Major judgments and accounting estimates

Major judgments and accounting estimates

The preparation of financial statements in accordance with IFRS for the closing as of December 31, 2025 requires the General Management to make estimates, assumptions and judgments that affect the information reported in the Consolidated Financial Statements and the Notes thereto.

These estimates, assumptions and judgments are based on historical experience and other factors believed to be reasonable at the date of preparation of the financial statements. They are reviewed on an on-going basis by General Management and therefore could be revised as circumstances change or as a result of new information.

Different estimates, assumptions and judgments could significantly affect the information reported, and actual results may differ from the amounts included in the Consolidated Financial Statements and the Notes thereto.

The following summary provides further information about the key estimates, assumptions and judgments that are involved in preparing the Consolidated Financial Statements and the Notes thereto. It should be read in conjunction with the sections of the Notes mentioned in the summary.

Ø

Estimation of hydrocarbon reserves

The estimation of oil and gas reserves is a key factor in the Successful Efforts method used by TotalEnergies to account for its oil and gas activities.

TotalEnergies’ oil and gas reserves are estimated by TotalEnergies’ petroleum engineers in accordance with industry standards and SEC (U.S. Securities and Exchange Commission) regulations.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geosciences and engineering data, can be determined with reasonable certainty to be recoverable (from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations), prior to the time at which contracts providing the rights to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Proved oil and gas reserves are calculated using a 12-month average price determined as the unweighted arithmetic average of the first-day-of-the-month price for each month of the relevant year unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. TotalEnergies reassesses its oil and gas reserves at least once a year on all its properties.

The Successful Efforts method and the mineral interests and property, plant and equipment of exploration and production are presented in Note 7 “Intangible and tangible assets”.

Ø

Impairment of property, plant and equipment, intangible assets and goodwill

As part of the determination of the recoverable value of assets for impairment (IAS 36), the estimates, assumptions and judgments mainly concern hydrocarbon prices scenarios, operating costs, production volumes and oil and gas proved and probable reserves, refining margins and product marketing conditions (mainly petroleum, petrochemical and chemical products as well as renewable industry products). The estimates and assumptions used by the General Management are determined in specialized internal departments in light of economic conditions and external expert analysis. The discount rate is reviewed annually.

Impairment of assets and the method applied are described in Note 3 “Business segment information”.

Ø

Asset retirement obligations

Asset retirement obligations, which result from a legal or constructive obligation, are recognized based on a reasonable estimate in the period in which the obligation arises.

This estimate is based on information available in terms of costs and work program. It is regularly reviewed to take into account the changes in laws and regulations, the estimates of reserves and production, the analysis of site conditions and technologies.

The discount rate is reviewed annually.

Asset retirement obligations and the method used are described in Note 12 “Provisions and other non-current liabilities”.

Ø

Climate change and energy transition

Climate change and the energy transition were considered in preparing the Consolidated Financial Statements. They may have significant impacts on the value of TotalEnergies’s assets and liabilities mentioned below, and on similar assets and liabilities that may be recognized in the future.

TotalEnergies supports the goals of the 2015 Paris Agreement, which calls for reducing greenhouse gas emissions in the context of sustainable development and the fight against poverty, and which aims to keep the increase in average global temperatures well below 2°C compared to pre-industrial levels.

TotalEnergies wants to rise to the dual challenge of meeting the energy needs of a growing world population while reducing global warming, and play an active role in the ongoing energy transition of the word.

TotalEnergies is thus implementing its transition strategy aimed at ensuring the growth of its energy production to reach a sales mix of 30% oil, 50% gas and 20% electricity and low-carbon molecules by 2030, with the lifecycle carbon intensity of energy products sold decreasing by 25% compared to 2015.

TotalEnergies has embedded the changing energy markets into its strategy by investing in electricity and renewables, developing the production of biofuels and biogas, favoring the use of natural gas, the transition fuel whose flexibility offers a lower carbon alternative to coal for electricity production and helps to mitigate the intermittency of solar and wind energies, targeting its investments in low-cost and low-emission oil, and developing nature-based carbon storage solutions as well as CO₂ capture and sequestration.

TotalEnergies is committed to reducing its carbon footprint caused by the production, processing and supply of energy to its customers. Although the pace of the transition will depend on public policy, consumption patterns and resulting demand, TotalEnergies has set itself the mission to offer its customers energy products that are affordable and generate less CO₂ and to support its partners and suppliers in their own low-carbon strategies.

TotalEnergies evaluates the solidity of its portfolio, particularly new material capital expenditure investments, on the basis of relevant scenarios and sensitivity tests. Each material capex investment, including in the exploration, acquisition or development of oil and gas resources, as well as in other energies and technologies, is subject to an evaluation that takes into consideration the objectives of the Paris Agreement, each new investment thus enhancing the resilience of the Company’s portfolio.

Economic criteria are analyzed in a scenario with Brent prices at $50/b and Henry Hub at $3/Mbtu, which are lower prices than those in the latest APS scenario published by the IEA and deemed compatible with the Paris agreement goals. Even if CO₂ pricing does not currently apply in all of the Company’s host countries, TotalEnergies includes as a base case in its investment criteria a minimum CO₂ price of 100$/t (or the applicable price in a given country, if it is higher), and beyond 2031, the CO₂ price is inflated by 2% per year.

A physical risk assessment was carried out by the Company in 2024 for around 300 onshore and offshore assets. The Company identifies a limited potential evolution of physical risks related to climate change by 2050.

For investments in upstream oil & gas projects, TotalEnergies focuses on value creation and cash generation over volume, and the Company prioritizes projects with low technical costs (less than $20/b for operating costs plus investment costs) or low-breakeven points (less than $30/b, taxes included) and a profitability that exceeds an internally defined threshold. Carbon Capture and Storage (CCS) and Nature Based Solutions (NBS) projects are evaluated on the basis of the actual cost of one ton of CO₂ (internal threshold in $/tCO₂). As for projects in renewable energies, they are evaluated on their ability to generate a return higher than 10%.

All oil and gas projects must help to lower the average intensity of greenhouse gas emissions (Scope 1+2) in their respective category. Currently, that means:

–

for new oil and gas projects (greenfield and acquisitions), the intensity of Scope 1+2 greenhouse gas emissions is compared, depending on their nature, to the intensity of the average greenhouse gas emissions of the Company’s upstream production assets or that of various downstream units (LNG plants, refineries).

–	for additional investments in existing assets (brownfield projects), the investment must lower the Scope 1+2 emissions intensity of the asset in question.

–	for projects involving other energies and technologies (biofuels, biogas…), the greenhouse-gas emissions reductions are assessed based on their contribution to reducing the lifecyle carbon intensity of energy products sold of the Company.

Besides, as described in Note 3.C “Asset impairment”, in order to ensure the resilience of its assets recognized on the balance sheet, the oil price trajectory retained by the Company for the computation of its impairments converges in the long term towards the price retained in 2050 by the IEA’s NZE scenario, i.e. $25.7₂₀₂₅/b; the prices retained for gas, the transition fuel, stabilize until 2040 at lower levels than current prices, before also converging towards the IEA’s NZE scenario prices in 2050.

The strategy is implemented in the long-term plan of the Company, which is forecasted for a 5-year period, updated every year, and approved by the Board of Directors.

It reflects the economic environment, the emission‑reduction targets set by the Company, and the current dynamics of energy transition, knowing that there is still significant uncertainty on the path to energy transition that the various countries will take.

The financial statements of TotalEnergies are prepared in coherence with the main technical and economic assumptions of the long-term plan and the objectives stated above.

They are also sensitive to various environmental considerations, including oil & gas prices and refining margins, as well as technical parameters, such as the estimation of hydrocarbons reserves. In particular, the selected assumptions and estimates have an impact on hydrocarbons reserves, the useful life of assets, the impairment of assets and provisions.

Asset impairment

The energy transition is likely to have an impact on future oil and gas prices and therefore on the recoverable amount of intangible assets and property, plant and equipment in the oil and gas industry.

The principles applied in determining the recoverable amounts are as follows:

-

the future cash flows were determined using the assumptions included in the 2026 budget and in the long-term plan of the Company approved by the Executive Committee and the Board of Directors. These assumptions, in particular including operational costs, estimation of oil and gas reserves, future volumes produced and marketed, represent the best estimate from the Company Management of economic and technical conditions over the remaining life of the assets;

-

the oil and gas price scenarios have been established based on data on global energy demand from the IEA’s World Energy Outlook, the latest edition of which was published in November 2025, and on its own supply and demand assessments; they take into account assumptions about the evolution of core indicators of the upstream activity (demand for hydrocarbons in different markets, investment forecasts, decline in production fields, changes in oil & gas reserves and supply by area and by nature of oil & gas products), of the downstream activity (changes in refining capacity and demand for petroleum products) and by integrating “climate” challenge;

-

these price scenarios, first prepared within the Strategy & Markets Division, are also reviewed with the Company segments which bring their own expertise. They also integrate studies issued by international agencies, banks and independent consultants. They are then approved by the Executive Committee and the Board of Directors;

-

the IEA’s World Energy Outlook 2025 presents three scenarios that are key references for the Company: the CPS (Current Policies Scenario), the STEPS (Stated Policies Scenario), and the NZE (Net Zero Emissions by 2050) long‑term scenario, as well as APS scenario from the IAE’s World Energy Outlook 2024;

o

the CPS scenario only includes climate actions already implemented to date around the world;

o

the STEP scenario encompasses a broader set of measures, including those that have been officially announced but not yet adopted;

o

The NZE scenario follows a different logic: it is a normative scenario that starts from the objective (net-zero emissions by 2050, without exceeding the CO₂ budget) and then constructs the energy pathways leading to it.

o

As a reminder, the APS 2024 scenario took into account all climate ambitions declared worldwide to date, including NDCs (Nationally Determined Contributions) and carbon-neutrality targets, and was compatible with the Paris Agreement.

-

the IEA's NZE scenario is understood as the set of actions to be taken for the global energy sector to achieve net-zero CO₂ emissions by 2050 and to be compatible with a +1.5°C scenario by 2100. This normative scenario is therefore not predictive of oil demand, and even less so of the price scenarios it proposes, particularly in the medium term (2030). Indeed, this scenario predicts that oil demand will peak in 2024 and decrease by 33% between 2024 and 2035, whereas according to the IEA’s latest projections, oil demand in 2025 would be higher than in 2024 and continue to grow until 2029. According to projections from other energy companies or external consultants, demand is expected to remain broadly stable until 2035 (a plateau around 2027–2033 according to WoodMac);

-

beyond 2030, the oil price trajectory retained by the Company converges in the long term, to the price retained in 2050 by the IEA’s NZE scenario, i.e $25.7₂₀₂₅/b. The prices retained for gas, the transition fuel, stabilize until 2040 at lower levels than current prices before converging towards the IEA’s NZE scenario prices in 2050.

The oil price trajectories adopted by the Company are based on the following assumptions:

-

Oil demand experienced sustained growth post-Covid crisis, accompanying the global economic recovery, which generated strong tensions on energy prices from mid-2021, exacerbated in 2022 by the war in Ukraine. In 2023, global oil demand exceeded its pre‑Covid 2019 level. This increase was stimulated by the lifting of lockdown measures in China, enabling the recovery of industrial activity, particularly in the petrochemical sector, as well as the rise in air travel. In 2025, demand continued to expand, but at a slightly slower rate, reflecting macroeconomic uncertainty and the slowdown in the petrochemical sector. By 2030, oil consumption is expected to keep growing, supported by population growth and rising living standards, particularly in emerging countries. However, this growth is expected to gradually slow down due to moderate global economic growth and the accelerated deployment in some regions of low-carbon substitute technologies. Some recent forecasts anticipate an oil‑demand peak before 2030 in China, while demand for certain petroleum products, such as gasoline and diesel, may already have peaked there. However, increasing oil demand in other Asian countries, particularly India, is partly taking over.

-

On the supply side, after a decade marked by strong U.S. production growth (accounting for 90% of global supply increases), the decision by the OPEC+ group of producers, to begin lifting part of the oil‑production restrictions in May 2025 is reshaping global oil‑supply trajectories. The expected increase in OPEC+ output and the impact of higher tariffs on trade had downward impacts on oil prices.

Brent is trading between $60₂₀₂₅/b and $70₂₀₂₅/b. In 2026, demand is expected to continue rising, and production capacity should be sufficient to meet it, although downward trends on prices may begin in 2026 to weigh on U.S. production levels. In this context, the selected scenario anticipates prices back toward $70₂₀₂₅/b.

-

Beyond 2030, given technological developments, particularly in the transport sector, the growth in oil demand would be low before reaching a plateau, and the selected price scenario decreases linearly to reach $50₂₀₂₅/b in 2040 and then $25.7₂₀₂₅/b in 2050, in line with the NZE scenario.

The average Brent prices over the period 2026-2050 thus stands at $51.8₂₀₂₅/b.

For natural gas, the transition fuel, the price trajectory adopted by the Company is based on the following assumptions:

-

Following the 2022/23 supply shock, natural gas markets underwent a gradual rebalancing in 2024 and 2025. During this period, the supply–demand balance remained tight and prices stayed well above their historical levels. This limited demand growth, particularly in Asian markets that are more price‑sensitive. Global gas demand returned to structural growth in 2024, mainly in Europe and North America, and continued to grow in 2025, albeit at a slower pace. The Company anticipates that in 2026 prices will remain higher than pre‑crisis levels in Asian and European hubs. Thereafter, natural gas demand is expected to be driven by the same fundamentals as oil: rising demand in the Asia‑Pacific region and declining overall natural gas demand in Europe, although LNG demand should grow in Europe due to declining domestic production and ban on Russian gas imports from 2027. Natural gas demand should also be supported by its substitution for coal in power generation and by its role as a flexible, dispatchable source capable of offsetting the intermittency and seasonality of renewable energies. The abundant global gas supply and the upcoming wave of increased liquefied natural gas capacity (expected between 2027 and 2030) are likely to limit the potential for higher gas prices. Beyond 2040, with the rise of renewable energies including battery storage, gas demand is expected to stabilize.

-

Natural gas prices are thus expected to fall from $3.4₂₀₂₅/Mbtu in 2026 to $3.0₂₀₂₅/Mbtu in 2027 in the United States, and then stabilize at these levels until 2040, supported by domestic demand driven by electricity generation, particularly for data centers, and by the growing volumes of LNG exports.

-

In Europe and Asia, due to the rapid increase in LNG offer, prices should generally adjust downward until 2029/2030 in order to stimulate price‑elastic demand, particularly in some Asian countries such as India. However, the partly inelastic nature of domestic U.S. natural gas and electricity demand (gas‑to‑power) may act as a brake on the decline in feedgas prices for LNG terminals, limiting the reduction in LNG prices in Europe in particular, despite rising volumes. As seen in previous market cycles, the continued growth of LNG demand in Europe and Asia should allow the market to rebalance around 2030. Thus, prices in Europe and Asia could fall from $9.7₂₀₂₅/Mbtu and $10.7₂₀₂₅/Mbtu in 2026 to $6.5₂₀₂₅/Mbtu and $7.5₂₀₂₅/Mbtu respectively in 2029/2030, before rising again to $8.0₂₀₂₅/Mbtu and $9.0₂₀₂₅/Mbtu and stabilizing at these levels until 2040. Natural gas prices would then converge in 2050 toward the IEA’s NZE scenario levels: $2.3₂₀₂₅/Mbtu in the United States, $4.1₂₀₂₅/Mbtu in Europe, and $5.0₂₀₂₅/Mbtu in Asia, respectively.

The future operational costs were determined by taking into account the existing technologies, the fluctuation of prices for petroleum services in line with market developments and the internal cost reduction programs effectively implemented.

The determination of value in use also takes into account on all identified assets the impact of their CO₂ emissions. Future scope 1 and 2 emissions of the assets concerned over the life of the assets are valued at $100/t or the applicable price in a given country, if it is higher, incorporating the existing free emission rights scheme in Europe. Beyond 2031, the CO₂ price is inflated by 2% per year.

The future cash flows are estimated over a period consistent with the life of the assets of the CGUs. They are prepared post-tax and take into account specific risks related to the CGUs’ assets. They are discounted using an 7% post-tax discount rate, this rate being the weighted-average cost of TotalEnergies capital estimated from historical market data. This rate was 7% in 2024 and 8% in 2023. The value in use calculated by discounting the above post-tax cash flows using an 7% post-tax discount rate is not materially different from the value in use calculated by discounting pre-tax cash flows using a pre-tax discount rate determined by an iterative computation from the post-tax value in use. These pre-tax discount rates generally range from 7% to 14%.

Asset impairments are subject to sensitivity testing. In particular, upstream assets are tested as follows:

-

decreases of -10% and -20% in the hydrocarbon’s prices, over the duration of the price scenario.

-

consideration of a CO₂ cost applied to future scope 1 and 2 emissions of $200/t, inflated by 2% per year beyond 2031 for all assets.

-

increase or decrease of 1% in the discount rate of future cash flows.

Finally, in 2020, TotalEnergies also reviewed its upstream assets that can be qualified as “stranded”, meaning with reserves beyond 20 years and high production costs, whose overall reserves may therefore not be produced by 2050. The only projects concerned were the Fort Hills and Surmont oil sands projects in Canada that TotalEnergies sold in 2023.

This portfolio management approach, along with TotalEnergies’ strategy of focusing its new oil investments on low‑carbon‑intensity and low‑production‑cost projects, mitigates the risk of having stranded assets in the future if a structural decline in demand for hydrocarbons occurs due to stricter global environmental regulations and constraints and a resulting change in consumer preferences.

The Company will continue to review price assumptions as the energy transition progresses and this may result in additional impairment charges in the future.

The effect of asset impairments on TotalEnergies’ financial statements and the associated sensitivity calculations are detailed in Note 3.C “Asset impairment”.

Exploration assets

The energy transition could affect the future development or economic viability of certain exploration assets.

TotalEnergies applies IFRS 6 “Exploration for and Evaluation of Mineral Resources”. Oil and gas exploration and production properties and assets are accounted for in accordance with the Successful Efforts method.

Exploratory wells are capitalized and tested for impairment on an individual basis as follows:

-

costs of exploratory wells which result in proved reserves are capitalized and then depreciated using the unit-of-production method based on proved developed reserves;

-

costs of exploratory wells are capitalized as work in progress until proved reserves have been found, if both of the following conditions are met:

◾ The well has found a sufficient quantity of reserves to justify, if appropriate, its completion as a producing well, assuming that the required capital expenditures are made;

◾ TotalEnergies is making sufficient progress assessing the reserves and the economic and operating viability of the project. This progress is evaluated on the basis of indicators such as whether additional exploratory works are under way or firmly planned (wells, seismic or significant studies), whether costs are being incurred for development studies and whether TotalEnergies is waiting for governmental or other third-party authorization on a proposed project, or availability of capacity on an existing transport or processing facility.

Costs of exploratory wells not meeting these conditions are charged to exploration costs.

These assets will continue to be carefully reviewed as the energy transition progresses, in line with the resulting capital expenditure allocation policy.

The effect of exploration activities on the financial statements of TotalEnergies is detailed in Note 7.2 “Property, plant and equipment”.

Intangible and tangible assets - depreciation and useful lives

The energy transition may curtail the useful life of oil and gas assets, thereby increasing the annual depreciation charges related to these assets.

The following accounting principles are applied to the hydrocarbon production assets of exploration and production activities:

-

Unproved mineral interests are tested for impairment based on the results of the exploratory activity or as part of the impairment tests of the cash-generating units to which they are allocated.

-

Unproved mineral interests are transferred to proved mineral interests at their net book value as soon as proved reserves are booked.

-

Proved mineral interests are depreciated using the unit-of-production method based on proved reserves. The corresponding expense is recorded as depreciation of tangible assets and mineral interests.

-

Development costs of oil and gas production facilities are capitalized. These costs include borrowing costs incurred during the period of construction and the present value of estimated future costs of asset retirement obligations.

-

The depletion rate of development wells and of production assets is equal to the ratio of oil and gas production for the period to proved developed reserves (unit-of-production method).

In the event that, due to the price effect on reserves evaluation, the unit-of-production method does not reflect properly the useful life of the asset, an alternative depreciation method is applied based on the reserves evaluated with the price of the previous year. This alternative method was not applied as of December 31, 2025, 2024, and 2023 because, given the price used to assess the reserves, the unit-of-production method correctly reflects the useful life of the assets.

With respect to phased development projects or projects subject to progressive well production start-up, the fixed assets’ depreciable amount, excluding production or service wells, is adjusted to exclude the portion of development costs attributable to the undeveloped reserves of these projects.

With respect to production sharing contracts, the unit-of-production method is based on the portion of production and reserves assigned to TotalEnergies taking into account estimates based on the contractual clauses regarding the reimbursement of exploration, development and production costs (cost oil/gas) as well as the sharing of hydrocarbon rights after deduction of cost oil (profit oil/gas).

Hydrocarbon transportation and processing assets are depreciated using the unit-of-production method based on throughput or by using the straight-line method whichever best reflects the economic life of the asset.

Given the characteristics of the Company’s portfolio of oil & gas assets, its current value on the balance sheet will be almost entirely depreciated by 2040.

Consequently, TotalEnergies does not anticipate significant changes in the useful life of its existing oil and gas assets that would represent an element of significant judgment impacting its consolidated accounts in the future.

The impact of the depreciation of oil and gas assets on the financial statements of TotalEnergies is detailed in Notes 7.1 “Intangible assets” and 7.2 “Property, plant and equipment”.

Asset retirement obligations

The energy transition may bring forward asset retirement obligations of certain oil and gas assets, thereby increasing the present value of the associated provisions.

Asset retirement obligations, which result from a legal or constructive obligation, are recognized based on a reasonable estimate in the period in which the obligation arises.

The associated asset retirement costs are capitalized as part of the carrying amount of the underlying asset and depreciated over the useful life of this asset.

An entity is required to measure changes in the liability for an asset retirement obligation due to the passage of time (accretion) by applying a discount rate to the amount of the liability. Given the long-term nature of expenditures related to our asset retirement obligations, the rate is determined by reference to the rates of high quality AA-rated corporate bonds on the USD area for a long-term horizon. The increase of the provision due to the passage of time is recognized as “Other financial expense”.

The discount rate used for the valuation of asset retirement obligation is 5% in 2025, as in 2024 and in 2023 (the expenses are estimated at current currency values with an inflation rate of 2% in 2025, 2024, and 2023).

In upstream activities, in application of its internal procedures, TotalEnergies regularly reviews, on an asset-by-asset basis, the estimate of its future asset retirement costs, as well as the date at which work will be performed. The Company has ensured the consistency of the dates used for these site - restoration activities and the dates used in calculating depreciation of upstream assets with those provided for in the contracts regarding licence expiries and end - of - production, as reflected in the cash - flow forecasts used for impairment testing. The assets and liabilities recognized in respect of retirement obligations under these rules as described in Note 12.1 “Provisions and other non-current liabilities” are adjusted accordingly.

The Company will continue to review its estimates of both costs and the maturity of commitments on a regular basis and will take into account any significant impact that may result from changes in these parameters in the future.

The effect of the asset retirement obligations on the financial statements of TotalEnergies and the associated sensitivity calculations are detailed in Note 12.1 “Provisions and other non-current liabilities”. A maturity schedule of these obligations is presented in Note 13.1 “Off-balance sheet commitments and contractual obligations”.

Ø

Income Taxes

A tax liability is recognized when in application of a tax regulation, a future payment is considered probable and can be reasonably estimated. The exercise of judgment is required to assess the impact of new events on the amount of the liability.

Deferred tax assets are recognized in the accounts to the extent that their recovery is considered probable. The amount of these assets is determined after taking into account deferred tax liabilities with comparable maturity, arising from the same entities and tax regimes. It takes into account existing taxable profits and future taxable profits which estimation is inherently uncertain and subject to change over time. The exercise of judgment is required to assess the impact of new events on the value of these assets and including changes in estimates of future taxable profits and the deadlines for their use.

In addition, these tax positions may depend on interpretations of tax laws and regulations in the countries where TotalEnergies operates. These interpretations may have uncertain nature. Depending on the circumstances, they are final only after negotiations or resolution of disputes with authorities that can last several years.

Incomes taxes and the accounting methods are described in Note 11 “Income taxes”.

Ø

Employee benefits

The benefit obligations and plan assets can be subject to significant volatility due in part to changes in market values and actuarial assumptions. These assumptions vary between different pension plans and thus take into account local conditions. They are determined following a formal process involving expertise and TotalEnergies internal judgments, in financial and actuarial terms, and also in consultation with actuaries and independent experts.

The assumptions for each plan are reviewed annually and adjusted if necessary to reflect changes from the experience and actuarial advice. The discount rate is reviewed quarterly.

Payroll, staff and employee benefits obligations and the method applied are described in Note 10 “Payroll, staff and employee benefits obligations”.

Ø

Russian-Ukrainian conflict

Russian assets were fully impaired in 2022, with the exception of the shares held in the Yamal LNG company. As a reminder, in total, the impact of impairments and provisions recorded in 2022 due to the RussoUkrainian conflict amounted to $(14,756) million in TotalEnergies’ net result.

With regard to TotalEnergies’ interests in Novatek and Arctic LNG 2, the accounting and measurement method remains unchanged as of December 31, 2025 in the absence of any new events: as the criteria for significant influence are no longer met within the meaning of IAS 28 “Investments in associates and joint-ventures”, TotalEnergies' 19.4% interest in Novatek and 10% interest in Arctic LNG 2 have no longer been accounted for using the equity method in the Company's financial statements since the end of the 4^th quarter of 2022 and the end of the 4^th quarter of 2023, respectively.

The Company has also ensured the absence of depreciation to be accounted for on Yamal LNG as of December 31, 2025, by testing the value of its equity accounted investment which amounts to $5,835 million.

Depending on the developments of the Russian-Ukrainian conflict and the measures that the European and American authorities may decide to implement, particularly in terms of sanctions, the activities of TotalEnergies in Russia, in particular those relating to the Yamal LNG asset, could be affected in the future, potentially impacting all or part of the carrying value of its equity interest.

Principles of consolidation

A) Principles of consolidation

Entities that are directly controlled by the parent company or indirectly controlled through other consolidated entities are fully consolidated.

Investments in joint ventures are accounted for by the equity method. TotalEnergies accounts for joint operations by recognizing its share of assets, liabilities, income and expenses.

Investments in associates, in which TotalEnergies has significant influence, are accounted for by the equity method. Significant influence is presumed when TotalEnergies holds, directly or indirectly through subsidiaries, 20% or more of the voting rights. In the case of a percentage of less than 20%, accounting under the equity method applies only when significant influence can be demonstrated.

All internal balances, transactions and income are eliminated.

Foreign currency translation

C) Foreign currency translation

The presentation currency of TotalEnergies’ Consolidated Financial Statements is the U.S. dollar. However, the functional currency of the parent company is the euro. The resulting currency translation adjustments are presented on the line “Currency translation adjustment generated by the parent company” of the consolidated statement of comprehensive income, within “Items not potentially reclassifiable to profit and loss”. In the balance sheet, they are recorded in “Currency translation adjustment”.

The financial statements of subsidiaries are prepared in the currency that most clearly reflects their business environment. It is referred to as their functional currency.

Since July 1, 2018, Argentina is considered to be hyperinflationary. IAS 29 “Financial Reporting in Hyperinflationary Economies” is applicable to entities whose functional currency is the Argentine peso. The functional currency of the Argentine Exploration & Production subsidiary is the U.S. dollar, therefore IAS 29 has no incidence on TotalEnergies accounts. Net asset of the other business segments is not significant.

(i) Monetary transactions

Transactions denominated in currencies other than the functional currency of the entity are translated at the exchange rate on the transaction date. At each balance sheet date, monetary assets and liabilities are translated at the closing rate and the resulting exchange differences are recognized in the statement of income.

(ii) Translation of financial statements

Assets and liabilities of entities denominated in currencies other than dollar are translated into dollar on the basis of the exchange rates at the end of the period. The income and cash flow statements are translated using the average exchange rates for the period. Foreign exchange differences resulting from such translations are either recorded in shareholders’ equity under “Currency translation adjustments” (for TotalEnergies share) or under “Non-controlling interests” (for the share of non-controlling interests) as deemed appropriate.

Divestment projects

2.3 Main divestment projects

Accounting principles

Pursuant to IFRS 5 “Non-current assets held for sale and discontinued operations”, assets and liabilities of affiliates that are held for sale are presented separately on the face of the balance sheet. Depreciation of assets ceases from the date of classification as “Non-current assets held for sale”.

Sales of goods and services, including excise taxes

Accounting principles

IFRS 15 requires identification of the performance obligations for the transfer of goods and services in each contract with customers. Revenue is recognized upon satisfaction of the performance obligations for the amounts that reflect the consideration to which TotalEnergies expects to be entitled in exchange for those goods and services.

Sales of goods

Revenues from sales are recognized when the control has been transferred to the buyer and the amount can be reasonably measured. Revenues from sales of crude oil and natural gas are recorded upon transfer of title, according to the terms of the sales contracts.

Revenues from the production of crude oil and natural gas properties, in which TotalEnergies has an interest with other producers, are recognized based on actual entitlement volumes sold over the period. Any difference between entitlement volumes and volumes sold, based on TotalEnergies net working interest, are recognized in the “Under-lifting” and “Over-lifting” accounts in the balance sheet and in operating expenses in the profit and loss.

Oil and gas delivered quantities that represent production royalties and taxes, when paid in cash, are included in revenues, except for the United States and Canada.

Certain transactions within the trading activities (contracts involving quantities that are purchased from third parties then resold to third parties) are shown at their net value in purchases, net of inventory variation. These transactions relate in particular to crude oil, petroleum products, gas, power and LNG.

Exchanges of crude oil and petroleum products realized within trading activities are shown at their net value in both the statement of income and the balance sheet.

Sales of services

Revenues from services are recognized when the services have been rendered.

Revenues from gas transport are recognized when services are rendered. These revenues are based on the quantities transported and measured according to procedures defined in each service contract.

Shipping revenues and expenses from time-charter activities are recognized on a pro rata basis over a period that commences upon the unloading of the previous voyage and terminates upon the unloading of the current voyage. Shipping revenue recognition starts only when a charter has been agreed to by both TotalEnergies and the customer.

Income related to the distribution of electricity and gas is not recognized in revenues in certain countries because TotalEnergies acts as an agent in this transaction. In these countries, TotalEnergies is not responsible for the delivery and does not set the price of the service, because it can only pass on to the customer the amounts invoiced to it by the distributors.

Excise taxes

Excise taxes are rights or taxes which amount is calculated based on the quantity of oil and gas products put on the market. Excise taxes are determined by the states. They are paid directly to the customs and tax authorities and then invoiced to final customers by being included in the sales price.

The analysis of the criteria set by IFRS 15 led TotalEnergies to determine that it was acting as principal in these transactions. Therefore, sales are presented on a gross basis, including excise taxes collected by TotalEnergies within the course of its oil distribution operations. In addition, the subtotal “Revenue from Sales” is presented as an additional line item in the P&L and is obtained by deducting Excise tax expenses from Sales.

Research and development costs

Accounting principles

Research costs are charged to expense as incurred.

Development expenses are capitalized when the criteria of IAS 38 are met.

Cash flow from operating activities

5.5 Cash flow from operating activities

Accounting principles

The cash flows incurred in currencies other than dollar has been translated into dollars using the exchange rate on the transaction date or the average exchange rate for the period. Currency translation differences arising from the translation of monetary assets and liabilities denominated in foreign currency into dollars using the closing exchange rates are shown in the consolidated statement of cash flows under “Effect of exchange rates”. Therefore, the consolidated statement of cash flows will not agree with the figures derived from the consolidated balance sheet.

Property, plant and equipment

Accounting principles Exploration costs TotalEnergies applies IFRS 6 “Exploration for and Evaluation of Mineral Resources”. Oil and gas exploration and production properties and assets are accounted for in accordance with the Successful Efforts method. Exploratory wells are capitalized and tested for impairment on an individual basis as follows: - Costs of exploratory wells which result in proved reserves are capitalized and then depreciated using the unit-of-production method based on proved developed reserves; - Costs of exploratory wells are capitalized as work in progress until proved reserves have been found, if both of the following conditions are met: ● The well has found a sufficient quantity of reserves to justify, if appropriate, its completion as a producing well, assuming that the required capital expenditures are made; ● TotalEnergies is making sufficient progress assessing the reserves and the economic and operating viability of the project. This progress is evaluated on the basis of indicators such as whether additional exploratory works are under way or firmly planned (wells, seismic or significant studies), whether costs are being incurred for development studies and whether TotalEnergies is waiting for governmental or other third-party authorization on a proposed project, or availability of capacity on an existing transport or processing facility. Costs of exploratory wells not meeting these conditions are charged to “Exploration costs”. Oil and Gas production assets of exploration and production activities Development costs of oil and gas production facilities are capitalized. These costs include borrowing costs incurred during the period of construction and the present value of estimated future costs of asset retirement obligations. The depletion rate of development wells and of production assets is equal to the ratio of oil and gas production for the period to proved developed reserves (unit-of-production method). In the event that, due to the price effect on reserves evaluation, the unit-of-production method does not reflect properly the useful life of the asset, an alternative depreciation method is applied based on the reserves evaluated with the price of the previous year. As of December 31, 2025, 2024 and 2023, this alternative method is not applied as, given the price used to assess the reserves, the unit-of-production method correctly reflects the useful life of the assets. With respect to phased development projects or projects subject to progressive well production start-up, the fixed assets’ depreciable amount, excluding production or service wells, is adjusted to exclude the portion of development costs attributable to the undeveloped reserves of these projects. With respect to production sharing contracts, the unit-of-production method is based on the portion of production and reserves assigned to TotalEnergies taking into account estimates based on the contractual clauses regarding the reimbursement of exploration, development and production costs (cost oil/gas) as well as the sharing of hydrocarbon rights after deduction of cost oil (profit oil/gas). Hydrocarbon transportation and processing assets are depreciated using the unit-of-production method based on throughput or by using the straight-line method whichever best reflects the economic life of the asset.
Other property, plant and equipment Other property, plant and equipment are carried at cost, after deducting any accumulated depreciation and accumulated impairment losses. This cost includes borrowing costs directly attributable to the acquisition or production of a qualifying asset incurred until assets are placed in service. Borrowing costs are capitalized as follows: ● if the project benefits from a specific funding, the capitalization of borrowing costs is based on the borrowing rate; ● if the project is financed by all TotalEnergies’ debt, the capitalization of borrowing costs is based on the weighted average borrowing cost for the period. Routine maintenance and repairs are charged to expense as incurred. The costs of major turnarounds of refineries and large petrochemical units are capitalized as incurred and depreciated over the period of time between two consecutive major turnarounds. Other property, plant and equipment are depreciated using the straight-line method over their useful lives, which are as follows:
● Furniture, office equipment, machinery and tools	3-12 years
● Transportation equipment	5-20 years
● Storage tanks and related equipment	10-15 years
● Specialized complex installations and pipelines	10-45 years
● Buildings	10-50 years

Other investments

Accounting principles

Other investments are equity instruments and are measured according to IFRS 9 at fair value through profit or loss (default option). On initial recognition, the standard allows to make an election to record the changes of fair value in other comprehensive income. For these equity instruments, only dividends can be recognized in profit or loss.

TotalEnergies recognizes changes in fair value in equity or in profit or loss according to the option chosen on an instrument by instrument basis.

For quoted shares on active markets, this fair value is based on the market price.

Earnings per share

Accounting principles

Earnings per share is calculated by dividing net income (TotalEnergies share) by the weighted-average number of common shares outstanding during the period, excluding TotalEnergies shares held by TotalEnergies SE (Treasury shares) which are deducted from consolidated shareholders’ equity.

Diluted earnings per share is calculated by dividing net income (TotalEnergies share) by the fully-diluted weighted-average number of common shares outstanding during the period. Treasury shares held by the parent company, TotalEnergies SE are deducted from consolidated shareholders’ equity. This calculation also takes into account the dilutive effect of share grants and capital increases with a subscription period closing after the end of the fiscal year.

The weighted-average number of fully-diluted shares is calculated in accordance with the treasury stock method provided for by IAS 33. The proceeds, which would be recovered in the event of an exercise of rights related to dilutive instruments, are presumed to be a share buyback at the average market price over the period. The number of shares thereby obtained leads to a reduction in the total number of shares that would result from the exercise of rights.

In compliance with IAS 33, earnings per share and diluted earnings per share are based on the net income after deduction of the remuneration due to the holders of deeply subordinated notes.

Employee benefits obligations

Accounting principles

In accordance with the laws and practices of each country, TotalEnergies participates in employee benefit plans offering retirement, death and disability, healthcare and special termination benefits. These plans provide benefits based on various factors such as length of service, salaries, and contributions made to the governmental bodies responsible for the payment of benefits.

These plans can be either defined contribution or defined benefit pension plans and may be entirely or partially funded with investments made in various non-consolidated instruments such as mutual funds, insurance contracts, and other instruments.

For defined contribution plans, expenses correspond to the contributions paid.

Defined benefit obligations are determined according to the Projected Unit Method. Actuarial gains and losses may arise from differences between actuarial valuation and projected commitments (depending on new calculations or assumptions) and between projected and actual return of plan assets. Such gains and losses are recognized in the statement of comprehensive income, with no possibility to subsequently recycle them to the income statement.

The past service cost is recorded immediately in the statement of income, whether vested or unvested.

The net periodic pension cost is recognized under “Other operating expenses”.

Provisions and other non-current liabilities

12.1 PROVISIONS AND OTHER NON-CURRENT LIABILITIES

Accounting principles

A provision is recognized when TotalEnergies has a present obligation, legal or constructive, as a result of a past event for which it is probable that an outflow of resources will be required and when a reliable estimate can be made regarding the amount of the obligation. The amount of the liability corresponds to the best possible estimate.

Provisions and non-current liabilities are comprised of liabilities for which the amount and the timing are uncertain. They arise from environmental risks, legal and tax risks, litigation and other risks.

Lease contracts

Accounting principles

A lease contract is a contract that grants lessee the right to use an identified asset for a specified period of time in exchange for consideration. At lease inception, an asset corresponding to right of use and a debt are recognized in the lessee’s balance sheet. Carrying value of right of use corresponds to present value of future lease payments plus any direct costs incurred for concluding the contract. Lease debt is recorded as a liability in the balance sheet under financial debts. Rights of use are depreciated over the useful lives applied by TotalEnergies.

Leases that are of short duration or that relate to low value assets are not recorded in the balance sheet, in accordance with the exemptions in the standard. They are presented as off-balance sheet commitments.

Fair value of financial instruments (excluding commodity contracts)

Accounting principles

TotalEnergies uses derivative instruments to manage its exposure to risks of changes in interest rates, foreign exchange rates and commodity prices. These financial instruments are accounted for in accordance with IFRS 9, changes in fair value of derivative instruments are recognized in the income statement or in other comprehensive income and are recognized in the balance sheet in the accounts corresponding to their nature, according to the risk management strategy. The derivative instruments used by TotalEnergies are the following:

- Cash management

Financial instruments used for cash management purposes are part of a hedging strategy of currency and interest rate risks within global limits set by TotalEnergies and are considered to be held for trading. Changes in fair value are systematically recorded in the income statement. The balance sheet value of those instruments is included in “Current financial assets” or “Other current financial liabilities”.

- Long-term financing

When an external long-term financing is set up, specifically to finance subsidiaries, and when this financing involves currency and interest rate derivatives, these instruments are qualified as:

1) Fair value hedge of the interest rate and currency risks on the external debt financing the loans to subsidiaries. Changes in fair value of derivatives are recognized in the income statement, as are changes in fair value of underlying financial debts and loans to subsidiaries.

The fair value of those hedging instruments of long-term financing is included in assets under “Non-current financial assets” or in liabilities under “Non-current financial debt” for the non-current portion. The current portion (less than one year) is accounted for in “Current financial assets” or “Other current financial liabilities”.

In case of the anticipated termination of derivative instruments accounted for as fair value hedges, the amount paid or received is recognized in the income statement and:

● If this termination is due to an early cancellation of the hedged items, the adjustment previously recorded as revaluation of those hedged items is also recognized in the income statement;

● If the hedged items remain in the balance sheet, the adjustment previously recorded as a revaluation of those hedged items is amortized over the remaining life of those items.

In case of a change in the strategy of the hedge (fair value hedge to cash flow hedge), if the components of the initial aggregated exposure had already been designated in a hedging relationship (FVH), TotalEnergies designates the new instrument as a hedging instrument of an aggregated position (CFH) without having to end the initial hedging relationship.

2) Cash flow hedge when TotalEnergies implements a strategy of fixing interest rate and/or currency rate on the external debt. Changes in fair value are recorded in other comprehensive income for the effective portion of the hedging and in the income statement for the ineffective portion of the hedging. When the hedged transaction affects profit or loss, the fair value variations of the hedging instrument recorded in equity are also symmetrically recycled to the income statement.

The fair value of those hedging instruments of long-term financing is included in assets under “Non-current financial assets” or in liabilities under “Non-current financial debt” for the non-current portion. The current portion (less than one year) is accounted for in “Current financial assets” or “Other current financial liabilities”.

If the hedging instrument expires, is sold or terminated by anticipation, gains or losses previously recognized in equity remain in equity. Amounts are recycled to the income statement only when the hedged transaction affects profit or loss.

3) In compliance with IFRS 9, TotalEnergies has decided to recognize in a separate component of the comprehensive income the variation of foreign currency basis spread (Cross Currency Swaps) identified in the hedging relationships qualified as fair value hedges and cash flow hedges.

- Foreign subsidiaries’ equity hedge

Certain financial instruments hedge against risks related to the equity of foreign subsidiaries whose functional currency is not the euro (mainly the dollar). These instruments qualify as “net investment hedges” and changes in fair value are recorded in other comprehensive income under “Currency translation” for the effective portion of the hedging and in the income statement for the ineffective portion of the hedging. Gains or losses on hedging instruments previously recorded in equity, are reclassified to the income statement in the same period as the total or partial disposal of the foreign activity.

The fair value of these instruments is recorded under “Current financial assets” and “Other current financial liabilities”.

- Commitments to purchase shares held by non-controlling interests (put options written on minority interests)

Put options granted to non-controlling-interest shareholders are initially recognized as financial liabilities at the present value of the exercise price of the options with a corresponding reduction in shareholders’ equity – TotalEnergies share. The financial liability is subsequently measured at fair value at each balance sheet date in accordance with contractual clauses and any variation is recorded in the income statement (cost of debt).

Financial instruments related to commodity contracts

16.1 FINANCIAL INSTRUMENTS RELATED TO COMMODITY CONTRACTS

Accounting principles

Financial instruments related to commodity contracts, including crude oil, petroleum products, gas, and power purchase/sales contracts within the trading activities, together with the commodity contract derivative instruments and freight rate swaps, are used to adjust TotalEnergies’ exposure to price fluctuations within global trading limits. According to the industry practice, these instruments are considered as held for trading. Changes in fair value are recorded in the income statement. The fair value of these instruments is recorded in “Other current assets” or “Other creditors and accrued liabilities” depending on whether they are assets or liabilities.

Certain energy derivatives are also held as part of a cash flow hedge for future transactions.

The valuation methodology is to mark-to-market all open positions for both physical and paper transactions. The valuations are determined on a daily basis using observable market data based on organized and over the counter (OTC) markets. In specific cases when market data is not directly available, the valuations are derived from observable data such as arbitrages, freight or spreads and market corroboration. For valuation of risks which are the result of a calculation, such as options for example, commonly known models are used to compute the fair value.