and terminal agreements. The total obligation at year-end 2025 for take-or-pay and unconditional purchase obligations was $54.1 billion. Cash payments expected in 2026 and 2027 are $6.3 billion and $6.2 billion, respectively.

Guarantees

The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2025, for guarantees relating to notes, loans, and performance under contracts (Note 7). Where guarantees for environmental remediation and other similar matters do not include a stated cap, the amounts reflect management’s estimate of the maximum potential exposure. Where it is not possible to make a reasonable estimation of the maximum potential amount of future payments, future performance is expected to be either immaterial or have only a remote chance of occurrence. Guarantees are not reasonably likely to have a material effect on the Corporation’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financial Strength

On December 31, 2025, the Corporation had total unused short-term committed lines of credit of $7.3 billion (Note 10) and total unused long-term committed lines of credit of $1.0 billion (Note 12). The table below shows the Corporation’s consolidated debt to capital ratios.

(percent)

2025

2024

2023

Debt to capital

14.0

13.4

16.4

Net debt to capital (1)

11.0

6.5

4.5

(1) Net debt is total debt less cash and cash equivalents excluding restricted cash. Net debt to capital ratio is net debt divided by net debt plus total equity. Total debt is the sum of notes and loans payable and long-term debt, as reported in the Consolidated Balance Sheet.

Management views the Corporation’s financial strength to be a competitive advantage of strategic importance. The Corporation’s financial position gives it the opportunity to access the world’s capital markets across a range of market conditions and enables the Corporation to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.

The Corporation's total debt level remained relatively flat in 2025, ending the year at $43.5 billion.

Litigation and Other Contingencies

As discussed in Note 7, a variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a material adverse effect upon the Corporation’s operations, financial condition, or financial statements taken as a whole. There are no events or uncertainties beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition. Refer to Note 7 for additional information on legal proceedings and other contingencies.

TAXES

(millions of dollars)

2025

2024

2023

Income taxes

11,504

13,810

15,429

Effective income tax rate

31%

33%

Total other taxes and duties

28,930

29,894

32,191

Total

40,434

43,704

47,620

2025

Total taxes on the Corporation’s income statement were $40.4 billion in 2025, a decrease of $3.3 billion from 2024. Income tax expense, both current and deferred, was $11.5 billion compared to $13.8 billion in 2024. The effective tax rate, which is calculated based on consolidated company income taxes and ExxonMobil’s share of equity company income taxes, was 31 percent. This is down two percentage points compared to 2024 due primarily to favorable one-time items. Total other taxes and duties of $28.9 billion in 2025 decreased $1.0 billion.

2024

Total taxes on the Corporation’s income statement were $43.7 billion in 2024, a decrease of $3.9 billion from 2023. Income tax expense, both current and deferred, was $13.8 billion compared to $15.4 billion in 2023. The effective tax rate, which is calculated based on consolidated company income taxes and ExxonMobil’s share of equity company income taxes, was 33 percent. This is flat compared to 2023. Total other taxes and duties of $29.9 billion in 2024 decreased $2.3 billion from 2023.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ENVIRONMENTAL MATTERS

Environmental Expenditures

(millions of dollars)

2025

2024

Capital expenditures

3,053

3,607

Other expenditures

4,580

5,348

Total

7,633

8,955

Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, water, and ground. These include significant investments in refining infrastructure and technology to manufacture clean fuels; projects to monitor and reduce air, water, and waste emissions, both from the Company’s operations and from other companies; and expenditures for asset retirement obligations. Using definitions and guidelines established by the American Petroleum Institute, ExxonMobil’s 2025 worldwide environmental expenditures for all such preventative and remediation steps were $7.6 billion, of which $4.6 billion were included in expenses with the remainder in capital expenditures. As the Corporation progresses its emission-reduction plans, worldwide environmental expenditures are expected to increase to approximately $9 billion annually in 2026 and 2027, with capital expenditures expected to account for approximately 44 percent of the total expenditures.

Environmental Liabilities

The Corporation accrues environmental liabilities when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. ExxonMobil has accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency has identified ExxonMobil as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could mitigate ExxonMobil’s actual joint and several liability exposure. At present, no individual site is expected to have losses material to ExxonMobil’s operations or financial condition. Consolidated company provisions made in 2025 for environmental liabilities were $0.4 billion ($0.3 billion in 2024), and the balance sheet reflects liabilities of $0.9 billion as of December 31, 2025, and $0.7 billion as of December 31, 2024.

MARKET RISKS

Worldwide Average Realizations (1)

2025

2024

2023

Brent ($ per barrel)

69.06

80.76

82.62

Henry Hub ($ per metric million British thermal unit)

3.43

2.27

2.74

TTF ($ per metric million British thermal unit)

12.39

10.77

15.15

(1) Consolidated subsidiaries.

Crude oil, natural gas, petroleum product, and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings have varied across the Corporation's operating segments. For the year 2026, a $1 per barrel change in the Brent price would have an approximately $700 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives. This Brent sensitivity includes oil-linked LNG sales which make up approximately 10 percent of the sensitivity. A $0.10 per million metric British thermal unit change in the Henry Hub price would have an approximately $90 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives. Similarly, a $0.10 per million metric British thermal unit change in the Title Transfer Facility (TTF) price would have an approximately $20 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives. This TTF sensitivity primarily represents LNG sales. These price markers have a direct impact on our realized prices. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, results of trading activities, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide broad indicators of changes in the earnings experienced in any particular period.

In the very competitive petroleum and petrochemical environment, earnings are primarily determined by margin capture rather than absolute price levels of products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the Corporation’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the Corporation’s financial strength as a competitive advantage.

In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Instead, where such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery and chemical complexes. Additionally, intersegment sales are at market-based prices. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity, and transportation capabilities. Refer to Note 3 for additional information on intersegment revenue.

Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to global economic conditions, political events, decisions by OPEC or OPEC+ and other major government resource owners and other factors, industry economics over the long term will continue to be driven by market supply and demand. The Corporation evaluates investments over a range of prices, including estimated greenhouse gas emission costs even in jurisdictions without a current greenhouse gas pricing policy.

The Corporation has an active asset management program in which nonstrategic assets are considered for divestment. The asset management program includes a disciplined, regular review to ensure assets are contributing to the Corporation’s strategic objectives.

Risk Management

The Corporation’s size, strong capital structure, geographic diversity, and the complementary nature of its business segments reduce the Corporation’s enterprise-wide risk from changes in commodity prices, currency rates, and interest rates. In addition, the Corporation uses commodity-based contracts, including derivatives, to manage commodity price risk and to generate returns from trading. The Corporation’s commodity derivatives are not accounted for under hedge accounting. At times, the Corporation also enters into currency and interest rate derivatives, none of which are material to the Corporation’s financial position as of December 31, 2025 and 2024, or results of operations for the years ended 2025, 2024, and 2023. Credit risk associated with the Corporation’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of and financial limits placed on derivative counterparties. No material market or credit risks to the Corporation’s financial position, results of operations, or liquidity exist as a result of the derivatives described in Note 6. The Corporation maintains a system of controls that includes the authorization, reporting, and monitoring of derivative activity.

The Corporation is exposed to changes in interest rates, primarily on its short-term debt and the portion of long-term debt that carries floating interest rates. The impact of a 100-basis-point change in interest rates affecting the Corporation’s debt would not be material to earnings or cash flow. The Corporation has access to significant capacity of long-term and short-term liquidity. Internally generated funds are generally expected to cover financial requirements, supplemented by long-term and short-term debt as required. Commercial paper is used to balance short-term liquidity requirements. Some joint-venture partners are dependent on the credit markets, and their funding ability may impact the development pace of joint-venture projects.

The Corporation conducts business in many foreign currencies and is subject to exchange rate risk on cash flows related to sales, expenses, financing, and investment transactions. Fluctuations in exchange rates are often offsetting and the impacts on ExxonMobil’s geographically and functionally diverse operations are varied. The Corporation makes limited use of currency exchange contracts to mitigate the impact of changes in currency values, and exposures related to the Corporation’s use of these contracts are not material.

CRITICAL ACCOUNTING ESTIMATES

The Corporation’s accounting and financial reporting fairly reflect its integrated business model involving exploration for, and production of, crude oil and natural gas; manufacture, trade, transport, and sale of crude oil, natural gas, petroleum products, petrochemicals, and a wide variety of specialty products; and pursuit of lower-emission and other new business opportunities including carbon capture and storage, hydrogen and ammonia, lower-emission fuels, ProxximaTM resin systems, carbon materials, low-carbon data centers, and lithium. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. The Corporation’s accounting policies are summarized in Note 1.

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Oil and Natural Gas Reserves

The estimation of proved oil and natural gas reserve volumes is an ongoing process based on rigorous technical evaluations, commercial and market assessments, and detailed analysis of reservoir and well performance, development and production costs, and other factors. The estimation of proved reserves is controlled by the Corporation through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Global Reserves and Resources Group which has significant technical experience, culminating in reviews with, and approval by, senior management. Notably, the Corporation does not use specific quantitative reserve targets to determine compensation. Key features of the reserve estimation process are covered in Disclosure of Reserves in Item 2.

Oil and natural gas reserves include both proved and unproved reserves.

•Proved oil and natural gas reserves are determined in accordance with Securities and Exchange Commission (SEC) requirements. Proved reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic and operating conditions and government regulations. Proved reserves are determined using the average of first-of-month oil and natural gas prices during the reporting year.

Proved reserves can be further subdivided into developed and undeveloped reserves. Proved developed reserves include amounts which are expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include amounts expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion. Proved undeveloped reserves are recognized only if a development plan has been adopted indicating that the reserves are scheduled to be drilled within five years, unless specific circumstances support a longer period of time.

The Corporation is reasonably certain that proved reserves will be produced. However, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals, government policy, consumer preferences, and significant changes in oil and natural gas price levels.

•Unproved reserves are quantities of oil and natural gas with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that, together with proved reserves, are as likely as not to be recovered.

Revisions in previously estimated volumes of proved reserves for existing fields can occur due to the evaluation or re-evaluation of (1) already available geologic, reservoir, or production data, (2) new geologic, reservoir, or production data, or (3) changes in the average of first-of-month oil and natural gas prices and/or costs that are used in the estimation of reserves. Revisions can also result from significant changes in development strategy or production equipment and facility capacity.

Unit-of-Production Depreciation

Oil and natural gas reserve volumes are used as the basis to calculate unit-of-production depreciation rates for most upstream assets. Acquisition costs of proved properties are depreciated using a ratio of asset cost to total proved reserves while capitalized drilling and developments costs are depreciated using a ratio of actual production volumes to proved developed reserves. The volumes produced and asset cost are known, while proved reserves are based on estimates that are subject to some variability.

In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative method is used. The straight-line method is used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the Corporation uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life.

To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes.

Fair Value Used in Business Combinations

In accounting for business combinations, the purchase price paid to acquire a business is allocated to its assets and liabilities based on their respective estimated fair values as of the date of acquisition. If applicable, any excess of the purchase price over the fair value is recorded as goodwill. The assessment of fair value is based upon the views of a likely market participant group.

On May 3, 2024, the Corporation acquired Pioneer Natural Resources Company (Pioneer), an independent oil and gas exploration and production company. To effect the acquisition, we issued 545 million shares of ExxonMobil common stock having a fair value of $63 billion on the acquisition date and assumed debt with a fair value of $5 billion.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In respect of the Pioneer acquisition, the most significant amount of judgment involved the estimated fair values of property, plant, and equipment related to crude oil and natural gas properties, for which we used discounted cash flow models. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, commodity prices consistent with the average of third-party industry experts, drilling and development costs, and risk-adjusted discount rates.

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. Actual results may differ from the projected results used to determine fair value.

See Note 20 for further information regarding the Pioneer acquisition during 2024.

Impairment

The Corporation tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. The Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of ASC 360 and ASC 932, and relies, in part, on the Corporation’s planning and budgeting cycle.

Because the lifespans of the vast majority of the Corporation’s major assets are measured in decades, the future cash flows of these assets are predominantly based on long-term oil and natural gas commodity prices and industry margins, development costs, and production costs. Significant reductions in the Corporation’s view of oil or natural gas commodity prices or margin ranges, especially the longer-term prices and margins, and changes in the development plans, including decisions to defer, reduce, or eliminate planned capital spending, can be an indicator of potential impairment. Other events or changes in circumstances, including indicators outlined in ASC 360, can be indicators of potential impairment as well.

In general, the Corporation does not view temporarily low prices or margins as an indication of impairment. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments, and technology and efficiency advancements. OPEC+ investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities, alternative energy sources, and levels of prosperity. During the lifespan of its major assets, the Corporation expects that oil and gas prices and industry margins will experience significant volatility. Consequently, these assets will experience periods of higher earnings and periods of lower earnings, or even losses. In assessing whether events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the Corporation considers recent periods of operating losses in the context of its longer-term view of prices and margins.

Global Outlook and Cash Flow Assessment. The annual planning and budgeting process, known as the Corporate Plan, is the mechanism by which resources (capital, operating expenses, and people) are allocated across the Corporation. The foundation for the assumptions supporting the Corporate Plan is the Global Outlook (Outlook), which contains the Corporation’s demand and supply projections based on its assessment of current trends in technology, government policies, consumer preferences, geopolitics, economic development, and other factors. Reflective of the existing global policy environment, the Outlook does not attempt to project the degree of necessary future policy and technology advancement and deployment for the world, or the Corporation, to meet net zero by 2050. As future policies and technology advancements emerge, they will be incorporated into the Outlook, and the Corporation’s business plans will be updated accordingly.

If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on the assumptions developed in the Corporate Plan, which is reviewed and approved by the Board of Directors, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the Corporation’s assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, development and operating costs including greenhouse gas emission prices, and foreign currency exchange rates. Notably, when assessing future cash flows, the Corporation includes the estimated costs in support of reaching its greenhouse gas emission-reduction plans, including its goal of net-zero Scope 1 and 2 greenhouse gas emissions from its Permian Basin operated assets by 2035. Volumes are based on projected field and facility production profiles, throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities. ExxonMobil considers a range of scenarios - including remote scenarios - to help inform perspective of the future and enhance strategic thinking over time. While third-party scenarios may be used for these purposes, they are not used as a basis for developing future cash flows for impairment assessments. As part of the Corporate Plan, the Company considers estimated greenhouse gas emission costs, even for jurisdictions without a current greenhouse gas pricing policy.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fair Value of Impaired Assets. An asset group is impaired if its estimated undiscounted cash flows are less than the asset group’s carrying value. Impairments are measured by the excess of the carrying value over fair value. The assessment of fair value is based upon the views of a likely market participant. The principal parameters used to establish fair value include estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, throughput and product sales volumes, commodity prices (which are consistent with the average of third-party industry experts and government agencies), refining and chemical margins, drilling and development costs, operating costs, and discount rates which are reflective of the characteristics of the asset group.

Other Impairment Estimates. Unproved properties are assessed periodically to determine whether they have been impaired. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the Corporation's future development plans, the estimated economic chance of success, and the length of time that the Corporation expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.

Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the assets are considered impaired and adjusted to the lower value. Judgment is required to determine if assets are held for sale and to determine the fair value less cost to sell.

Investments accounted for by the equity method are assessed for possible impairment when events or changes in circumstances indicate that the carrying value of an investment may not be recoverable. Examples of key indicators include a history of operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If the decline in value of the investment is other than temporary, the carrying value of the investment is written down to fair value. In the absence of market prices for the investment, discounted cash flows are used to assess fair value, which requires significant judgment.

Recent Impairments. Impairments in 2025 totaled $2.0 billion after-tax, including a write-down to fair value of Upstream oil and gas assets held for sale and charges associated with the optimization of materials and supply inventory.

Impairments in 2024 were immaterial.

In 2023, the Corporation recognized after-tax charges of $3.4 billion, primarily related to the idled Upstream Santa Ynez Unit assets and associated facilities in California, which reflected the continuing challenges in the state regulatory environment that impeded progress towards restoring operations. Other impairments in the year included a $0.6 billion charge related to an Upstream equity investment.

Factors which could put further assets at risk of impairment in the future include reductions in the Corporation’s price or margin outlooks, changes in the allocation of capital or development plans, reduced long-term demand for the Corporation's products, and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural gas price or margin increases. However, due to the inherent difficulty in predicting future commodity prices or margins, and the relationship between industry prices and costs, it is not practicable to reasonably estimate the existence or range of any potential future impairment charges related to the Corporation’s long-lived assets.

For further information regarding impairments in property, plant, and equipment and suspended wells, refer to Notes 9 and 16, respectively.

Asset Retirement Obligations

The Corporation is subject to retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, discount rates, and inflation rates. See Note 9 for further information regarding asset retirement obligations.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Pension Benefits

The Corporation and its affiliates sponsor about 70 defined benefit (pension) plans in nearly 40 countries. Note 4 provides details on pension obligations, fund assets, and pension expense.

Some of these plans (primarily non-U.S.) provide pension benefits that are paid directly by their sponsoring affiliates out of corporate cash flow rather than a separate pension fund because applicable tax rules and regulatory practices do not encourage advance funding. Book reserves are established for these plans. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets.

For funded plans, including those in the U.S., pension obligations are financed in advance through segregated assets or insurance arrangements. These plans are managed in compliance with the requirements of governmental authorities and meet or exceed required funding levels as measured by relevant actuarial and government standards at the mandated measurement dates. In determining liabilities and required contributions, these standards often require approaches and assumptions that differ from those used for accounting purposes.

The Corporation will continue to make contributions to these funded plans as necessary. All defined-benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.

Pension accounting requires explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the discount rate for the benefit obligations, and the long-term rate for future salary increases. Pension assumptions are reviewed annually by outside actuaries and senior management. These assumptions are adjusted as appropriate to reflect changes in market rates and outlook. The long-term expected earnings rate on U.S. pension plan assets in 2025 was 6.0 percent. The 10-year and 20-year actual returns on U.S. pension plan assets were 5 percent over both periods. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted-average of the target asset allocation percentages and the long-term return assumption for each asset class. A worldwide reduction of 0.5 percent in the long-term rate of return on assets would increase annual pension expense by approximately $150 million before tax.

Differences between actual returns on fund assets and the long-term expected return are not recognized in pension expense in the year that the difference occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected remaining service life of employees.

Litigation and Tax Contingencies

A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending lawsuits. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. For contingencies where an unfavorable outcome is reasonably possible and significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. As described in Note 7, for purposes of our contingency disclosures, “significant” includes material matters, as well as other matters, which management believes should be disclosed. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies.

Management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past. Payments have not had a material adverse effect on our operations or financial condition. In the Corporation’s experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement.

The Corporation is subject to income taxation in many jurisdictions around the world. The benefits of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict. The Corporation’s unrecognized tax benefits and a description of open tax years are summarized in Note 15.