This section is the Company’s analysis of its financial performance and of significant trends that may affect its future performance. It should be read in conjunction with the Consolidated Financial Statements and related Notes thereto included in Item 18. The Consolidated Financial Statements are prepared in accordance with International Financial Reporting Standards as issued by the IASB. This section contains forward-looking statements, which are subject to risks and uncertainties. For a list of important factors that could cause actual results to differ materially from those expressed in the forward-looking statements, see the cautionary statement concerning forward-looking statements on page ii. Basis of preparation Eni is a diversified energy company, operating in several jurisdictions across all continents. It engages in exploration, development, production and trading of oil, gas and LNG, in the businesses of new energies including electricity production from renewable sources and biofuels manufacturing, the refining of crude oil and marketing of refined products and the production of plastics both from oil-based feedstock and from renewable feedstock. For financial reporting purposes and considering how the chief operating decision maker is assigning profit responsibilities and assessing managerial performance and capital allocation processes, Eni reportable operating segment have been identified as follows: - Exploration & Production, which is integrating results of the E&P operating segment with those of activities of marketing, shipping and trading of oil and products to enhance synergies and to fully capture margins across the value chain; - Global Gas & LNG Portfolio and Power, which is integrating results of the operating segment Global gas, power and LNG portfolio with those of the activities of managing and upgrading the fleet of gas-fired power plants which are ancillary to gas and power supply and trading activities; - Enilive: this operating segment engages in the manufacturing of biofuels at the operated Italian plants of Venice and Gela and through the Chalmette JV in the USA, whilst advancing expansion plans in Italy and South-East Asia. It manages a network of refueling service stations in Italy and selected European markets, also providing services and non-fuel products to drivers. It also markets fuels through other channels (resellers, ports, airports, etcetera); - Plenitude engages in the activities of retail marketing of gas, power and related services, with a customer base of about 10 million retail points of delivery (gas and electricity) in Europe (of which 8 million were in Italy) as of December 31, 2025. It engages in the renewable energy business (solar photovoltaic and wind facilities both onshore and offshore), which comprises building, commissioning, and managing renewable energy producing installations and managing and expanding a network of charging points for electric vehicles throughout the European territory; - Refining and Chemicals: this reportable segment aggregates the results of the refining business and those of the chemicals business managed by Eni’s subsidiary Versalis. The Refining business engages in refining crude oil to manufacture fuels and in wholesale marketing activities, which mainly consist of the inter-company supply of refined products to the Group subsidiary Enilive and in sales to large accounts. The Chemical business engages in the production and marketing of basic petrochemical products, plastics and elastomers. Versalis is developing the business of manufacturing chemical products from renewable raw materials, bioplastics and bio-based products through the recently acquired subsidiary Novamont. Activities are concentrated in Italy and in Europe. The results of operations of the Refining business and the Chemical business have been combined in a single reporting segment because the businesses exhibit similar economic characteristics; - Corporate and Other activities: include the costs of the main business support functions, as well as, the results of the Group environmental clean-up and remediation activities performed by the subsidiary Eni Rewind and of the businesses engaged in developing the projects for CO2 capture and storage and/or utilization and agricultural hubs to ensure supply of bio-feedstock to the Group’s biorefineries. Operating results 2025 trading environment The 2025 trading environment negatively affected the Company’s results of operations and cash flow for the year, mainly due to a decline in the price of Brent crude oil and the appreciation of the EUR vs the USD. The price of the Brent benchmark crude oil, the main driver of the Group’s results of operations, was 69 $/bbl on average in the year and declined significantly from the average value of 81 $/bbl recorded in 2024, down by about 15%. Crude oil prices have gradually weakened from the second quarter of the year, driven by an uncertain macroeconomic backdrop due commercial disputes triggered by the decision of the US administration to impose import tariffs on its main trading partners and the related risks of an economic slowdown and other geopolitical risks. In the same period, supply growth has been outpacing demand rise due to continuing production gains in non-OPEC countries, notably the US, Canada, Brazil and Guyana, while the eight voluntary members of the OPEC+ DoC started unwinding the production cuts made in previous years to support prices. Both the International Energy Agency “IEA” and official statistics from the US government estimated that oil production exceeded consumption by around 2 mmbbl/d in 2025, with the surplus set to widen further in 2026. An uncertain macroeconomic outlook and the perceived build-up in supplies triggered a continued sell-off of future contracts by financial operators, driving down the price of the commodity. Early in January 2026, crude oil prices touched the lowest level in more than five years, with the Brent crude falling to around 60 $/bbl. From that point onwards, crude oil prices have been improving steadily, recovering to more than 100 $/bbl by start of March 2026 driven by better-than-expected macroeconomic data and escalating tensions in the Middle East. 92 Table of Contents The outlook for 2026 remains uncertain due to projections of weak economic activity in China and Europe, as well as forecast of continued supply additions in the USA, Canada, Guyana, Brazil and other geographies, an improved political landscape in Venezuela which could open the Country’s oil sector to investments from foreign companies to increase production, and the stated intent by the OPEC+ plus alliance to return to the market all members’ available spare capacity. Factoring the described trends, the geopolitical risks related to ongoing tensions in the Middle East and the protraction of Russia’s military aggression of Ukraine and assuming a moderate macroeconomic growth, the management estimates crude oil prices at 70 $/bbl for the year 2026 (nominal terms). Under this pricing assumption, we expect to increase oil and gas production at a rate consistent whit our growth target in the 2026-2030 planning period envisaging a compounded average growth rate of around 4%. As discussed in Item 3-Risk factors, the Group results of operations are exposed to the variability of crude oil prices and the other scenario variables described herein. In 2025, natural gas prices at the main European hubs were substantially in line with the previous year, albeit on a downward path due to continuing production ramp-ups and additions to LNG capacity in the US where production and export volumes have both reached all-time highs. Furthermore, gas production increased in other geographies like China, which is a net importer, while Canada which has large gas surpluses, entered the LNG export market. Supply additions and growing worldwide LNG flows also due to lower imports from China helped European gas-consuming countries to replace large volumes of gas previously imported from Russia via pipeline with little price volatility. Those developments resulted in gas prices at the main European hubs declining during the seasonal consumption peak of the last quarter, when prices normally rise. Due to recent developments in Middle East, we expect a high degree of volatility in the European gas market for 2026. Looking forward, we believe that gas prices will resume their downward trend as more LNG supplies come online. Margins of petrochemicals products have been negatively and significantly affected by the European economic downturn and low growth of the Chinese economy, as well as the cost disadvantages of the European manufacturing sector due to comparatively higher expenses for feedstock and energy inputs, and environmental charges than in competing geographies and lack of scale against the backdrop of global overcapacity fueling continued price competition. We expect that an ongoing restructuring of our chemical business will start showing in 2026 results to partly offset a continued challenging environment. On a positive side, margins of refined products improved from the second half 2025 due to several plant outages worldwide, reduced exports of refined products from Russia due the consequences of the war with Ukraine and increased sanctions from Western countries, and other market imbalances. Furthermore, margins of manufactured biofuels rebounded from the depressed level of 2024 due to better final prices. Finally, the appreciation of the Euro vs the USD exchange rate (down by 7% for the yearly average and by 15% for the closing rate) negatively affected the reported amounts of revenues, earnings and cash flows at dollar-denominated subsidiaries, as well as reduced the Group net equity. 2025 2024 2023 Average price of Brent dated crude oil in U.S. dollars (1) 69.06 80.76 82.62 Average price of Brent dated crude oil in euro (2) 61.12 74.64 76.43 Average EUR/USD exchange rate (3) 1.130 1.082 1.081 Spot gas price at the Italian PSV (4) 39 36 42 Standard Eni Refining Margin (SERM)(5) 7.3 5.1 8.1 Euribor - three month euro rate % (3) 2.18 3.57 3.43 (1) Price per barrel. Source: S&P Global Energy. (2) Price per barrel. Source: Eni’s calculations based on S&P Global Energy data for Brent prices and the EUR/USD exchange rate reported by the European Central Bank (ECB). (3) Source: ECB. (4) €/MWh natural gas prices. Source: ICIS European Spot Gas Markets. (5) In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations. 93 Table of Contents Key consolidated financial data 2025 2024 2023 (€ million) Sales from operations 82,151 88,797 93,717 Operating profit (loss) 5,010 5,238 8,257 Adjusted operating profit (Non-GAAP measure) (1) 8,344 10,348 13,805 Net profit (loss) attributable to Eni 2,608 2,624 4,771 Adjusted net profit (Non-GAAP measure) (1) 4,989 5,257 8,322 Net cash provided by operating activities 13,330 13,092 15,119 Capital expenditures 8,647 8,485 9,215 Acquisitions 878 2,593 2,592 Disposal of assets, consolidated subsidiaries and businesses 1,383 2,788 596 Shareholders’ equity including non-controlling interest 52,787 55,648 53,644 Finance debt (including lease liabilities) 34,164 36,801 34,065 Net borrowings excluding lease liabilities (1) 9,386 12,175 10,899 Net profit (loss) attributable to Eni fully diluted (€ per share) 0.78 0.78 1.40 Dividend per share (€ per share) 1.05 1.00 0.94 Ratio of finance debt (including lease liabilities) to total shareholders’ equity plus finance debt (including lease liabilities) 0.39 0.40 0.39 Gearing before lease liabilities ex IFRS 16 (1) 0.15 0.18 0.17 __________ (1) For a discussion of the usefulness and a reconciliation of these non-GAAP financial measures with the most directly comparable GAAP financial measures see – "Non-GAAP measures of performance" and "Liquidity and capital resources – Financial Conditions" below. Executive summary In 2025, the Company’s results of operations and cash flows were negatively affected by an unfavorable trading environment driven by a steep decline in crude oil prices, which remained the key factor in determining the Company’s profitability, and to a lesser extent the appreciation of the EUR vs the USD. The average price of Brent benchmark crude oil fell by 15% in 2025 compared to 2024, down to 69 $/bbl on average (from 81 $/bbl in 2024). The downtrend in crude oil prices was caused by an uncertain macroeconomic outlook and by a continuing deterioration in market fundamentals due to supply growth outstripping demand additions. The 2025 Group results were also affected by subdued natural gas prices and declining margins of commodity plastics. On a positive note, refining margins were helped by market dislocations and several plant outages on a worldwide scale, while the businesses of renewable power and of biofuels performed steadily. A negative trading environment was further compounded by the devaluation of the USD dollar vs the EURO. The movement in EUR/USD exchange rate reduced the reported amounts of earnings at Eni Group dollar-denominated subsidiaries when translating their financial statements in Euros. The management estimated that the decline in crude oil prices reduced the Group financial performance in 2025 as follows:  Operating profit by an estimated €1.9 billion;  Net cash provided by operating activities “operating cash flow” by an estimated €1.6 billion. 94 Table of Contents The Group consolidated net profit attributable to Eni’s shareholders for 2025 was €2.61 billion, and was almost flat y-o-y. Considering market headwinds, management believes that the Group recorded a solid performance in 2025 driven by several initiatives to withstand the impact of lower crude oil prices and of other exogenous factors. Those initiatives comprised working capital optimizations, cost cutting measures, capital discipline, portfolio management and other actions intended to optimize the Company cash-outs or accelerate the cash conversion cycle of revenues. Particularly, management leveraged its “satellite strategy” to valorize the Group subsidiaries which have been engaging in developing the businesses of renewables energies and of manufacturing biofuels, via direct investments in the share capital of such subsidiaries by private equity funds, interested in gaining exposure to such businesses. As part of this, in 2025 the Group completed two very important transactions. The first related to an equity investment made by KKR in Eni’s subsidiary Enilive, which engages in the manufacture of biofuels and in the retail marketing of fuels and services to drivers, with the acquisition of a 30% interest resulting in cash proceeds of about €3.6 billion to Eni. A similar transaction was closed in relation to Plenitude, which is the other subsidiary of Eni engaging in the business of the new energies including the production of renewable power, where Ares made a 20% direct equity investment in Eni’s subsidiary share capital for cash proceeds of €2 billion to Eni. Both transactions did not have any impact on profit because they were recognized as transactions between owners. Those transactions were part of the Group portfolio management for the year which also included the disposal for €1.1 billion of a 30% interest in the operated Baleine oilfield off Cote d’Ivoire, which was brought online from one of our exploration discoveries where we retained high working interest. This latter disposal was part of our dual exploration model designated to accelerate reserves monetization by selling part of our high working interests in exploration assets. Despite a weak trading environment, the operating cash flow was a healthy €13.3 billion driven by solid results at E&P on the back of production growth and cost efficiencies, the contribution of the gas trading arm, steady performances at our transition-related satellites, Enilive/Plenitude, and several cash optimizations to improve working capital needs. Those cash inflows were utilized to fund our organic growth capital projects for €8.6 billion and to return €5 billion of cash to shareholders via dividends (about €3.1 billion) and the execution of a share buy-back program for 2025 (€1.9 billion, also including completion of previous year program), which has been expanded in the course of the year from an originally planned €1.5 billion to a revised €1.8 billion in consideration of the Campany’s progress in deleveraging the balance sheet. After funding other financing needs, the surplus cash was utilized to reduce net borrowings which fell from €12.2 billion to about €9.4 billion at 2025 year-end. Net borrowing is a non-GAAP financial measure tracked by management to evaluate the soundness of the Company’s balance sheet and financial structure (see glossary for a definition of Net borrowings and the paragraph “liquidity and capital resources” for a reconciliation of net debt with the most comparable GAAP measure)., 95 Table of Contents Reported earnings In 2025, the Group earned €5 billion of reported operating profit, translating to net profit pertaining to Eni’s shareholders of €2.61 billion after interest expense, income from investments and taxes. The 2025 operating profit was down by approximately €0.2 billion due to the E&P operating segment mainly on the back of unfavorable commodity and currency trends, partly offset by volume growth, lower expenses and lower identified items. Lower income taxes, but higher interest expense and reduced results at equity accounted entities and other investments translated into an overall improvement of about €0.2 billion, thus bringing net profit attributable to Eni’s shareholders unchanged year-on-year. NON-GAAP measures of performance: adjusted operating profit and adjusted net profit Adjusted operating profit (loss) and adjusted net profit (loss) are calculated by excluding the following items from the reported results: inventory holding gains or losses and identified gains and losses or extraordinary items (pre and post-tax, respectively) that in management’s view and results assessment do not reflect business base performance. Extraordinary items recognized in 2025 mainly comprised asset impairments at the E&P operating segment (around €1.1 billion pre-tax), environmental provisions (€0.56 billion), impairment losses at other businesses (€0.5 billion), risk provisions (€0.3 billion) mainly relating to a dispute with the Italian Antitrust Authority, for an overall net positive adjustment of €2.4 billion net of tax effects and including a revaluation of deferred tax assets and a post-tax inventory holding loss. Those same items categories amounted to a net positive adjustment of €2.6 billion in 2024. Management is excluding the above mentioned identified items from reported results when evaluating the Group and each operating segment’s underlying performance. By doing so, the management is determining and utilizing non-GAAP measures of financial performance, defined as “adjusted operating profit” and “adjusted net profit”. Management believes that those non-GAAP measures of financial performance furnish valuable information to investors and users of financial reports because the identified items excluded from the GAAP measures to determine the adjusted results are intrinsically difficult to forecast and are influenced by several factors like possible permitted accounting choices, the modalities whereby assets are increased by organic development vs acquisitions, evolution in the operating environment influencing the timing of recognition of expenses and provisions, and managerial decisions and judgement. Furthermore, we understand that those non-GAAP measures are utilized by other oil&gas companies, which are removing the same items as the ones identified by our Company from reported results, and this facilitates comparison of performances across the industry. Finally, we note that we have consistently applied those adjustments to our results for several reporting years, by this way preserving comparability of our performance as measured in terms of adjusted results over time. A summary reconciliation of Group’s reported results vs adjusted results for the three-year period 2023-2025 is provided below: Year ended December 31, 2025 2024 2023 (€ million) GAAP operating profit (loss) 5,010 5,238 8,257 Inventory holding (gains) and losses 745 434 562 Identified net (gains) losses 2,589 4,676 4,986 Total net items in operating profit 3,334 5,110 5,548 Non-GAAP operating profit (loss) 8,344 10,348 13,805 GAAP net profit (loss) 2,608 2,624 4,771 Inventory holding (gains) and losses, post tax 508 308 402 Identified net (gains) losses, post tax 1,873 2,325 3,149 Total net items in net profit 2,381 2,633 3,551 Non-GAAP net profit (loss) 4,989 5,257 8,322 96 Table of Contents The Group underlying performance – i.e. excluding the identified gains and losses as well as the inventory holding loss – was an adjusted operating profit of €8,344 million compared to €10,348 million in 2024, down by approximately 19% or €2 billion. This performance reflected the lower contribution by (i) the E&P segment (down by €1.7 billion) due to a negative trading environment reflecting a decline in crude oil prices y-o-y (down by 15%) and the appreciation of the EUR/USD rate (up by 4%), partly offset by higher hydrocarbon production volumes, lower expenses as well as cost efficiency initiatives. Other businesses performed in line or better than 2024: (i) the GGP and Power segment contribution (up by €0.13 billion) reflected continued value maximization from gas portfolio optimization, offsetting a negative scenario; (ii) Enilive increased the results (up by €0.11 billion) driven by a recovery in bio-margins and higher volumes processed. The Chemical business (was negatively affected by a challenged trading environment and reported a loss of €0.82 billion, in line with the loss reported in 2024), and finally an adjusted operating loss was reported at the Refining business (with €0.1 billion, slightly better than 2024). Excluding identified items and the inventory evaluation profit, adjusted net profit for 2025 was €4,989 million, a €268 million decrease compared to €5,257 million reported in 2024. The result was driven by a lower operating performance, lowering contribution from equity accounted entities driven by the negative commodity scenario partly offset by better operating and volume performances. The Group tax rate, excluding identified items (see paragraph “Taxes” of this item), was 44% and was lower than in 2025 (52% in 2024) due to a better geographical mix of profits before taxes in E&P reflecting higher contribution from jurisdictions with lower-than-average tax rates also as result of portfolio rationalization and as several exploration projects were matured to FID enabling the recognition of the tax benefits associated with previously incurred exploration expenses. Breakdown of identified items In 2025, identified items amounted to a total positive adjustment of €3,334 million in operating profit and of €2,381 million in net profit, including an inventory pre-tax loss of €745 million (€508 million post-tax) relating to oil and refined products. Those items mainly comprised: (i) impairment losses of €1.1 billion in the Exploration & Production segment mainly driven by the alignment of disposal groups to their sale prices and downward reserves revisions and price effects at other oil&gas assets; (ii) the write-down of capital expenditures made for compliance and stay-in-business at certain CGUs with expected negative cash flows in the Refining business (€0.25 billion); (iii) impairment losses of chemical plants driven by a reduced profitability outlook because of continuing margins deterioration (€0.2 billion); (iv) environmental and remediation provision of €0.56 billion which were recorded for about €0.17 billion by our subsidiary managing environmental remediation activities at dismissed Italian plants, €0.13 billion by the refining business and €0.17 billion by the chemicals business; (v) provisions for redundancy incentives (€0.72 billion) (vi) risk provisions (€0.3 billion) mainly relating to a proceeding pending before the Italian Antitrust Authority (AGCM) regarding the business of retail sales of biofuels. These items were partly offset by the reclassification of the negative balance of €0.33 billion in relation to exchange rate differences and derivatives, and by the net gains on disposal assets mainly in the upstream business (€0.03 billion). Furthermore, the tax item included about €0.38 billion of write-up of deferred tax assets due to improved profitability prospects of Italian subsidiaries. 97 Table of Contents For a breakdown of identified gains and losses by business segments, refer to the reconciliation of the Non-GAAP measures to the most comparable performance measures calculated in accordance with IFRS, in the Operating profit (loss) by segment section. The table below sets forth details of the identified gains and losses included in the net results during the period presented. Year ended December 31, 2025 2024 2023 (€ million) Identified gains and losses of operating profit (loss) 2,589 4,676 4,986 - environmental charges 560 900 648 - gains on an environmental agreement with an Italian operator (869) - impairment losses, net 1,582 2,900 1,802 - impairment of exploration projects 140 - net gains on disposal of assets (21) (38) (11) - risk provisions 325 44 39 - provision for redundancy incentives 72 73 158 - effects of fair-valued commodity derivatives (26) 1,056 1,255 - exchange rate differences and derivatives (334) 258 (16) - other 431 212 1,111 Net finance (income) expense 279 (155) 30 of which: - exchange rate differences and derivatives reclassified to operating profit (loss) 334 (258) 16 Net (income) expense from investments (158) (319) (698) of which: - gain on the GIP deal in CCS activities (73) - gain on the SeaCorridor deal (834) - gain on the divestment of a 10% stake in Saipem (166) - net gain on the divestment of upstream assets (373) Income taxes (790) (1,941) (1,180) Total non core gains and losses of net profit (loss) 1,920 2,261 3,138 Attributable to: - non-controlling interest 47 (64) (11) - Eni's shareholders 1,873 2,325 3,149 Cash flow and net borrowings Group’s results of operations in 2025 drove a cash flow from operating activities “CFFO” of €13.3 billion, €0.24 billion higher than in 2024 and included €1.79 billion of dividends paid by equity-accounted and other non-controlled entities. Cash inflows of the year funded capital expenditures of €8.6 billion to pursue Group’s development projects and to sustain oil&gas production, leaving a surplus of about €4.7 billion that was utilized to fund part of cash returns to Eni’s shareholders of €5 billion, consisting of €3.1 billion of dividends and stock repurchases of €1.9 billion. The stock repurchases comprised completion of the 2024 buy-back program and over 80% of the 2025 buy-back program of at least €1.8 billion. This latter was completed in February 2026. Cash flow from divesting activities net of funds deployed for acquisitions ensured a surplus of around €6.3 billion. The main 2025 dispositions included the disposals of noncontrolling interests in consolidated subsidiaries relating to a 30% investment of private equity fund KKR into Enilive for €3.57 billion, a second investment tranche (2.4%) of the EIP fund into Plenitude (€0.21 billion) and a 20% investment by Ares Fund into Plenitude (€2 billion) as well as asset disposals (€1.38 billion) mainly relating to the sale of a 30% stake in the Baleine project and other non-strategic fields in Congo. Those inflows were partly offset by funds for acquisitions (for overall €0.9 billion) and mainly related to the expansion of renewable generation capacity at Plenitude (€0.5 billion), to acquisition of additional interest in upstream assets (€0.2 billion) as well as to the expansion of the agri-business activity (€0.1 billion). As a result of those cash movements and including the repayment of lease liabilities and the incurrence of finance debt in connection with supplier finance agreements, GAAP finance debt including lease liabilities was €34.2 billion at December 31, 2025, about €2.6 billion higher than at the end of 2024. Group net borrowings (Non-GAAP measure – see Glossary) decreased by €2.8 billion to €9.4 billion. The management’s tracked measure of financial structure – gearing (ratio of net borrowings to shareholders equity plus net borrowings – see glossary) came in at 0.15. This was remarkable considering that the USD devaluation reduced total equity by an estimated amount of €6 billion equivalent to around one point and half of gearing. For a discussion of use on Non-GAAP measures relating to finance debt, net borrowings and capital ratios see paragraph “Liquidity and capital resources” below. 98 Table of Contents Critical accounting estimates 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 Company through long-standing approval guidelines and internal procedures and controls. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Headquarter Reserve Evaluators which have significant technical experience, culminating in reviews with and approval by senior management. Key features of the reserve estimation process are covered in Disclosure of Reserves in Item 4. Oil and natural gas reserves include both proved and unproved reserves.  Proved oil and natural gas reserves are determined in accordance with U.S. 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 Company 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. 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, as well as management’s re-prioritization of capital commitments. A downward revision in proved reserves normally results in higher amortization charges to profit and loss due to the unit-of-production method and reduces future production levels. It can also trigger a reduction in the recoverable amounts of underlying assets with possible recognition of an impairment loss. In 2025, the Company recognized about €570 million of impairment losses at Italian gas-producing assets and at minor assets in Turkmenistan, the United Arab Emirates and the USA due to downward reserve revisions considering that those were mature fields subject to more frequent reserves revisions due to reassessment of available data. Unit-of-Production Depreciation Oil and natural gas proved reserve volumes are used as the basis to calculate unit-of-production depreciation rates for most E&P 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. In case of phased development projects where plants and production facilities like common treatment centers, and FPSO and FLNG vessels have technical lives that exceed the expected duration of proved reserves (both developed and undeveloped), in addition to proved reserves the Company includes in the ratio volumes of probable reserves in determining the UOP rate to obtain a more equitable apportionment of the asset cost over the economic life of the underlying reserves. The volumes produced and asset cost are known, while reserves used in determining the UOP rate are based on estimates that are subject to some variability. To the extent that proved reserves for a property are substantially de-booked because they are uneconomic at the prices determined in accordance with the US SEC rules, 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, the Company might apply an alternative estimation technique to determine the UOP rate. In such circumstances, the rate includes volumes of reserves estimated with regard to economic viability parameters, reasonable and consistent with management’s expectations of production, in order to recognize depreciation charges that result in a more equitable allocation of cost over the economic life of an upstream asset than being fully amortized at the time of reserve de-booking. 99 Table of Contents 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. In respect of the recently completed acquisitions (particularly in 2024), the most significant amount of judgment involved the estimated fair values of property, plant and equipment related to crude oil and natural gas properties and to renewable electricity generation assets 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 our internal plans, drilling, development and maintenance costs, estimations regarding future availability of generation assets and risk-adjusted discount rates. The assumptions and inputs incorporated within the fair value estimates are subject to considerable management judgement and are based on industry, market, and economic conditions prevalent at the time of the acquisition. Actual results may differ from the projected results used to determine fair value. See Note 4 for further information regarding the acquisitions made during 2025. Impairment The Company tests assets (i.e. property, plant and equipment “PP&E”) 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. Goodwill carrying amounts are tested annually, independently from the evidence of impairment indicators. The Company has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. However, considering the volatility of the trading environment and the fact that the Company engages in a commodity business, the management performs the recoverability test of fixed assets’ net book values at least once a year, also in cases when there is no evidence of impairment indicators. This process relies mostly on the Company’s planning and budgeting cycle. The recoverability test of the carrying amounts of oil and gas properties is the most critical accounting estimates in the preparations of the Company’s financial statements due to materiality of stated amounts (oil&gas assets represents about 80% of the item PP&E) and because the estimation of assets’ value-in-use is highly judgmental and relies on management’s forecasts of highly uncertain variables, like long-term commodity prices. Because the lifespans of the vast majority of the Company’s oil&gas 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 management’s view of oil or natural gas commodity prices or margin ranges, and changes in the development plans, including decisions to defer, reduce, or eliminate planned capital spending, can be an indicator of potential impairment, as well as an increase in the discount rate. Among these, forecasts of long-term crude oil and natural gas prices are the most important assumptions because they are the primary drives of asset’s future net cash flows. In general, the Company does not view temporarily low realized prices as an indication of market imbalances that warrant a revision to the Company’s long-term pricing assumptions, which are the single, most important variables in determining the future net cash flows of oil&gas properties. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices 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 Company expects that oil and gas prices will experience significant volatility. Consequently, these assets will experience periods of higher earnings and periods of lower earnings, or even losses. In 2025, operating profit of the Company’s E&P operating segment fell 6% y-o-y driven by lower crude oil prices due to an oversupplied market. However, the Company believes that current imbalances are of short-term nature and therefore the management has retained its long-term price assumptions which are mostly unchanged from the previous year. Therefore, in 2025 the Company recognized €1.08 billion of impairment losses at its oil&gas assets which were primarily driven by factors other than long-term prices, like reserves revisions and disposal effects. 100 Table of Contents When updating the recoverability test of the carrying amounts of oil&gas assets, the management generally relies on the estimation of assets’ values-in-uses, considering the difficulty in obtaining information about assets’ fair values. 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 budget and mid-term 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 Company’s assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, production volumes, development and operating costs including greenhouse gas emission prices and expenses planned to meet the Company’s emissions reduction targets. Notably, when assessing future cash flows, the Company includes the estimated costs in support of reaching its 2030 greenhouse gas emission-reduction plans, including its goal of net-zero Scope 1 and 2 emissions at all oil&gas properties by that timeline. Volumes are based on projected fields and facility production profiles. 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. Cash flow projections net of the related tax effects are then discounted to determine the net present value of those cash flows. The discount rate is a post-tax discount rate that approximates the one a market participant would utilize in estimating the net present value of assets similar to those owned by the Company. The Company utilizes post-tax cash flows and discount rates because it has estimated they would yield the same result as a pre-tax estimation. In assessing the recoverability of the carrying amounts of its oil&gas assets the Company has adopted the following pricing assumptions, which remained largely unchanged from the previous assessment: 2026 2028-2030 2040 2050 Brent crude oil price $/bbl real terms 2025: 68 75 65 53 Regarding natural gas properties which revenues are indexed to spot prices at European hubs our assumptions reflect a high degree of volatility in the short-term while remaining unchanged in the longer term, as follows: 2026 2028-2030 2040 2050 Natural gas spot prices at TTF $/mmBTU real terms 2025: 11.8 7.9 7.6 6.9 Therefore, having retained its pricing assumptions substantially unchanged, in 2025 the Company recognized certain impairment losses which were mainly driven by downward reserves revisions as explained before. Considering the highly judgmental nature of the assumptions underlying the recoverability of the carrying amounts of oil&gas properties, particularly long-term pricing assumptions, the Company stress-tested the outcome of its impairment review by applying a “haircut” of 10% to its pricing assumptions across all years of financial projections at each asset or group of asset as well as a one percentage point increase in the discount rate “weighted average cost of capital” WACC, holding all other factors constant, with the following impacts: Possible estimated impairment losses (cumulative amount) (€ billion) -10% to Brent prices (1.0) +100 b.p, increase to WACC (0.2) Other stress tests of the recoverability of E&P assets are disclosed in Note 15 to the Consolidated Financial Statements. An asset or an asset group is impaired if its estimated cash flows discounted at a rate reflective of the cost of the capital to the Group are less than the carrying values. Impairments are measured by excess of the carrying value over value-in-use or fair value when available. Fixed assets in other Company’s operating segments are tested for recoverability using a methodology similar to the E&P operating segment. Elements of judgement include forecasts of future industry margins, wholesale price of electricity, maintenance and development costs and expectations about average utilization rates of plants and renewable electricity generation facilities. Evidence of impairment indicators also include recent periods of operating losses in the context of the Company’s longer-term view of prices and margins. In 2025, the Company recognized a minor impairment loss at its polyethylene manufacturing plants in the Versalis business unit based on the recent history of losses and management’s view of structural weaknesses in the supply/demand balance and in industry margins. 101 Table of Contents Other Impairment Estimates. Unproved oil&gas 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 Company’s future development plans, the estimated economic chance of success, and the continuing commitment on part of the management to pursue exploration and appraisal activities, as well as length of time that the Company 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. In 2025, we recorded an impairment loss of around €330 mln at a gas property to reflect the lower expected fair value in a disposal process than its carrying amount. This held-for-sale asset was part of the Company’s divestiture program to reduce risks and anticipate cash flows from long-lived assets. 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 trends in quoted market prices, 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. Asset Retirement Obligations The Company is subject to retirement obligations for oil&gas properties. 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 expected expenditure, estimated amounts and timing of settlements, discount rates, and inflation rates. Those assumptions also consider the management’s expectations about possible impacts of the energy transition on the timing of assets decommissioning. The most judgmental assumption about the recognition of decommissioning provisions concerns the expected timing of decommissioning, which incorporates estimations about the expected useful lives of oil&gas assets and the pace of the transition. In case our assumptions are too optimistic, we could incur an upward revision of the liability and increased amortization charges through P&L as well as being forced to review our finance needs. Management estimated that in case the timing of incurrence of decommissioning expenses is brought forward by five years, the book value of the provision would increase by around €1.2 billion. In the case of refineries and petrochemicals complexes, decommissioning provisions are recognized when an asset is definitively shut down and no economic options exist to upgrade or reconvert the asset to produce decarbonized commodities. 102 Table of Contents Group profit and loss The table below sets forth a summary of Eni’s profit and loss account for the periods indicated. All line items included in the table below are derived from the Consolidated Financial Statements prepared in accordance with IFRS. For the disclosure on 2024 Group results compared to 2023 see the Annual Report on Form 20-F 2024, filed to the SEC on April 4, 2025. Year ended December 31, 2025 2024 2023 (€ million) Sales from operations 82,151 88,797 93,717 Other income and revenues (1) 1,478 2,417 1,099 Total revenues 83,629 91,214 94,816 Operating expenses (70,296) (74,544) (77,221) Other operating (expense) income 641 (352) 478 Depreciation, depletion and amortization (7,349) (7,600) (7,479) Impairment reversals (impairment losses) of tangible and intangible and right of use assets, net (1,582) (2,900) (1,802) Write-off of tangible and intangible and right of use assets (33) (580) (535) OPERATING PROFIT (LOSS) 5,010 5,238 8,257 Finance income (expense) (819) (599) (473) Income (expense) from investments 1,587 1,850 2,444 PROFIT (LOSS) BEFORE INCOME TAXES 5,778 6,489 10,228 Income taxes (3,020) (3,725) (5,368) Net profit (loss) 2,758 2,764 4,860 Attributable to: - Eni's shareholders 2,608 2,624 4,771 - Non-controlling interest 150 140 89 (1) Includes, among other things, contract penalties, income from contract cancellations, gains on disposal of mineral rights and other fixed assets, compensation for damages and indemnities and other income. 103 Table of Contents Analysis of the line items of the profit and loss account a) Sales from operations The table below sets forth, for the periods indicated, sales from operations generated by each of Eni’s business segments including intragroup sales, together with consolidated sales from operations. Year ended December 31, 2025 2024 2023 (€ million) Exploration & Production 50,367 54,440 55,773 Global Gas & LNG Portfolio and Power 17,120 18,876 24,168 Enilive and Plenitude 29,278 31,301 32,877 Refining and Chemicals 18,179 21,210 23,061 Corporate and other activities 2,073 1,905 1,830 Consolidation adjustments (34,866) (38,935) (43,992) SALES FROM OPERATIONS 82,151 88,797 93,717 2025 compared to 2024. Sales from operations (revenues) for 2025 (€82,151 million) decreased by €6,646 million from 2024 (or down by 7.5%) due to lower energy commodities prices and the dollar depreciation, which negatively affected all business segments. The average Brent price decreased by 15% and negatively affected the reported amounts of revenues in the E&P segment including crude oil trading activities. That reduction was partly offset by higher traded volumes. Sales in the GGP and Power segment were negatively affected by lower gas supplies with volumes down 14% (or 7 bcm) and lower spot gas prices in the seasonally strong fourth quarter. Sales in the Refining and Chemicals segment were negatively affected by lower commodity prices and a decline in sales volumes of refined products and petrochemicals products (down 14%), the latter also reflecting plant closures. Furthermore, the appreciation of the EUR vs the USD exchange rate (up by 4% for the yearly average) negatively affected the reported amounts of revenues mainly in the E&P segment. The drivers of the changes in revenues year-on-year are detailed in the following table: Sales from operations: change 2025 vs 2024 change of which: price effects exchange rate effects volume/mix effects (€ billion) E&P (4.1) (5.4) (2.3) 3.6 GGP and Power (1.8) 0.2 (2.0) Enilive and Plenitude (2.0) (1.3) (0.7) Refining and Chemicals (3.1) (1.6) (1.5) Other income and revenues 2025 compared to 2024. Eni’s other income and revenues amounted to €1,478 million, a decrease of €939 million. The reduction from the previous year was due to the circumstance that in the previous year Eni recognized an exception €1,048 million gain relating to the agreement with an Italian operator for the sharing of environmental costs incurred by Eni at certain decommissioned Italian sites jointly managed in the past. This line item included income and revenues relating to other oil and gas services, amounts billed to joint operators, gains on the disposal of assets and other income. b) Operating expenses The table below sets forth the components of Eni’s operating expenses for the periods indicated. Year ended December 31, 2025 2024 2023 (€ million) Purchases, services and other 67,056 71,114 73,836 Impairment losses (impairment reversals) of trade and other receivables, net 11 168 249 Payroll and related costs 3,229 3,262 3,136 Operating expenses 70,296 74,544 77,221 104 Table of Contents 2025 compared to 2024. Operating expenses for 2025 (€70,296 million) decreased by €4,248 million compared to 2024, down by 5.7%, primarily reflecting lower supply costs of raw materials (natural gas under long-term supply contracts, refinery and chemical feedstocks). Payroll and related costs (€3,229 million) decreased slightly by €33 million from 2024 (down by 1.0%) mainly due to divestments activities outside Italy following the portfolio optimizations, partly offset by increases on wages mainly in Italy due to the renewal of collective labor agreements. c) Depreciation, depletion, amortization, impairment losses (impairment reversals) net and write-off The table below sets forth a breakdown of depreciation, depletion, amortization, impairment losses (impairment reversals) net and write-off for the periods indicated. Year ended December 31, 2025 2024 2023 (€ million) Exploration & Production 6,061 6,353 6,271 Global Gas & LNG Portfolio and Power 279 267 295 Enilive and Plenitude 745 708 665 Refining and Chemicals 146 161 142 Corporate and other activities and impact of unrealized intragroup profit elimination 118 111 106 Total depreciation, depletion and amortization 7,349 7,600 7,479 Impairment losses (impairment reversals) of tangible and intangible assets, goodwill and right of use assets, net 1,582 2,900 1,802 Write-off of tangible and intangible and right of use assets 33 580 535 Total depreciation, depletion, amortization, impairment losses (impairment reversals) of tangible and intangible and right of use assets, net and write off of tangible and intangible and right of use assets 8,964 11,080 9,816 2025 compared to 2024. In 2025, depreciation, depletion and amortization charges (€7,349 million) decreased by €251 million from 2024, mainly in the Exploration & Production segment following the appreciation of the EUR vs. USD and the effect of amortization suspension at certain assets that were reclassified as held-for-sale. Those decreases were partly offset by higher charges due to projects start-ups and reserves revisions. Charges increased in the Enilive and Plenitude segment due to start-ups of new renewable energy installations. In 2025, the Group recorded impairment losses at property, plant and equipment for a total amount of €1,582 million, out of which €1,081 million were recorded at the Exploration & Production segment, mainly at certain assets in Congo and Cote d’Ivoire due to the alignment to the fair value of divestments as part of an ongoing portfolio optimization. Other impairment charges were driven by reserves revisions and changed pricing assumptions at oil&gas assets in Italy, Turkmenistan, the United Arab Emirates and the USA. The Refining and Chemicals segment incurred €451 million of impairment losses driven by the write-off of expenditures incurred in the year for compliance and stay-in-business at certain Cash Generating Units with expected negative cash flows in the Refining business (€253 million) and in the Chemicals business (€198 million), with the latter also including a write-off of an uneconomical business line due to a reduced profitability outlook because of continuing margins deterioration. Write-off of tangible and intangible and right of use assets amounted to €33 million and mainly related to the E&P segment as capitalized costs of suspended exploratory wells were expensed through profit due to unsuccessful assessment of commerciality of reserves or economic feasibility of projects in Algeria and Oman. Exploration wells write-offs were significantly lower than in the comparative period. 105 Table of Contents d) Operating profit (loss) by segment The table below sets forth Eni’s operating profit by business segment for the periods indicated. Year ended December 31, 2025 2024 2023 (€ million) Exploration & Production 6,302 6,715 8,693 Global Gas & LNG Portfolio and Power 1,770 (909) 2,626 Enilive and Plenitude 652 1,589 (74) Refining and Chemicals (2,485) (1,681) (2,121) Corporate and other activities (1,499) (371) (948) Impact of unrealized intragroup profit elimination 270 (105) 81 Operating profit (loss) 5,010 5,238 8,257 Exploration & Production. In 2025, the Exploration & Production segment reported an operating profit of €6,302 million, with a decrease of €413 million compared to the operating profit of €6,715 million reported in 2024. This decrease was driven by lower crude oil prices (international oil price for the Brent benchmark crude oil declined by 15%) reflecting oversupplied markets and macroeconomic uncertainty. In 2025, Eni’s average realized prices for crude oil and natural gas liquids decreased by 7% on average, with Eni’s average liquids prices decreasing by 13%. Lower crude oil realizations exchange rate effect and impacts of divestments made in 2024 were partly offset by production growth, better volume mix, cost efficiencies, significantly lower exploration wells write-offs and asset impairment losses. In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in segment base performance, management generally excludes the identified gains and losses presented below to assess the underlying industrial trends and obtain a better comparison of core business performance across reporting periods. In 2025, identified gains and losses included impairment losses of €1,081 million and minor other charges net. Excluding those items, the E&P segment reported a Non-GAAP operating profit of €7,493 million, with a decrease of €1,727 million from 2024, down by 19%, driven by lower realizations in US dollars at equity production, exchange rate effect and impacts of divestments made in 2024. These negatives were partly offset by higher production sold, better volume mix effects, lower exploration write-offs, as well as by cost efficiencies. change of which: price effects exchange rate effects volume/mix effects cost effects (€ million) Change in E&P Non-GAAP operating profit (loss) 2025 vs. 2024 (1,727) (1,798) (378) 118 331 Year ended December 31, 2025 2024 2023 Exploration & Production (€ million) GAAP operating profit (loss) 6,302 6,715 8,693 Impairment losses (impairment reversals), net 1,081 2,203 1,043 Net gains on disposal of assets (10) (25) 2 Environmental provisions 24 9 81 Risk provisions 122 9 7 Reclassification of currency derivatives and translation effects to management measure of business performance (48) 22 73 Write off of exploration projects 140 Other 22 147 225 Total identified gains and charges 1,191 2,505 1,431 Non-GAAP operating profit (loss) 7,493 9,220 10,124 106 Table of Contents Global Gas & LNG Portfolio (GGP) and Power This reportable segment aggregates the results of the GGP business engaged in the purchase and marketing of gas, LNG and electricity and in trading activities, with those of the power business engaged in the production of electricity from cogeneration plants feed with gas and in providing backup capacity to the Italian grid because this business is ancillary to GGP. In 2025, the GGP and Power segment reported an operating profit of €1,770 million compared to a loss of €909 million in 2024. This increase was positively affected by movements in fair-valued commodity derivatives entered into (from a loss of €1,740 million in 2024 to a gain of €377 million in 2025), a large part of which was lacking correlation with the underlying performance due to the accounting under IFRS, as well as lower sales volumes, reduced gas prices in the seasonally strong fourth quarter, and other scenario effects. In reviewing the performance of the Company’s GGP and Power segment and with a view to better explaining year-on-year changes in the segment performance, management generally excludes certain fair-valued commodity derivatives with gains and losses recognized through to profit to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. We enter into commodity and currency derivatives to reduce our exposure to: (i) the commodity risk due to different indexation between the purchase cost and the selling price of gas or to lock in a commercial margin once a sale contract has been signed or is highly probable; and (ii) the underlying exchange rate risk due to the fact that our selling prices are indexed to the euro and our supply costs are denominated in dollars. These derivatives normally hedge the Group net exposure to commodities and exchange rates but do not meet the requirements for being accounted for as hedges in accordance with IFRS. As part of our ordinary activities, we also entered into forward gas sale contracts which are intended to be settled with the delivery of the commodity and which are accounted at fair value because they were not eligible for the own use exemption at their inceptions, whereas purchase costs of gas were accounted on an accrual basis. In explaining year-on-year changes and in evaluating the business performance, management believes that is appropriate to exclude the fair value of commodity derivatives which lacked the formal criteria to be accounted for as hedges or were not eligible for the own use exemption, including the ineffective portion of cash flow hedges. We also excluded from our measure of underlying performance the effects of the settlement of certain commodity derivatives of which the underlying physical transaction had yet to be finalized with the delivery of the commodity. Furthermore, although the Group classifies within net finance expense those gains and losses on currency derivatives, as well as on the alignment of trade receivables and payables denominated in dollars into the accounts of euro subsidiaries at the closing rate, we believe that it is appropriate to consider those gains and losses on currency derivatives and currency differences at our dollar-denominated trade payables and receivables as part of the underlying business performance. In 2025, those fair value effects on commodity derivatives amounted to a gain of €377 million, while in 2024 those fair value effects amounted to a charge of €1,740 million. In 2025, identified items also included a €46 million charge determined as a timing difference between the value of gas inventories accounted for under the weighted-average cost method provided by IFRS as measured at the balance sheet date and the management’s own measure of performance, which considers the storage injection season and the withdrawal season and defer the margins captured by leveraging the seasonal “summer vs. winter” spreads in gas prices net of the effects of the associated commodity derivatives to when those volumes held in storage are actually sold, normally during the next withdrawal winter season. Excluding the below-listed gains and charges, the GGP business reported a Non-GAAP operating profit of €1,015 million, with a decrease of €84 million from 2024, while the Power business reported an adjusted operating profit of €347 million, up by €211 million from 2024, for a net increase of 127 million for the segment. The increase was due a one-off gain in the Power business due to a contract renegotiation, partly offset by negative scenario effects, lower sales volumes and reduced benefits of contract renegotiations and settlments in the GGP business. The GGP business operating performance was underpinned by continued margin improvement from gas and LNG portfolio optimization activities, including asset-backed trading actions. change of which: price effects contract renegotiations and risk provisions cost effects (€ million) Change in GGP and Power Non-GAAP operating profit (loss) 2025 vs. 2024 127 (67) 255 (61) 107 Table of Contents Year ended December 31, 2025 2024 2023 Global Gas & LNG Portfolio and Power (€ million) GAAP operating profit (loss) 1,770 (909) 2,626 Impairment losses (impairment reversals), net (18) 101 (38) Provision for redundancy incentives 2 1 6 Fair value (gains)/losses on commodity derivatives (377) 1,740 99 Reclassification of currency derivatives and translation effects to management measure of business performance (292) 228 (105) Other 277 74 825 Total identified gains and charges (408) 2,144 787 Non-GAAP operating profit (loss) 1,362 1,235 3,413 - Global Gas & LNG Portfolio 1,015 1,099 3,247 - Power 347 136 166 Enilive and Plenitude. In 2025, the Enilive and Plenitude segment reported an operating profit of €652 million, compared to an operating profit of €1,589 million in 2024, representing a decrease of €937 million. Enilive reported an operating profit of €499 million (€282 million in 2024), while Plenitude reported an operating profit of €153 million, compared to an operating profit of €1,307 million in 2024. The main item excluded from GAAP operating profit in determining the Non-GAAP profitability measure of Plenitude were the effects related to fair value changes of commodity derivatives lacking the formal criteria to be accounted as hedges under IFRS, which exhibited significant volatility y-o-y, and provisions for environmental remediation and other charges. In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes derivatives effects and the other identified gains and losses described above in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Excluding those items, the Enilive business reported a Non-GAAP operating profit of €682 million (an operating profit of €571 million in 2024), helped by higher results of the biorefining business in Italy, mainly driven by a recovery of biofuels margins and by higher processed volumes. The performance of the retail business was steady. The Plenitude business reported a Non-GAAP operating profit of €554 million, lower than operating profit of €616 million in 2024, due to weaker results in the retail business, mainly related to a reduced contribution of the activity of energy efficiency solutions and increasing competitive pressure, partly offset by higher volumes of electricity generation at renewable plants reflecting capacity additions. change of which: price effects volume/mix effects cost effects (€ million) Change in Enilive Non-GAAP operating profit (loss) 2025 vs. 2024 111 80 95 (64) Change in Plenitude Non-GAAP operating profit (loss) 2025 vs. 2024 (62) (50) 14 (26) 108 Table of Contents The items excluded from GAAP operating loss in determining the Non-GAAP measure of profitability mainly include effects associated with commodity fair-valued derivatives, lacking the formal criteria to be classified as hedges under IFRS which amounted to a charge of €368 million. Year ended December 31, 2025 2024 2023 Enilive and Plenitude (€ million) GAAP operating profit (loss) 652 1,589 (74) (Profit) loss on inventory 115 112 47 Risk provisions 2 8 Impairment losses (impairment reversals), net 7 113 45 Environmental provisions 57 38 36 Provision for redundancy incentives 2 (2) 22 Fair value (gains)/losses on commodity derivatives 368 (682) 1,142 Reclassification of currency derivatives and translation effects to management measure of business performance (1) (1) 2 Other 36 18 29 Total identified gains and charges 584 (402) 1,331 Non-GAAP operating profit (loss) 1,236 1,187 1,257 of which: - Enilive 682 571 742 -Plenitude 554 616 515 Refining and Chemicals In 2025, this segment reported an operating loss of €2,485 million compared to a loss of €1,681 million in the previous year, due to an almost €0.6 billion increased loss on inventories evaluated at the weighted average cost or net realized value whichever is the lower, and a deteriorated performance of the chemical business affected by a negative scenario. The main item excluded from GAAP operating profit in determining the Non-GAAP profitability measure of this segment is the inventory holding gain (or loss). Inventory holding gains or losses represent the difference between the cost of sales of the volumes sold during the period calculated using the cost of supplies incurred during the same period and the cost of sales calculated using the weighted average cost method. Under the weighted average cost method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historic cost of purchase, or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant impact on reported income thereby affecting comparability. The amounts disclosed represent the difference between the charge (to the income statement) for inventory on a weighted average cost method basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during the period is principally calculated on a quarterly or monthly basis by dividing the total cost of inventory acquired in the period by the number of barrels acquired. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. We regard the inventory holding gain or loss, including any write-down to align the carrying amounts of inventories to their net realizable value at the reporting date, as lacking correlation to the underlying business performance which we track by matching revenues with current costs of supplies. Other identified charges included asset impairments and environmental risk provisions. In 2025, Eni’s refining business reported a Non-GAAP operating loss of €77 million, in line with the year-ago loss. 109 Table of Contents In addition to the inventory holding profit (or loss), the identified items of this business for the year 2025 comprised the write-down of capital expenditures made for compliance and stay-in-business at certain CGU with expected negative cash flows (€253 million) and environmental provisions of €133 million reflecting updated estimates of remediation costs at operational hubs. The Chemical business reported a non-GAAP operating loss of €819 million in 2025, compared to a non-GAAP operating loss of €814 million in 2024 due to lower products margins and to a lesser extent, reduced sales volumes driven by lower demand across all business segments due to a slowdown in the macro environment and comparatively higher production costs in Europe for energy inputs and other expenses, which reduced the competitiveness of Versalis production with respect to US and Asian players, against the backdrop of global overcapacity and rising competitive pressures. Those negatives were partly offset by lower expenses due to plant closures and cost efficiencies. The Eni’s subsidiary is implementing a vast and complex turnaround plan to regain profitability by shutting down unprofitable plants, upgrading uneconomical facilities to manufacturing hubs for the energy transition and developing remunerative product lines like biochemicals, polymers from recycled plastics and compounding. As part of this plan, the two loss-making cracking plants of Brindisi and Priolo have been definitively halted. The management expects improvements to the operating profit in the course of 2026. In addition to the inventory holding profit (or loss), the identified items of this business for the year 2025 comprised an impairment loss taken at polyethylene plants reflecting a deteriorated profitability outlook and the write-down of capital expenditures made for compliance and stay-in-business (€198 million) at certain CGU with expected negative cash flows and environmental provisions of around €173 million relating estimations of remediation costs in hubs under transformation and other charges of around €77 million reflecting the costs incurred to close down unprofitable plants. change of which: price effects volume/mix effects cost effects (€ million) Change in Refining Non-GAAP operating profit (loss) 2025 vs. 2024 (1) 141 (108) (34) Change in Chemical Non-GAAP operating profit (loss) 2025 vs. 2024 (5) (42) (43) 80 Year ended December 31, 2025 2024 2023 Refining and Chemicals (€ million) GAAP operating profit (loss) (2,485) (1,681) (2,121) (Profit) loss on inventory 684 95 557 Environmental provisions and other costs net of a gain of an environmental agreement 306 177 337 Impairment losses (impairment reversals), net 451 455 726 Net gains on disposal of assets (5) (2) (9) Risk provisions 36 33 11 Provision for redundancy incentives 11 19 31 Fair value (gains)/losses on commodity derivatives (8) (1) (1) Reclassification of currency derivatives and translation effects to management measure of business performance 7 6 11 Other 107 9 96 Total identified gains and charges 1,589 791 1,759 Non-GAAP operating profit (loss) (896) (890) (362) - Refining (77) (76) 252 - Chemicals (819) (814) (614) 110 Table of Contents Corporate and Other activities. These activities are mainly cost centers comprising holdings, financing and treasury activities in support of operating subsidiaries, central functions like legal affairs, human resources, captive insurance activities, general and administrative support, as well as research and development, new technologies, business digitalization and the environmental activity developed by the subsidiary Eni Rewind. Furthermore, the results of CCUS and Agribusiness of Eni have been included in the “Corporate and other activities” reporting segment. More information on the Company's segment reporting is disclosed in note n.35 to the Consolidated Financial Statements. The aggregate Corporate and Other activities reported an operating loss of €1,499 million compared with a loss of €371 million in 2024. A higher loss was due to a risk provision relating to a proceeding pending before the Italian Antitrust Authority (AGCM) and the circumstance that in the previous year Eni recognized a one-off gain relating to the agreement with an Italian operator for the sharing of environmental costs incurred by Eni at certain decommissioned Italian sites jointly managed in the past. e) Net finance expenses The table below sets forth a breakdown of Eni’s net financial expenses for the periods indicated: Year ended December 31, 2025 2024 2023 (€ million) Income (expense) on derivative financial instruments (80) 278 (61) of which - Derivatives on exchange rate (86) 310 (63) - Derivatives on interest rate 6 (32) 2 Exchange differences, net 133 (38) 255 Finance expense from banks on short and long-term debt (1,026) (1,185) (874) Interest expense for lease liabilities (348) (314) (267) Interest income due to banks 191 294 356 Net income from financial assets measured at fair value through profit or loss 235 388 284 Finance expense due to the passage of time (accretion discount) (250) (261) (341) Other finance income and expense, net 204 17 81 (941) (821) (567) Finance expense capitalized 122 222 94 NET FINANCE EXPENSES (819) (599) (473) In 2025, net finance expenses were €819 million (€599 million in 2024). The increase in net finance expenses in 2025 compared to 2024 was due to lower gains at commodity derivatives due to trends in the EUR vs USD exchange rates and lower income recorded at fair-valued financial assets held for trading. f) Net income from investments The table below sets forth a breakdown of Eni’s net income from investments for the periods indicated: Year ended December 31, 2025 2024 2023 (€ million) Share of gains (losses) from equity-accounted investments 1,161 866 1,336 Dividends 242 227 255 Net gains (losses) on disposals 77 562 430 Other income (expense), net 107 195 423 1,587 1,850 2,444 111 Table of Contents In 2025, the Group reported a net profit from investments of €1,587 million, down by €263 million from 2024 mainly due to lower net gains on the disposal of assets (down by €485 million), following the circumstance that in 2024 this line item included the gains on the divestment of certain assets in the E&P segment as well as the sale of a 10% stake in the equity interests of Saipem. This reduction was partly offset by increasing Eni’s share of profits generated by equity-accounted investments (up by €295 million) and was mainly driven by higher profits in the Exploration & Production segment (up by €212 million), mainly driven by a higher net result at Vår Energi due to asset revaluations and exchange rate gains, and in the Refining and Chemical segment (up by €47 million) as well as in the Corporate and Other activities segment (up by €44 million). A break-down of profits earned for the main investments is provided below: (i) in E&P, we recognized a profit of €1,116 million, an increase of €212 million. It included Eni’s share of results in the joint venture Vår Energi (€602 million), the Azule Energy Holdings joint venture (€415 million), as well as Eni’s share in Ithaca Energy (loss of €15 million); (ii) The GGP SeaCorridor associate for €32 million; (iii) The Refining ADNOC Refining&Trading associate, where we recognized a profit of €121 million ; (iv) the joint venture Saipem, where we recognized a profit of €71 million. Dividends of €242 million were paid by minority investments in certain entities which were designated at fair value through other comprehensive income under IFRS 9, except for dividends which were recorded through profit. These entities mainly comprised Nigeria LNG Ltd (€156 million) and Everen Ltd (€30 million). Net gains on the disposal of assets amounted to €77 million, decreasing by €485 mainly and referred to the divestment of an interest in Ithaca Energy and the sale of a 49.99% stake in Eni CCUS Holding. g) Taxes In 2025, income taxes decreased by €705 million to €3,020 million and compared to the pre-tax profit of €5,778 million resulted in a tax rate of 52.3% (compared to 57.4% in 2024). The reduction in 2025 tax rate was due to : i) recognition of €385 million of deferred tax assets at Italian subsidiaries due to reinstatement of previously written-off tax-loss carryforwards reflecting an improved profitability outlook; ii) a better geographical mix of profits before taxes in E&P reflecting higher contribution from jurisdictions with lower-than-average tax rates also as result of portfolio rationalization; iii) recognition of the tax benefit associated with previously incurred exploration expenses at certain development projects that were matured to final investment decision “FID” in 2025; iv) lower non-deductible charges recorded at certain E&P foreign subsidiaries. The management also calculated an adjusted tax rate which excluded identified items from taxable profit and the tax effect associated with identified items and write-ups of previously impaired tax assets from the line-item income taxes. This adjusted tax rate, which is the measure of tax rate tracked by management, decreased by approximately 8 percentage points in 2025 compared to 2024, to 44%. The reduction in the Group adjusted tax rate was driven by the E&P segment due to recognition of a one-off benefit as several development projects were matured to FID enabling the recognition of the tax benefit associated with previously incurred exploration expenses, and a better geographical mix of pre-tax profits as explained above. 112 Table of Contents Liquidity and capital resources Eni’s cash requirements for working capital, dividends to shareholders, capital expenditures, acquisitions and share repurchases have been financed in the last three years primarily by a combination of funds generated from operations, issues of equity investments (hybrid bonds), divestments of property, plant and equipment and shareholdings in equity accounted entities, or the reimbursement of operating financing receivables owed to Eni by unconsolidated entities, and in 2025 also by taking on new finance debt. The Group continually monitors the balance between cash flow from operating activities and net expenditures, targeting a sound and balanced financing structure. The following table summarizes the Group cash flows and the principal components of Eni’s change in cash and cash equivalent for the periods indicated. This cash flow statement is a GAAP measure of cash flow and is presented herein to help readers understand the change in the year of the Group net borrowings which is a NON-GAAP measure as explained further on. Year ended December 31, 2025 2024 2023 (€ million) Net profit (loss) 2,758 2,764 4,860 Adjustments to reconcile net profit to net cash provided by operating activities: - amortization and depreciation charges, impairment losses, write-off and other non monetary items 7,209 9,951 7,781 - net gains on disposal of assets (99) (601) (441) - dividends, interest, taxes and other changes 3,590 4,246 5,596 Changes in working capital related to operations 2,735 1,286 1,811 Dividends received by equity investments 1,785 1,946 2,255 Taxes paid (3,737) (5,826) (6,283) Interests (paid) received (911) (674) (460) Net cash provided by operating activities 13,330 13,092 15,119 Capital expenditures (8,647) (8,485) (9,215) Acquisition of investments and businesses (878) (2,593) (2,592) Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments 1,383 2,788 596 Other cash flow related to investing activities 183 (996) (348) Net cash inflow (outflow) related to financial activities (1,339) (531) 2,194 Changes in short and long-term finance debt (2,555) (1,293) 315 Repayment of lease liabilities (1,250) (1,205) (963) Dividends paid and changes in non-controlling interests and reserves 537 (4,522) (4,882) Net issue (repayment) of perpetual hybrid bond (328) 1,640 (138) Effect of changes in consolidation and exchange differences of cash and cash equivalent (198) 83 (62) Net increase (decrease) in cash and cash equivalent 238 (2,022) 24 Cash and cash equivalent at the beginning of the year 8,183 10,205 10,181 Cash and cash equivalent at year end 8,421 8,183 10,205 113 Table of Contents Year ended December 31, 2025 2024 2023 (€ million) Net cash provided by operating activities 13,330 13,092 15,119 Capital expenditures (8,647) (8,485) (9,215) Acquisitions of investments and businesses (878) (2,593) (2,592) Disposals of consolidated subsidiaries, businesses, tangible and intangibleassets and investments 1,383 2,788 596 Other cash flow related to capital expenditures, investments and divestments 183 (996) (348) Repayment of lease liabilities (1,250) (1,205) (963) Net borrowings (1) of acquired companies (762) (631) (234) Net borrowings (1) of divested companies 362 (155) Exchange differences on net borrowings and other changes (1,141) (364) (1,061) Dividends paid, share repurchases and changes in minority interest and reserves 537 (4,522) (4,882) Net issue (repayment) of perpetual hybrid bond (328) 1,640 (138) Change in net borrowings(1) before IFRS 16 effects 2,789 (1,276) (3,873) Repayment of lease liabilities 1,250 1,205 963 Inception of new leases and other changes (497) (2,322) (1,348) Change in net borrowings after IFRS 16 effects (1) 3,542 (2,393) (4,258) Net borrowings (1) at the beginning of the year 18,628 16,235 11,977 Net borrowings (1) at year end 15,086 18,628 16,235 (1) Net borrowings is a non-GAAP financial measure. For a discussion of the usefulness of net borrowings and its reconciliation with the most directly comparable GAAP financial measures see “Financial Condition” below. In 2025, adjustments to reconcile the net profit reported in the year to net cash provided by operating activities mainly related to depreciation, depletion, amortization, impairment charges and results of equity-accounted entities for €7,209 million. Adjustments to net profit also included accrued income taxes (€3,020 million) and net interest expense (€812 million), which were partly offset by amounts actually paid (€3,737 million and €911 million, respectively). The dividends received by equity-accounted investments of €1,785 million mainly related to Azule Energy Holdings, Vår Energi and Adnoc R&T, while other dividends recorded through profit of €156 million mainly related to Nigeria LNG. 114 Table of Contents a) Changes in working capital related to operations In 2025, working capital generated an inflow of €2,735 million driven by several initiatives to optimize working capital needs including non-recourse arrangements to discount certain receivables in support of supply and trading activities and the management of credit risk, partly offset by the cash-outs relating to utilizations of provisions in connection with advancement of Group’s decommissioning activities at oil&gas assets and environmental remediation programs. Year ended December 31, 2025 2024 2023 (€ million) Exploration & Production 6,253 6,055 7,135 Global Gas & LNG Portfolio and Power 109 110 119 Enilive and Plenitude 1,232 1,303 1,064 Refining and Chemicals 663 632 556 Corporate and other activities 430 408 360 Impact of unrealized intragroup profit elimination (40) (23) (19) Capital expenditures 8,647 8,485 9,215 Acquisitions of investments and businesses 878 2,593 2,592 9,525 11,078 11,807 Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments (1,383) (2,788) (596) Capital expenditures totaled €8,647 million and €8,485 million, respectively in 2025 and in 2024. For a discussion of capital expenditures by business segment and a description of year-on-year changes see “Capital expenditures by segment”. Cash outflows for acquisitions of €878 million mainly related to the purchase of renewable generation capacity at Plenitude (€0.5 billion) and additional working interest at certain fields in the E&P (€0.1 billion). These outflows were offset by the divestment of a 30% stake in the Baleine project (€1.1 billion) and other non-strategic fields in Congo. b) Dividends paid, share repurchases and changes in non-controlling interests and reserves In 2025, dividends paid and changes in non-controlling interests and reserves (€537 million) related to the dividends paid to Eni shareholders (€3,080 million which comprised two quarterly installments of the 2024 dividend for about €1.5 billion and the first and the second quarterly installment of the 2025 dividend of €0.26 per share each, amounting to €1.6 billion). The company purchased own shares for an amount of €1,896 million to complete the 2024 buy-back program (€0.4 billion) and as a part of the 2025 new buy-back program (€1.5 billion). As of February 18, 2026, the 2025 buy-back program was completed with an overall amount of 119 million shares purchased for a cash outlay of €1,800 million. Cash returns to shareholders were offset by the cash-ins associated with transactions among owners as the Company agreed to dispose noncontrolling interests in Enilive where KKR equity fund finalized an investment of 30% in the share capital of the subsidiary for net proceeds of €3.57 billion to Eni, and Plenitude where Ares equity fund purchased a 20% interest for €2 billion and previously EIP fund increase its outstanding stake by further 2.4% to 10% for cash consideration of €0.21 billion. Financial condition Management assesses the Group’s capital structure and financial condition by tracking net borrowings, which is a non-GAAP financial measure. Eni calculates net borrowings as total finance debt (short-term and long-term debt, including finance leases as per IFRS 16) derived from its Consolidated Financial Statements prepared in accordance with IFRS less: cash, cash equivalents and certain highly liquid investments not related to operations including, among others, a liquidity reserve made of held-for-trading securities and finally other liquid assets not related to operations, mainly cash deposits at exchanges and other financial counterparts established as a collateral of derivative transactions. The Group also included in its financial assets subtracted from gross finance debt certain long-term financing receivables owed to us by non-consolidated entities to reflect the increasing financial autonomy of such entities as provided by our “satellite strategy”, resulting in the Group being exposed only to a credit risk with respect to those entities. The amount of those long-term financing receivables reclassified among financial assets was around €3 billion as of December 31, 2025. Net borrowing is also calculated by excluding liabilities of financial leases (ex IFRS 16). 115 Table of Contents Financial assets measured at fair value through profit or loss constituting part of the Group’s liquidity reserves amounted to around €7 billion as of end of 2025 and were accounted as mark-to-market financial instruments. Of this amount, fixed income securities issued by industrial companies and financial institutions were €6.1 billion. Although the fair value of these investments is netted from financial debt in our calculation of net borrowings, there is no certainty that these investments could be readily monetizable at their carrying value, particularly in the event of market stress. For further information, see “Item 18 – Note 7 – Financial assets at fair value through profit and loss – of the Notes to the Consolidated Financial Statements”. Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways in which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest plus net borrowings “gearing” to assess Eni’s capital structure, to analyse whether the ratio between finance debt and total funds is well balanced compared to industry standards and to track management’s short-term and medium-term targets. That ratio is also calculated excluding IFRS 16 lease liabilities from both numerator and denominator. Management continuously monitors trends in net borrowings and trends in gearing in order to optimize the use of internally-generated funds versus funds from third parties. The measure calculated in accordance with IFRS that is most directly comparable to net borrowings is total finance debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to gearing is the ratio of total debt to shareholders’ equity (including non-controlling interest) plus total finance debt. Eni’s presentation and calculation of net borrowings and gearing may not be comparable to other companies. The tables below set forth the calculations of net borrowings and gearing for the periods indicated and their reconciliation to the most directly comparable GAAP measure. (€ million) Dec 31 2025 Dec 31 2024 Total finance debt including lease liabilities 34,164 36,801 less: Cash and cash equivalents (a) (8,242) (8,183) Financial assets measured at fair value through profit or loss (6,991) (6,797) Financing receivables held for non-operating purposes (b) (3,845) (3,193) Lease liabilities (5,700) (6,453) Net borrowings excluding lease liabilities (a) 9,386 12,175 Shareholders' equity including non-controlling interest (b) 52,787 55,648 Gearing before lease liabilities ex IFRS 16 (a/b+a) 0.15 0.18 (a) It includes €142 mln of cash at held-for-sale subsidiaries provisionally deposited at third-party banks at the end of 2025 and then moved to the Group cash pooling at the beginning of 2026. (b) Considering Eni’s strategy based on the satellite model which envisages an increasing financial autonomy of non-consolidated entities, it includes loans granted to certain JVs, where Eni is exposed solely to a credit risk as a repayment plan is scheduled. Therefore, such financing receivables have been netted against gross finance debt to determine Eni’s net borrowings and to calculate the Group gearing. See also Item 18 - Note 20 on Consolidated Financial Statements. As of December 31, 2025 2024 (€ million) Shareholders’ equity including non-controlling interest as per Eni’s Consolidated Financial Statements prepared in accordance with IFRS 52,787 55,648 Ratio of finance debt including lease liabilities to total equity plus finance debt 0.39 0.40 Less: ratio of cash, cash equivalents and financial assets to total equity plus net borrowings (0.17) (0.15) Ratio of net borrowing to total equity plus net borrowings (gearing including IFRS 16 lease liabilities) 0.22 0.25 Ratio of net borrowing excluding lease liabilities to total equity plus net borrowings excluding lease liabilities (gearing ex IFRS 16) 0.15 0.18 116 Table of Contents At December 31, 2025, total finance debt of €34,164 million including lease liabilities consisted of €8,363 million of short-term debt (including the portion of long-term debt due within twelve months equal to €3,434 million) and €20,101 million of long-term debt. At the same date, lease liabilities were €5,700 million (short-term portion €1,263 million). In 2025, net borrowings including lease liabilities amounted to €15,086 million, representing a €3,542 million decrease from 2024 driven by net cash provided by operating activities and proceeds from asset disposal and divestments of noncontrolling interests in subsidiaries significantly exceeding capital expenditures, cash returns to shareholders and other contractual obligations as IFRS 16 lease liabilities (down to €5,700 million as of December 31,2025 from €6,453 million as of December 31, 2024) mainly related to the Exploration & Production segment and comprised leases of certain FPSO vessels and platforms used in the development of the OCTP offshore projects in Ghana, Area 1 in Mexico and the Baleine project in Cote d’Ivoire, as well as the multi-year rental of rigs; to the Enilive business line relating to highways concessions, land leases, leases of service stations for the sale of oil products and the car fleet dedicated to the car sharing business; to the Corporate and Other activities segment mainly regarding property rental contracts (real estate and IT). Net borrowings excluding the lease liabilities, which is the Non-GAAP measure of financial condition mostly tracked by management would amount to €9,386 million, down by €2.8 billion compared to December 31, 2024. The ratio of finance debt to total equity plus finance debt was 0.39 at 2025 year-end, including the IFRS 16 lease liability (0.40 in 2024). Total equity of €52,787 million decreased by €2,861 million from December 31, 2024. This was due to negative foreign currency translation differences (€6,410 million) reflecting the depreciation of the US dollar vs. the euro as of December 31, 2025 vs. December 31, 2024, the payment of dividends to Eni shareholders (two tranches of the 2024 dividend for €1.5 billion and the first and the second quarterly instalment of the 2025 dividend for €1.6 billion) as well as the buy-back of Eni shares (€1.9 billion). Those decreases were partly offset by the net profit for the period (€2.76 billion), and the recognition through retained earnings of the positive difference between the book value of the noncontrolling interests in the subsidiaries Enilive and Plenitude divested to third parties and the consideration received (€3.4 billion). The Group Non-GAAP measure of its financial condition mostly tracked by management was gearing calculated as ratio of net borrowings to total equity plus net borrowings excluding lease liabilities and was 0.15 at year end. Considering that in 2025 the non-controlling interest increased significantly, gearing calculated considering only equity attributable to Eni’s shareholders (€47.9 billion) would be 0.16. Capital expenditures by segment Exploration & Production. In 2025, capital expenditures of the Exploration & Production segment amounted to € 6,253 million and mainly related to the development of hydrocarbon fields (€5,502 million). Significant expenditures were directed mainly in the United Arab Emirates, Libya, Egypt, Indonesia, Algeria, Congo and Italy. 117 Table of Contents Global Gas & LNG Portfolio and Power. In 2025, capital expenditure in the Global Gas & LNG portfolio and Power totaled €109 million relating to power plants upgrading. Enilive and Plenitude In 2025, capital expenditures in the Enilive and Plenitude segment amounted to €1,232 million. Plenitude’s capital expenditure was €764 million related to development activities in the renewable business, acquisition of new customers, as well as development of electric vehicles network infrastructure, Enilive’s capital expenditure was €468 million mainly related to biorefineries and marketing activity in Italy and in the rest of Europe, regulation compliance and stay-in-business initiatives in the retail network, as well as HSE initiatives. Refining and Chemicals In 2025, capital expenditures in the Refining and Chemicals segment amounted to €663 million and mainly related to: (i) traditional refining in Italy (€481 million) relating to the reconversion of Livorno in biorefinery, maintenance and stay-in-business; and (ii) circular economy and asset integrity in the chemical business (€182 million). Recent developments and significant transactions The table below sets forth certain indicators of the trading environment for the periods indicated (rounded for the first quarter 2026): Three months ended March 31, January 1 through March 19, 2025 2026 Average price of Brent dated crude oil in U.S. dollars (1) 75.7 76 Average EUR/USD exchange rate (2) 1.052 1.17 Standard Eni Refining Margin (SERM) (3) 3.8 10 Gas at the TTF in $/mmBTU 14.4 13 (1) Price per barrel. Source: S&P Global Energy. (2) Source: ECB. (3) In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations. See “management expectations of operations” below for a discussion on how key market indicators are performing against management’s expectations. The main business transactions that occurred in the first quarter 2026 are reported in Item 4. See also section “Subsequent events” in the Notes to the Consolidated Financial Statements. 118 Table of Contents Management’s expectations of operations Business trends Exploration & Production In the next five-year plan 2026-2030, the management intends to increase the financial returns of the E&P segment at a constant scenario basis leveraging profitable production growth, capital and cost discipline, and reduction of time-to-market of projects. At the same time, we are planning to reduce CO2 direct emissions and methane emissions at our E&P operations. Our plans are assuming a Brent crude oil price scenario of: 2026 2027 2028-2030 2040 2050 Brent crude oil price $/bbl real terms 2025: 68 66 75 65 53 Our long-term price forecast factored our expectations about possible impacts of the energy transition on crude oil demand and prices. Our Brent price assumption in nominal terms for 2026 is 70 $/bbl. Against those pricing assumptions, we plan to increase production at a compounded average growth rate “CAGR” of around 3-4% through 2030. This growth rate would be higher when excluding impacts of the planned divestment of part of our working interests at certain assets. The main drivers of this expected growth are the development of new projects in Libya, Qatar, UAE, Egypt, the subsequent project phases at the Baleine field off Cote d’Ivoire and at the Congo FLNG project where a floating production vessel was moored at the end of 2025, the start of an LNG-focused joint venture in Indonesia, as well as new fields start-ups and ramp-ups in Angola and Norway. The long-term plateau will be supported by the development of our more recent discoveries, like the gas discoveries off Cyprus, the Coral North gas discovery off Mozambique, where we took FID in 2025, and finally the first gas at the large Argentina FLNG project expected in the medium term. New fields start-up and ramp-up will contribute around 850 KBOE/d of new production in 2030, underpinning achievement of our growth objectives. LNG expansion is expected to make the largest contribution to this expected growth. Therefore, our production plans contemplate a gradual increase of the proportion of natural gas, liquefied natural gas and natural gas liquids in the production mix till achieving a higher share than liquids by 2030. Another feature of our production plans is geographic diversification as we expect to significantly increase the share of Americas and Far East in our portfolio at 2030, gaining better exposure to fast growing energy markets. Due to market risks and uncertainties, management intends to retain a strong focus on capital and cost discipline, on shortening the projects cycle and on reducing the time-to-market of our reserves and the breakeven Brent price as levers to maintain our development projects profitable through the cycle. We plan to invest a major part of the Group €29 billion gross expenditures budgeted for the next five-year plan 2026-2030 to explore for and develop hydrocarbons reserves. Those expenditures do not include expected expenditures that will be incurred by our participated joint ventures and associates, like the expenditures that will be incurred by Var Energi, Azule Energy, Ithaca Energy and the LNG joint venture in Indonesia/Malaysia, this latter expected to become operational by mid-2026. Those equity-accounted entities are expected to self-finance their respective capital expenditures requirements, without recurring to shareholders’ funds. Our capex plan includes the assumptions of continuing inflationary pressures throughout the E&P supply chain, albeit at a slower pace than in recent years, and a gradual appreciation of USD vs the EUR. Our strategy is designed to retain profitable and cash-generative E&P operations, by leveraging accretive exploration and effective development and field operation activities to accelerate the time-to-market of reserves which will help the Company reduce projects’ pay-back period, minimize financial exposure and lower the full cycle cost of the barrel and hence the Brent breakeven price. The execution of an asset disposition plan will help accelerate the cash conversion cycle of reserves, i.e. in a stage earlier than production. Asset dispositions will target high-potential discoveries with large working interests, where we can dilute our stakes maintaining the operatorship in line with our dual exploration model, as well as mature producing fields. The cash proceeds from asset disposals will reduce the cash requirements to fund the organic growth plans. As part of this model, in 2025 we divested a 30% interest in the large Baleine oilfield offshore Cote d’Ivoire with net proceeds of €1.1 billion and we are planning to divest a further 10% interest of this asset as well as a 25% interest in the Congo FLNG project. We believe that this strategy based on capital discipline and acceleration of the cash conversion cycle of reserves is warranted to reduce the segment’s financial exposure and the Brent price of breakeven of projects given current uncertainties in the short- and medium-term outlook due to a possible macroeconomic slowdown and risks of oversupplies, as well as the risks posed by the energy transition in a longer term. We plan to carefully select our development projects against our pricing assumptions and minimum requirements of internal rates of return. We intend to reduce financial exposure and the execution risk leveraging on a phased approach in developing our projects. Although we plan to deliver our planned projects on time and on budget, several of our projects are complex due to scale and reach of operations, environmentally sensitive locations, external conditions, including offshore operations, potential industry bottlenecks like in the case of shipyards and rigs and other industry limits and other considerations including the risk factors described in Item 3. These constraints and factors might cause delays and cost overruns. In addition, costs of industrial inputs (labor, materials, field services) are expected to rise driven by inflation, albeit at a smaller pace than in recent years. Sticky inflationary pressures in the oil supply chain have been driven by downsizing, restructuring, merging and investment reduction at suppliers of specialized oilfield services, rigs, and other equipment in response to a prolonged downturn in the oil sector from 2015 throughout the COVID pandemic and now again with the 2025 oil price downturn, resulting in possible or actual constraints in the supply of vessels, rigs and skilled labor. Our capital plans included our best assumptions of expected cost increases due to inflation. To deliver on our expected rate of returns at our projects and on reducing the time-to-market of reserves we are planning to: 119 Table of Contents  performing project activities in accordance with a so-called parallel approach as opposed to a sequential approach, for example the discovery appraisal and pre-fid activities, by upgrading existing plants and vessels and by deploying a phased project approach to achieve early start-up and then ramping up production, thus reducing the time-to-market and financial exposure. An example of this approach is the Baleine project where we reached an initial production target of 70 Kbbl/d in just four years from the discovery (2021) by utilizing a refurbished floating production vessel to speed up activities. In the meantime, a new floating production vessel is being built to achieve the production ramp up to plateau. The Congo FLNG project, which started at the end of 2022, achieved the start of phase two by end of 2025 with the installation and commissioning of a second vessel for the floating production of LNG which has significantly increased installed LNG production capacity and is set to make its first LNG loading shortly. The development of gas reserves located in the Coral discovery area off Mozambique will be boosted by installation of a second unit for floating LNG production in the Coral North area, which is expected to start operations in just three years leveraging the know-how of the Coral South FLNG deployment;  signing master agreement with our main suppliers to maximize cost savings and by designing facilities using a modular approach that enables us to extend the useful lives of plants and vessels;  leveraging on near-field or infrastructure-led exploration that has proven to be effective at increasing the reserves at already producing fields thus enabling to exploit synergies from existing facilities so to reduce the time to market and extend the useful lives of existing plants. For example, the important natural gas discoveries off Indonesia, among which the recent Konta discovery, are planned to be developed through the production facilities existing in the area, including the spare capacity available at the Bontang liquefaction plant and the operated Jangkrik FSU vessel. Those development strategies will help reduce the time-to-market of reserves and obtain expenditures savings in development activities;  continuing in-sourcing of critical engineering and project management phases, for example by exercising tight control over construction, hook-up and commissioning, which based on our experience could significantly improve the ability of the Company to carry out projects on time and on budget;  applying our design-to-cost method whereby the Company has redirected its exploration efforts towards mature and low-complexity areas where we can achieve fast time-to-market and cost synergies, for example the Congo LNG project and the discoveries in Indonesia. We expect that cost control and profitable operations will be supported by continued progress in our technologies designed to improve drilling performance and the recovery factor and digital investment to improve workplace safety and asset integrity thus reducing asset downtime. According to our plans, exploration will continue ensuring cost-effective replacement of produced reserves and fast time to market, supporting cash generation and evolving our reserve portfolio towards the planned mix of resources featuring a larger proportion of natural gas relative to the portfolio as well as geographic diversification. Our exploration initiatives will comprise two clusters:  Exploration projects in near-field prospects and in proven/mature areas and in other infrastructure-lead basins i.e. in permits close to producing fields, where we can leverage existing infrastructures to readily develop the discovered resources, attaining fast contribution to cash flow and production levels with minimum impact on expenditures;  Selected initiatives in high-risk/high-rewards plays, where we retain high working interest and the operatorship, which will enable us to apply our dual exploration model in case of material discoveries with a view of accelerating the conversion of resources into cash. Our production plans include assumptions relating to production levels in certain countries that are particularly exposed to risks of disruptions and political instability, including possible disruptions to our production levels in the countries involved in the current Middle East conflict. To factor in possible risks of unfavorable geopolitical developments in those countries, which may lead to temporary production losses and disruptions in our operations in connection with, among others, acts of war, sabotage, hits to production facilities social unrest, clashes, and other form of civil disorder, we have applied a haircut to our future production levels based on management’s appreciation of those risks, past experience and other considerations. This contingency factor does not cover worst-case developments and extreme events, which could determine prolonged production shutdowns. Furthermore, in recent years we have pursued a strategy intended to diversify the geographic reach of our operations aiming at reducing the geopolitical risk in our portfolio. 120 Table of Contents Global Gas & LNG Portfolio The gas market is currently in a situation of oversupply driven by massive additions to LNG export capacity in USA, where production and LNG exports have reached all-time highs, Qatar where a large LNG project is set to come online shortly and then Canada where a first LNG export plant started operations, while the biggest gas-importing country, China, has slowed down its LNG purchases also due to rising internal production. Gas demand has been weakening due to the scale-up of renewable generation capacity in EU, China and elsewhere, rising competition from the nuclear energy and weak economic activity in EU, partly offset by rising consumption from data centers. We expect gas prices to weaken in the medium-to-long term. The current disruptions to LNG production in the Middle East as a consequence of the conflict situation are expected to impact the market fundamentals at least in the short term leading to increased price volatility. Against this backdrop, our GGP business has established a business model designed to achieve steady profitability and cash generation which are largely insulated from trends in natural gas prices and in market volatility. This business model is leveraging the continuing optimization of the segment’s asset portfolio (long-term contracts with contractual flexibilities, physical flows, access to transport capacity, availability of storage capacity, trading activities) and integration with E&P by trading growing amount of equity LNG to capture the full margin of the gas value-chain, as well as contractual renegotiations. Our planning assumptions are discounting the zeroing of natural gas purchases from Russia, although our long-term supply contracts with Russia’s state-owned company Gazprom are still in force. Our sales commitments relating to supplies to our retail subsidiary Plenitude, to our natural gas-fired power plants owned by the subsidiary EniPower and other ongoing selling obligations will be covered by purchases under our outstanding long-term contracts with suppliers other than Russian counterparts and by maximizing the integration between the E&P and the GGP segments. Against this scenario, the Company’s priority in its GGP business is to retain stable profitability and cash generation based on the following drivers: (i) To continuously renegotiate our long-term gas supply and sale contracts to align pricing terms and delivery quantities to current market conditions and dynamics as they evolve; (ii) To resume a growth trajectory in sales volumes by leveraging increasing supplies of LNG and signing sales contracts with Asian customers to balance and diversify the portfolio.; (iii) To improve margins by maximizing portfolio optimizations leveraging synergies between gas and LNG and assets flexibilities; (iv) To grow the LNG trading business leveraging on the integration with the E&P segment with the aim of maximizing the profitability of equity gas supplies along the entire value-chain. We plan to increase contracted supplies of LNG through new supplies from E&P’s equity production in Algeria, Congo, Qatar, Mozambique, and Cyprus leveraging the expected ramp-up of equity production of LNG to achieve a robust portfolio of reselling opportunities, aiming at obtaining a significant increase in contracted LNG volumes by 2030. We make use of commodities and financial derivatives to hedge against the risks of different indexation formulas in our gas procurement costs vs. selling prices in relation to contracted sales or highly probable sales. A number of these derivatives may be accounted as trading derivatives because they lack formal criteria to be treated as hedges in accordance with IFRS and consequently are recorded through profit and loss and may add a component of volatility to our results of operations. Those derivatives are normally risk-reducing, although there is also a degree of uncertainty about results. Furthermore, we are also making use of derivatives to improve margins by leveraging on market volatility and availability of assets like the flexibilities associated with our take-or-pay gas contracts, LNG contracts, transport rights to capture arbitrage opportunities (for example the winter vs summer spread, the spot vs. the Brent indexation spread) and time lags in contracts indexation formulae. Those asset-backed derivatives are of speculative nature with gains and losses recognized through profit. Although asset availability tends to limit the possible downside risks associated with those derivatives, still the Company is exposed to price volatility and to the incurrence of losses also of significant amounts. 121 Table of Contents Enilive (biofuels & marketing) Enilive, operational from January 1, 2023, has been established through the spin-out of Eni’s activities in the field of biofuels manufacturing and in the retail marketing of fuels and non-fuels products. It also engages in selling fuels to wholesale markets and the cargo market. Enilive is designated to market increasing volumes of decarbonized fuels to people on the move, leveraging integration with its biorefineries as well as to grow the share of revenues from non-fuel products and services leveraging emerging trends in mobility and marketing innovations. In 2025, Eni and private equity fund KKR completed an investment transaction whereby KKR acquired an ownership interest of 30% in the share capital of Enilive with net proceeds of €3.6 billion to Eni. Eni is retaining control of the entity. This transaction highlight the value of the Enilive business model which integrates manufacturing operations in the biofuels segment with a significant retail market presence based on a network of modern and advanced service stations. Enilive will leverage its integrated business model to improve profitability going forward. Our forecast is also assuming a gradual increase in the spreads of biofuels over the costs of feedstock, which include waste&residues and vegetable oils as demand for biofuels is seen rising in the medium term driven by shifting consumers’ preferences and a favorable regulatory environment with mandatory target of biofuels volumes supplied to the market in the Eu economic space and in the USA. According to our forecast, increasing biofuels consumption will occur both in road transport and in the airline sector, with global demand significantly exceeding supplies from the medium term onwards. To meet the expected increase in demand for biofuels, the Group is implementing an industrial plan to significantly grow the manufacturing capacity building a global business with the goal of reaching 5 million tons of installed capacity by 2030. The action plan contemplates upgrading existing plants, building and commissioning three biorefineries in Italy by reconverting traditional plants and international expansion with the expected start-up of two new plants under construction in South Korea in partnership with LG Chem and in Malaysia in partnership with Petronas and Euglena, as well as other initiatives at various stages of maturation. Our expansion will leverage our co-developed “Ecofining” technology to produce hydrogenated vegetable oils “HVO” and sustainable aviation fuels “SAF”, retaining high level of SAF optionality to capture market trends. The management is engaged in building a reliable and sustainable supply chain of bio-feedstock to be processed at the Company’s manufacturing units, maximizing feedstock flexibility. As part of that plan, we are developing a vertically integrated business model, which contemplates establishing a network of agricultural hubs in many of the countries of E&P operations, in Africa, in Italy and in other geographies. This activity is intended to not compete with the food chain and to produce a vegetable oil at Eni’s dedicated mills by treating supplies of raw vegetables grown by local farmers, supplied to Eni’s biorefineries under long-term agreements. The agricultural business will be scaled up in the planning period to reach a significant level of supplies by 2030. This vertical integration will strengthen Enilive’s access to supplies and boost margins on the production of biofuels, insulating our company from the volatility of raw materials costs. In Marketing activities, where we expect a very competitive environment, we are seeking to retain steady and robust profitability mainly by focusing on innovation of products and services anticipating customer needs, strengthening our line of premium products, as well as efficiency. We plan to enhance the network by upgrading several service stations to transform them from traditional outlets into mobility hubs to capitalize on the growing demand for a wider mobility experience and by expanding the number of service stations where we will market our innovative HVO-based biofuels and other alternative energy carriers (for example the service of recharging electric vehicles and biomethane). Profitability will be also supported by increasing sales of non-fuel products and services leveraging new formats and partnerships with established operators in various fields and cross-selling opportunities with retail customers of Plenitude. Based on those drivers, the management expects that Enilive will significantly improve its profitability going forward. 122 Table of Contents Plenitude Plenitude is Eni’s subsidiary managing the Group legacy business to sell gas and power to the residential sector, as well as the new businesses of renewable generation of electricity and a network of charging points for EV. Plenitude intends to leverage synergies among those businesses to improve its profitability going forward. Plenitude has the mission to supply its customers with increasing volumes of decarbonized energy commodities, contributing to the Group medium and long-term targets of reducing CO2 emissions. In 2025, Eni and private equity fund Ares completed an investment transaction whereby Ares acquired an ownership interest of 20% in the share capital of Plenitude with net proceeds to Eni of €2 billion. Previously, Eni and private equity fund EIP agreed an equity investment of almost €0.8 billion (structured in two deals with same characteristics in 2024 and 2025) whereby EIP acquired noncontrolling interest of 10% in the share capital of Plenitude. Eni is retaining control of Plenitude. Furthermore, as announced in March 2026, the management has commenced a reorganization of the shareholding structure of Eni’s subsidiary Plenitude, which is involving the current noncontrolling shareholders of the entity Ares fund and Energy Infrastructure Partners. The aim is to establish a new governance framework based on joint control between Eni and Ares, which will result in the derecognition of Plenitude from Eni's financial statements, with a significant improvement to Eni’s financial position. Completion of this deal has been assumed in Eni’s financial plans for 2026. Our forecast foresees that the EU power market will grow at a moderate pace till 2030 and that the environment for the expansion of renewable electricity production and generation capacity will remain supportive. In the retail market, we expect a very dynamic and competitive environment with the entrance of new operators and we see an opportunity in enhancing the offer to retail customers to preserve our market share. Finally, the business of recharges for EV will evolve in connection response to changing dynamics in the adoption rates of EV. We plan to accelerate the development of the installed renewable capacity of wind and solar plants to reach about 15 GW of installed capacity by 2030 by developing the existing portfolio of projects and leveraging external growth through selected and synergistic business combinations and joint ventures entities. We plan to expand our network of charging points for electric vehicles with the objective of installing 30 thousand rechargers by 2030, in line with the expected rates of adoption of electric vehicles and by selecting the expenditures targeting mature markets and highly profitable installations. In the retail segment, we plan to grow our customer base, leveraging the pending acquisition of energy provider Acea Energia to strengthen our presence in the core Italian retail market and growing selectively outside Italy with the target to reach 15 million customers in Europe by 2030. We plan to boost profitability per customer and to preserve the customers portfolio in the context of expected rising competitive pressures by enhancing scale and reach of the commercial offer. Planned commercial initiatives include increasing supply volumes of equity renewable energy, expansion of the offer of new products and services other than the commodity and continuing innovation in marketing processes including the deployment of digitalization in the acquisition of new customers, a reduction in the cost to serve and effective management of working capital. Customer retention and expansion will also leverage cross-selling opportunities and joint marketing initiatives with Enilive. Based on those drivers, the management expects that Plenitude will significantly improve its profitability going forward. Refining The downstream oil refining business is exposed to structural headwinds in the European sector due to lack of scale, global overcapacity, higher energy costs and environmental expenses than in other geographies and tough competition from player in Middle East, Far East and Africa which can count on advantages due to economies of scale, lower expenses and proximity to expanding markets. The profitability of our refining business will be affected by expected weak economic growth in Europe and a structural reduction in consumption of fossil fuels in our key European markets due to an expected penetration of EVs and mandated measures by EU governments to reduce CO2 emissions. Based on those assumptions, we plan to retain a strong focus on plant efficiency and reliability, cost discipline, measures to optimize energy consumption in the operations to maximize our realized refining margins. Considering the structural weaknesses of the refining sector in Europe, we plan to continue evaluating economically-viable solutions to restructure and downsize our oil-based, operated refineries in Italy. Currently, works have started to transform the Livorno hub into a biorefinery, based on the same reconfiguration process that we deployed in the past to upgrade the Gela and the Venice refineries. The Livorno biorefinery is expected to start operations at the end of 2026, and by that time it is planned to be contributed to Enilive. Alo the Sannazzaro hub will be restructured with construction of a biorefinery unit, where authorization from relevant Italian authorities have been achieved and a final investment decision by the management is expected shortly. Chemicals business In 2025, the Eni’s chemicals sector managed by the subsidiary Versalis reported another year of losses due to the structural weaknesses of the business of commodity plastics, because of global overcapacity and rising competition from producers in USA, Middle and East Asia, which are advantaged by economies of scale and lower operating expenses than European player like our Versalis, against the backdrop of sluggish economic growth in Europe and a slowdown in demand, which exacerbated the price competition. The Eni’s business was negatively affected by comparatively higher costs of plant utilities indexed to natural gas (for example the cost of natural gas in Europe is several times higher than in USA) and environmental obligations than in other geographies, which made overseas products more competitive than ours, and those trends negatively affected products margins and sales volumes. In 2025, realized margins of commodity plastics fell to their worst level in years. 123 Table of Contents Those negative trends are likely to continue affecting business performance in the future. Furthermore, the current disruptions to the streams of products from Middle East due to the ongoing conflict represent a risk to the profitability outlook of Versalis due to possible spikes in feedstock expenses. The Company is executing a comprehensive plan of restructuring and transformation of Versalis, which will leverage Eni’ technologies to establish new product platforms in the segments of transition and circular economy, as well as upgrading chemicals from bio-feedstock and specialties, seeking to reduce exposure to the most commoditized market segments and to achieve a structurally more sustainable and competitive products mix. In the course of 2025, two large, loss-making cracking units, the ones at Brindisi and Priolo, were definitively shut down and works have started to reconvert the two hubs in manufacturing districts for the renewable energies. The improvement in the Group profit and loss and cash flow due to those closures are expected to show off in 2026. The levers of the industrial plan comprise: (i) to complete restructuring and upgrading of the hubs which were shut down in 2025 and to restructure other loss-making plants aiming at reducing the exposure towards the most commoditized segments of the industry; (ii) to develop the segment of bioplastics and biochemicals leveraging the integration of the recently-acquired Novamont and by ensuring the supply of competitive and flexible feedstock; (ii) to increase the weight of differentiated products called “specialties” which, based on our experience, are more profitable than commodity plastics, also leveraging on growing our market share in the compounding and specialized formulations through Finproject that we acquired in 2021, (iv) to develop the business of the circular economy by increasing production of polymers made from the mechanical recycling of waste plastics or through the expected scale-up of a technology for producing polymers via the chemical recycling of waste plastics, currently in a pilot phase; (v) to reduce fixed costs and to further rationalize capital expenditures. Based on those actions, the management expects Versalis to recover profitability by the end of the plan period. Expected Group financial performance For 2026, we expect net cash provided by operating activities (“operating cash flow”) and cash from divesting activities to be the main sources of cash to fund our capital plans, returns to shareholders and other commitments. Our operating cash flow is mainly driven by our E&P business due to its relatively larger size and higher profitability compared to our other businesses. Therefore, our operating cash flow is exposed to the volatility of hydrocarbons prices, that are highly correlated to the macroeconomic cycle, the global balance between demands and supplies and the worldwide levels of inventories, among others. Based on our experience, those backdrop conditions can vary very rapidly. Furthermore, due to physical characteristics of reservoirs and fields, oil supplies have a little degree of flexibility in the short term to respond to eventual swings in demand, which can be swift and significant. Accordingly, hydrocarbons prices corrections can be sudden and severe. Due to those considerations, our operating cash flow features high variability and little predictability. The 2026 outlook is compounded by many risks and uncertainties in connection with the uneven pace of recovery in the global economy, considering an ongoing slow pace in the Chinese economy which is the second largest consumer of crude oil in the world, stagnant activity in the Eurozone, the impacts of trade disputes on international commerce, the willingness of the OPEC+ cartel to stick with its current plans of gradually tapering the production cuts and the level of compliance of cartel members with quotas, the monetary policy of the US Federal Reserve, and finally the evolution of the conflict between Russia and Ukraine and other geopolitical risk factors, particularly the escalating tensions in the Middle East which culminated in acts of war involving USA, Israel and Iran, and Iranian retaliatory attacks in the Gulf area and Israel with possible risks of enlargement of the conflict. Any negative development in the macroeconomic context could negatively affect demand for crude oil and the price of the barrel. From an industrial standpoint the greatest uncertainties will involve the ability of US shale producers to continue growing production despite financial discipline and reports from market sources that shale growth may have plateaued. Another factor will be the evolving situation in Venezuela and the Country’s ability to revive its ailing oil sector with the support of international oil companies, which could add more supplies to an already oversupplied market. Considering those risks and uncertainties, we have retained flat Brent price assumptions, and we are forecasting a crude oil price at 70 $/bbl for 2026. As disclosed in Item 3, our results of operations and cash flow are subject to trends in crude oil prices and, to a lesser extent, prices of natural gas and products. We estimate that each one-dollar change in the price of the Brent crude oil from our planning assumption impacts our cash flow from operation by around €110 million. This sensitivity applies for a given range of variation in the price of crude oil. We are assuming spot prices of natural gas at European hubs to be around 12 $/mmBTU, flat compared to 2025, and the Company’s gouge of the refining trading environment, SERM at 6 $/bbl, lower than in 2025. The average EUR vs USD exchange rate is assumed at 1EUR=1.15 USD. We are estimating our cash flow from operations to vary by about €80 million for each one-dollar change in the spot prices of natural gas in Europe, while we are estimating our cash flow from operations to vary by about €90 million for each one-dollar change in the SERM. The Group’s results and cash flow are also exposed to trends in the exchange rate of the EUR vs the USD; currently, we are estimating our cash flow from operating activities to vary by about €390 million for a 5 USD/cent movement in the EUR/USD cross rate. 124 Table of Contents Against the volatility of our operating cash flows, our funding requirements for developing hydrocarbons reserves are characterized by a low degree of flexibility. The E&P segment is a capital-intensive business and needs large amounts of financial resources to support production volumes and to develop new oil&gas reservoirs. Hydrocarbons development projects are long lead-times projects due to the complexity of activities to be carried out before production is achieved, hence the payback of capital projects usually begins in a very distant future, leaving the Company exposed both financially and to price volatility during the execution phase. Once a final investment decision has been made to develop a new hydrocarbon field and contracts have been signed to build production facilities, platforms, vessels, FPSO units and other equipment, management may face difficulties at postponing or stopping cash outlays in response to a sudden contraction in operating cash flows. Management can reduce incremental investments at producing fields, like workover or infilling operations, when economic and operating conditions allow for that. The Company is executing an important growth plan and in case the scenario for crude oil and gas prices evolves adversely, the Company may experience a cash flow shortfall leading to inability to fund its capital commitments and the dividend by internally generated funds. In such a situation, the Company could be forced to take on new debt or to draw its liquidity reserves and that could negatively affect the Company’s results of operations, returns, and put at risk its targets of financial structure. We plan to make an amount of capital expenditures of around €7 billion in 2026, driven by new project start-ups and ramp-ups in E&P, cost inflation, by development of the renewable generation capacity of our subsidiary Plenitude, the manufacturing capacity of biofuels, and the restructuring of the chemicals business and refineries. The business of renewable generation is currently absorbing cash because it is in a ramp-up phase. Furthermore, we expect to fund a significant portion of the planned cash requirements in 2026 through the execution of an asset disposal plan which will encompass a possible dilution of our working interest in E&P assets (for example large discovery areas or fields currently in production phase) and other disposals. Those proceeds are included in our 2026 financial plan. Furthermore, as announced in March 2026, the management has commenced a reorganization of the shareholding structure of Eni’s subsidiary Plenitude, which is involving the current noncontrolling shareholders of the entity Ares fund and Energy Infrastructure Partners. The aim is to establish a new governance framework based on joint control between Eni and Ares, which will result in the derecognition of Plenitude from Eni's financial statements, with a significant improvement to Eni’s financial position. Completion of this deal has been assumed in Eni’s financial plans for 2026. Execution of this disposal plan is exposed to risks in connection with an uncertain macro-outlook and the announcement of asset disposal plans by several companies competing with Eni, which could reduce transaction values. Management is retaining a prudent financial framework, based on capital and cost discipline, selective investment criteria, pre-set cash allocation priorities and retention of a maximum limit of ratio of indebtedness. New capital projects are approved when they fit strict economic criteria, including being profitable in a low-price environment and having short pay-back periods and reduced time-to-market to limit financial exposure. By applying those criteria, we aim to increase projects’ resilience to possible risks relating to price volatility and, in the long-term, to the energy transition. One of the pillars of our financial discipline is our internal requirement of self-financing the planned capital expenditures through operating cash flows, leaving a surplus to fund other cash requirements, first the dividend and financial obligations at maturity. For 2026 under our pricing, exchange and inflation rates assumptions, we expect to generate enough cash flow from operations to fund the planned capital expenditures of about €7 billion, leaving a surplus. That surplus and the expected proceeds from our disposal plan will be deployed to fund other Company’s cash commitments, which will mainly comprise cash returns to shareholders, disbursements in connection with pending acquisitions and the repayment of lease liabilities and other commitments, among which dividends to noncontrolling interests, retaining a preset ratio of net borrowings to total sources of funds “gearing” which is expected to remain within the range set by the management at 0.1-0.15. For further information see Item 3 – Risk factors and notes to the consolidated financial statements. This financial framework is completed by the maintenance of a liquidity reserve consisting of cash on hand, marketable securities and committed credit lines, which have been dimensioned to help the Company withstand a sudden contraction in operating cash flows, a spike in the volatility of commodity prices leading to increased margining obligations in connection with our derivatives transactions, or short-term difficulties in accessing capital markets. At the end of 2025 this liquidity reserve amounted to €18.8 billion of cash on hand and held-for-trading securities and other financing receivables and €9 billion of committed borrowings facilities. The actions planned in the next five-year period featuring profitable hydrocarbons production growth, an increasing contribution of our transition businesses managed by Plenitude and Enilive due to a planned expansion of renewable capacity, biofuels manufacturing capacity additions, continuing gas and LNG portfolio optimizations in GGP, and expected progress in the restructuring of downstream oil businesses coupled with capital and cost discipline will underpin a solid cash generation. On those bases, and considering the proceeds expected from the execution of our disposal plan, we expect to be in a position to ensure competitive shareholders returns and to retain a robust balance sheet with our core ratio of net borrowings to total equity plus net borrowings (both before IFRS 16 lease liabilities) – gearing – expected to remain within a planned range of 0.1-0.15 across the plan period. In the next five-year plan 2026-2030, we expect to incur about €29 billion of capital expenditures, of which a major part is planned to be directed to the exploration and development of hydrocarbons reserves. To support the Group cash generation, we are planning to execute a cost saving program of about €2.3 billion in the period 2024-2027, which was raised from a previous €1.8 billion target. Due to cash flow unpredictability as a function of the scenario volatility, management is always allocating a portion of funds to uncommitted projects, which can be more comfortably cancelled or postponed in case of a downturn in oil prices. In the five-year plan 2026-2030 out of the planned capital budget of €29 billion, the portion allocated to uncommitted projects represents on average more than 30% of expenditures in each year of the financial projections. 125 Table of Contents Our financial projections and capital investment decisions are based on management’s appreciation of the cost of capital to the Group at about 6% post-tax. This rate is in line with 2024 because a perceived reduction in the volatility of Eni’s share and a reduced market risk premium were offset by higher expected interest rates on debt. When making final investment decisions, the thresholds against which specific investment internal rate of returns are benchmarked are defined by adding to the above-mentioned cost of capital, a risk premium associated with the country where the investment will be executed and an additional business risk premium to cover high-risk investments (like exploration projects) and to provide an extra return. This financial outlook is subject to the volatility of crude oil prices and to the other risk factors described in Item 3. Remuneration policy Management is committed to delivering on a progressive and competitive shareholder remuneration policy, that is reflective of the expected improvement in underlying earnings and cash flows on a constant scenario basis and of the increased resiliency of the business to cyclical fluctuations. In setting the level of shareholders’ remuneration, management is also considering its assumptions about future trends in crude oil prices and in other market variables. As part of that framework, the management is planning to return shareholders an amount of cash representing a portion in a range of 35 to 45% of the expected cash flow from operations before working capital requirements “adjusted cash flow”. That portion is higher than the previous range of 35-40% to take into account a perceived solid financial structure of the Company, lower expected expenditures than in the past and a growing contribution of dividends from equity-accounted entities to the cash flow. In 2025, the management gauged this adjusted cash flow measure at around €12.5 billion and cash returns to shareholders came in close to the upper limit of that range as we returned €5 billion of cash to shareholders comprising the 2025 dividend of €1.05 per share (equal to €3.15 billion, with the third and fourth instalments to be distributed in the first half 2026) and the 2025 buy-back program of €1.8 billion, which was completed in February 2026. Going forward, distributions will continue contemplating a combination of dividends and share repurchases. We expect to gradually increase the dividend in future years in line with the expected improvement in the Group underlying financial performance, and to enhance the dividend resilience to the scenario. Share repurchases will complement the dividend and are intended as a flexible tool to distribute raising amount of cash generated by the business in case of upside in the scenario variables, a better than budgeted company’s performance or other factors. For the full year 2026, we expect to distribute shareholders an amount equal to 40% of the adjusted cash flow which will be earned by the Company under the assumption of 70 $/bbl of Brent crude oil (nominal terms) through dividends and share repurchases. According to our financial framework, in case the Group results of operations are trending higher than management’s plans due to a better pricing environment than management expectations (i.e. a Brent crude oil price higher than 70 $/bbl) and/or an improved business underlying performance, management intends to distribute up to 60% of the incremental cash flows through share repurchases (in line with the past), until management’s expected Brent crude oil price for the full year reaches 90 $/bbl on average. In case management’s forecast of the Brent crude oil price exceeds 90 $/bbl for 2026 full year, the Company intends to distribute shareholders 100% of the incremental adjusted cash flow at a Brent price higher than 90 $/bbl and/or other scenario variables 50% above planned levels (namely spot natural gas prices and refining margins) as extraordinary dividend. In case the commodity scenario underperforms management’s expectations, the Company plans to leverage on its financial flexibility as well as on possible revisions of the capital expenditure plans considering the proportion of uncommitted projects in our development portfolio, to preserve shareholders’ returns. For 2026, having assessed the progress of the Company in executing its strategy, based on a sound financial position and management scenario assumptions, management is planning to increase the yearly dividend to €1.1 per share, up 4.8% from 2025. This dividend is expected to be paid in four equal quarterly instalments in September 2026, November 2026, March 2027, and May 2027. Therefore, the expected cash out for dividend payments in 2026 will include two instalments of the 2025 dividend of €0.26 per share each, and two instalments of the planned 2026 dividend of €0.27 per share each. Consistently with its remuneration policy, for 2026 Eni plans to execute a share buyback program of at least €1.5 billion assuming a Brent scenario of 70 $/bbl and that the Company delivers its planned adjusted cash flow for the year. Execution of this buyback program is subject to shareholders’ approval at the Annual General Meeting scheduled for May 2026. In case of a better oil price environment and/or better business underlying performance, the buyback is expected to be increased to an upper limit of €4 billion. 126 Table of Contents Off-balance sheet arrangements Eni has entered into certain off-balance sheet arrangements, including several guarantees and commitments, as described in “Item 18 – Note 28 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements”. Eni’s principal contractual obligations, including commitments undertake-or-pay or ship-or-pay contracts in the gas business, are disclosed under “Contractual obligations” in the same footnote. See the Glossary for a definition of take-or-pay or ship-or-pay clauses. Those off-balnce sheet agreements also comprise various forms of guarantees provided by Eni on behalf of unconsolidated subsidiaries and affiliated companies, mainly relating to guarantees for loans, lines of credit and performance under contracts. Off-balance sheet arrangements comprise those arrangements that may potentially impact Eni’s liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of Eni’s business purposes, Eni is not dependent on these arrangements to maintain its liquidity and capital resources; nor is management aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on the Company’s financial condition, results of operations, liquidity or capital resources. Liquidity risk Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace as to be unable to meet short-term financing requirements and to settle obligations. Such a situation would negatively impact the Group results and cash flow as it would result in the Company incurring higher borrowing expenses to meet its obligations, divesting assets at discount to their fair values or under the worst of conditions the inability of the Company to continue as a going concern. At present, the Group believes it has access to sufficient funding and has also both committed and uncommitted borrowing facilities as we retain cash reserves and cash on hand to meet currently foreseeable funding requirements. The Group cash reserve consists of cash on hand and very liquid financial assets (short-term deposits, held-for-trading securities and other financial assets) of €18.8 billion and committed borrowing facilities of €9 billion. This liquidity reserve based on our financial framework can alternatively be used to absorb temporary swings in cash flows from operations, to provide financial flexibility to pursue the Group development programs or to fund the Group contractual obligations with respect to the repayment of financing debt at maturity up to a 48-month horizon. For a description of how the Company manages the liquidity risk see “Item 18 – Note 28 to the Consolidated Financial Statements”. Due to the continued volatility in commodity markets, we might incur increased liquidity risks due to the need to deposit larger amounts of cash collateral at financial institutions and commodity-based exchanges to guarantee the settlement of derivatives contracts (margin calls). The Group is continuously assessing the ability of its financial headroom to cope with possible market turbulence and volatility. To withstand uncertain financial markets and macroeconomic conditions, the Group has retained a level of financial flexibility in planning future capital requirements to grow the business, as a portion of the capital expenditure plan of €29 billion of the five-year period 2026-2030 is allocated to uncommitted projects (more than 30% on average in the plan). Working capital Management believes that, considering unutilized credit facilities, the Company’s liquidity reserves, our credit rating and access to capital markets, Eni has sufficient working capital for its foreseeable requirements. 127 Table of Contents Credit risk Credit risk is the risk that our commercial or financial partners fail to pay amounts due to us in connection with the provision of goods and services, financing or derivatives transactions. In recent years, the Group has experienced a significant level of counterparty default due to Europe and Italy’s weak economic growth and financial difficulties affecting national oil state-owned entities and local companies, which are joint operators in Eni-lead projects. It is possible that the ability of our debtors to pay amounts due to us will deteriorate in the next future, in case of a deepening of the current economic slowdown, leading us to recognize significant amounts of expected credit losses in future reporting periods. For a description of how the Company manages the credit risk see “Item 18 – Note 28 to the Consolidated Financial Statements”. For more information about the allowance for doubtful accounts calculated in accordance with the expected credit loss model see “Item 18 – Note 8 to the Consolidated Financial Statements”. Volatility of the macro environment Global financial markets are volatile due to several macroeconomic risk factors and unpredictable developments. In case of unpredictable developments in the Russia military aggression against Ukraine or in the Middle-East tensions, intensification of trade disputes between the USA and its main trading partners, or a financial crisis triggering a downturn in economic activity and energy demand, in the event of a credit crunch, or if Eni is unable to access the financial markets (including cases where this is due to Eni’s financial position or market sentiment as to Eni’s prospects) at a time when cash flows from Eni’s business operations may be under pressure, the Company may incur significantly higher borrowing costs than in the past or difficulties obtaining the necessary financial resources to fund Eni’s development plans, therefore jeopardizing Eni’s ability to maintain long-term investment programs. A reduction in the investments needed to develop Eni’s reserves and to grow the business may significantly and negatively affect Eni’s business prospects, results of operations and cash flows, and may impact shareholder returns, including dividends and share price appreciation. The retention of cash reserves and borrowing facilities and the financial flexibility in the expenditure program are tools that Eni may activate in case of unfavorable macro developments and systemic crises. Market risk The fair values of Eni’s financial assets and liabilities as well as expected cash flow from highly probable transactions are exposed to movements in commodity prices, currency fluctuations and changes in interest rates. Unfavorable movements in prices and rates could significantly and negatively affect Eni’s results of operations and cash flow. The Group does not hedge its strategic exposure to volatile hydrocarbons prices in the activity of producing its oil&gas reserves, except for specific transactions or particular market circumstances. Other strategic, unhedged exposures include long-term gas supply contracts for the portion not balanced by sales contracts (already stipulated or expected), the margin deriving from the chemical transformation process, the refining margin and long-term storage functional to the logistic-industrial activities. The Group enters into commodity derivatives to manage exposure to price volatility in commercial activities involving the reselling of commodities in view of optimizing margins. Frequently, exposures to price volatility or to different indexation between the cost of supplies and the reselling prices are not hedged on a transaction-by-transaction basis; instead, exposures are pooled at Group level and derivatives are activated to hedge net exposures, with gain and losses recognized through profit. Eni’s euro-denominated subsidiaries incur revenues and expenses in currencies other than the euro or are otherwise exposed to currency fluctuations because prices of oil, natural gas and refined products generally are denominated in, or linked to, the U.S. dollar, while a significant portion of Eni’s expenses are incurred in euros and because movements in exchange rates may negatively affect the fair value of assets and liabilities denominated in currencies other than the euro. Therefore, movements in the U.S. dollar (or other foreign currencies) exchange rate versus the euro affect results of operations and cash flows and year-on-year comparability of the performance. These exposures are normally pooled at Group level and net exposures to exchange rate volatility are netted on the marketplace using derivative transactions. However, the effectiveness of such hedging activity is uncertain, and the Company may incur losses also of significant amounts. Eni is exposed to fluctuations in interest rates that may affect the fair value of Eni’s financial assets and liabilities as well as the amount of finance expense recorded through profit. Eni enters into derivative transactions with the purpose of minimizing its exposure to the interest rate risk. For a description of how the Company manages the Market risk see “Item 18 – Note 28 of the Notes on Consolidated Financial Statements”. Research and development For a description of Eni’s research and development operations in 2025, see “Item 4 – Research and development”. 128 Table of Contents