15 Impairments of tangible and intangible assets and right-of-use assets. Sensitivity of outcomes to decarbonization scenarios

Climate change and energy transition

The recoverability test of the carrying amounts of oil&gas cash generating units (CGUs) is the most important of the critical accounting estimates utilized in the preparation of Eni’s consolidated financial statements. This is due to the relative weight of the invested capital in the E&P operating segment on total consolidated assets and because of the highly judgmental nature of assumptions utilized by the management in the impairment review process.

Estimation of future expected cash flows associated with the use of oil&gas assets is based on management’s assessment and subjective assumptions about highly uncertain matters like future hydrocarbons prices, assets’ useful lives, projections of future operating and capital expenditures, the volumes of reserves that will ultimately be recovered and costs of decommissioning oil&gas assets at the end of their useful lives. Furthermore, the recoverability of carrying amounts is still pending on the management’s commitment to allocating funds to develop reserves and hence is subject to possible changes to capital allocation priorities. The hydrocarbon prices are forecasted based on management’s expectations about future trends in demands and supplies of hydrocarbons in the short to the long-term, which incorporate assumptions about the evolution of several scenario variables, including macroeconomic growth, changes in consumers’ preferences, modifications in governments’ regulatory and political framework in response to climate change and preservation of the ecosystem, the pace of the energy transition, the role of technologies, and finally production plans of public oil&gas companies and production policies of the OPEC+ alliance. Eni’s forecast prices are constantly benchmarked against the market view of investment banks and energy consultants. Short-term price forecasts will also incorporate risks and uncertainties of the current macroeconomic outlook and geopolitical factors (like the ongoing crisis in the Middle East and other macroeconomic risks such as the impact of international trade disputes on growth and other factors).

Climate change and the energy transition risk were taken into full consideration as part of the recoverability test of the carrying amounts of oil&gas CGUs, including the evaluation of exploration assets and unproved mineral interests. They may have significant impacts on the value of Eni’s oil&gas properties and on similar properties that may be recognized in the future. Considering the exposure of its oil&gas assets to the transition risk, the Company has adopted strict return criteria when making a final investment decision to mitigate the risks of having stranded assets in the future and of recognizing possible impairment charges in the profit and loss account once a new capital project is capitalized among property, plant and equipment. Each material capital budgeting investment project, including in the exploration and acquisition of oil and gas resources, is subject to an evaluation that takes into consideration the objectives of the Paris Agreement, in view of each new project contributing to enhance the resilience of the Company’s portfolio in terms of reduction of the average carbon intensity and improvement of profitability metrics.

Economic returns and expected cash flows are estimated based on the management’s assumptions about future commodity prices which are set in the industrial plan approved by the Board, as well as management’s forecast of operating and development costs, future production volumes and timing and costs of decommissioning. Furthermore, future cash flows of oil&gas assets discount the expected expenditures to reduce emissions or to have projects already carbon neutral for scope 1&2 emissions from the onset, in line with the Company’s goal of achieving net zero CO2 emissions for scope 1&2 of the whole oil&gas assets portfolio by 2030. The 2026 forecast marginally discounts current geopolitical risks.

As result of this evaluation process and the Company’s focus on value creation and cash generation over volume, Eni’s capital allocation prioritizes new oil&gas projects featuring: (i) low breakeven prices, translating into an average Brent breakeven price of around $35 per barrel for the portfolio of new oil&gas projects; (ii) internal rate of returns “IRR” exceeding an internally defined threshold comprising the cost of the capital to the Group “WACC” of 6% post-tax plus a country risk premium and a further step-up to cover exploration projects and generate an extra-return; (iii) ability to reduce the average carbon intensity of the portfolio (scope 1&2); (iv) resilience to the transition risk, which is measured in terms of change to projects’ IRR when applying an internally estimated cost per emitted ton of CO2 (internal threshold in $/tCO2).

The recent asset rationalization comprising the disposal of certain long-life oilfields characterized by high expected future expenditures and above-average carbon intensity, including Alaska, Nigeria and Congo onshore fields, has further strengthened the risk profile and resilience of the oil&gas portfolio, reducing exposure to assets at risk of becoming stranded in the long-term.

The impairment test of Eni’s oil&gas assets is prepared in coherence with the main technical and economic assumptions of the industrial plan approved by the Board of Directors, including commodity price assumptions.

The principles applied in determining the recoverable amounts of oil&gas CGU are as follows:

- the future cash flows were determined using the assumptions included in the industrial plan 2026-2030 and in the long-term plan of the Company approved by the Board of Directors. These assumptions, including operational costs, development expenditures, estimation of oil and gas reserves, future volumes produced and marketed, and timing and costs of decommissioning oil&gas plants and facilities 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 projections adopted by the Company are based on the following assumptions:

- oil demand experienced sustained growth post-Covid crisis, driven by a global economic recovery, and has continued growing throughout 2025. By 2030, oil consumption is expected to continue to grow, supported by population growth and rising living standards, particularly in emerging countries. Growth after 2030 is expected to be more moderate due to the gradual diffusion of low-carbon technologies. Therefore, in this context of moderate demand growth driven by emerging countries and assuming continued capital discipline on part of the majority of international oil companies, the approaching to maximum sustainable capacity by member countries of the OPEC+ alliance and a levelling off of shale oil production in the United States, our scenario anticipates a gradual recovery in crude oil prices, which are expected to reach $68/bbl in 2026 and then reach $75/bbl by 2030 (all prices in 2025 real terms);

- beyond 2030, we project a linear decline of approximately 1.7% per year, to $65 in 2040 and $53 in 2050 (all prices in real terms 2025), which discounts the risks of energy transition and of a possible slowdown in the growth rate or a contraction in global oil demand post-2030.

The average Brent price over the period 2026-2050 thus stands at $65/bbl in real terms 2025.

For natural gas, the transition fuel, the price projections adopted by the Company assume a less tense global gas market in the coming years. Rising demand, also driven by growing electricity needs particularly in new consumption segments (e.g., data centers, AI), is expected to be accompanied by increased LNG production capacity, with new projects to be completed in the next few years, especially in the United States and Qatar. In this context, the gas prices used to determine the value in use of the CGUs whose revenues are indexed to gas spot prices are as follows (in real terms 2025):

Gas prices for LNG projects and in the Group main geographies are mainly indexed to the price of crude oil.

The future operational costs were determined by considering 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 considers on all identified CGU the expected expenditures to improve energy efficiency and reduce the carbon footprint (CO2 emissions scope 1&2). Furthermore, any residual emissions after the efficiency actions are expected to be offset by carbon credit compensation, the expenses of which are considered in the evaluation of the headroom of the overall Eni’s E&P segment. CGUs in geographies that are part of emission trading schemes include in their respective cash flow future expenses for emission allowances.

The future cash flows are estimated over a period consistent with the life of the CGUs. They are elaborated post-tax and take into account specific risks related to the CGUs’ assets. They are discounted by applying a 6% post-tax discount rate (unchanged from 2024), this rate being the weighted-average cost of the capital to the Group estimated from market data and future projections of the mix of funds employed to finance the invested capital. This rate is adjusted to factor a risk premium specific to each country where the group operates (WACC Adjusted). The value in use calculated by discounting the above post-tax cash flows 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 9% to 15% in the case of assets impaired in 2025.

In applying the methodology described, €564 million of impairment losses were recognized in the 2025 financial statements at assets mainly in Turkmenistan, the United Arab Emirates and USA and gas assets in Italy due to reserve estimate revisions and price effects.

Asset impairments are subject to sensitivity testing. In particular, upstream assets are stress-tested by assuming the following changes in estimation parameters:

- a decrease of 10% in hydrocarbon prices, over the duration of the cash flows projections;

- an increase of 100 basis point in the discount rate of future cash flows;

- consideration of the price curves and CO2 costs of the IEA’s Net Zero Scenario 2050 for all assets.

Table of Contents

The sensitivities scope includes the activities of Eni subsidiaries and joint ventures driven by Eni; the assets of the independent equity-owned entities Vår Energi ASA, Ithaca Energy Plc, and Azule Energy Holdings Ltd are excluded, as are assets held for sale (Indonesia, Congo, a stake in Ivory Coast, and certain assets in the UAE).

The sensitivities do not consider potential value recovery actions, such as rescheduling and/or cancellation of planned development activities, contract renegotiations, cost effects, or actions to accelerate the payback period. The sensitivity analysis was not applied to the business line of gas-fired power generation plants, due to the insignificant carrying amounts of tangible assets (€887 million) and their residual economic-technical lives, and to the Biorefining business line (€2,711 million) that is not exposed to transition risk. No impact can be associated with refineries and petrochemical plants, given that their carrying amounts have been completely impaired.

The characteristics of Eni’ s portfolio, the fast-track and phased development approach in producing reserves and absence of exposure to unconventional projects mitigate 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.

Given the characteristics of the Company's oil and gas assets, their stated amounts in the balance sheet will be almost entirely amortized by 2035. Accordingly, Eni does not anticipate significant changes in the useful lives of its existing oil and gas assets that could represent a significant valuation factor with an impact on its consolidated financial statements in the future.

Other assets exposed to transition risk, including refineries and petrochemical plants, were completely written down in previous years and are largely undergoing industrial conversion and reconfiguration processes, requiring new investments that will be capitalized when incurred in future reporting periods. Any decommissioning provisions are recognized for permanently closed refining plants and petrochemical complexes, whose conversion is deemed uneconomical. In 2025, the only Versalis CGU with a book value related to the polyethylene plants (€151 million) and was completely impaired.

Other risks

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 liability. Given the long-term nature of expenditures related to our asset retirement obligations, the rate is determined by reference to the rates of treasury bonds having comparable duration as that of the liability. 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 ranged 2-5.2% in 2025, slightly lower in 2024 for the U.S. dollar, higher for the euro (expenses are estimated at current currency values with an inflation rate between 2% and 2.4%).

The provision is sensitive to the number of discounting years. Given that the assumptions adopted represented management’s best estimates of the timing of decommissioning and asset retirement, assuming that the cost incurrence is brought forward by five years compared to the statutory assumption to account for transition risk, this would result in an increase in the provision’s book value of approximately €1.2 billion.

In upstream activities, in application of its internal procedures, Eni 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 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.

A maturity schedule of these obligations is presented in Note 28 - Guarantees, commitments and risks.