Eni S p A : Fact Book 2025 06 May 2026 Press Release

About this update from Eni S.p.a.

Fact 2025 Book Mission We are an energy company. We concretely support a just energy transition, with the objective of preserving our planet and promoting an efficient and sustainable access to energy for all. Our work is based on passion and innovation, on our unique strengths and skills, on the equal dignity of each person, recognizing diversity as a key value for human development, on the responsibility, integrity and transparency of our actions. We believe in the value of long-term partnerships with the Countries and communities where we operate, bringing long-lasting prosperity for all. Global goals for a sustainable development The 2030 Agenda for Sustainable Development, presented in September 2015, identifies the 17 Sustainable Development Goals (SDGs) which represent the common targets of sustainable development on the current complex social problems. These goals are an important reference for the international community and Eni in managing activities in those Countries in which it operates. ‌Eni Fact Book 2025 Eni at a glance Main data 4 Eni share performance 6 Financial Data 9 Quarterly information 20 Operating review Exploration & Production 28 Global Gas & LNG Portfolio and Power 57 Enilive and Plenitude 65 Refining and Chemicals 77 Environmental activities 88 Annex Results by business segment 92 Employees 98 Energy conversion table 99 Disclaimer Eni's Fact Book is a supplement to Eni's Annual Report and is designed to provide supplemental financial and operating information. It contains certain forward-looking statements regarding capital expenditures, dividends, buy-back programs, allocation of future cash flow from operations, financial structure evolution, future operating performance, targets of production and sale growth and the progress and timing of projects. By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that will or may occur in the future. Actual results may differ from those expressed in such statements, depending on a variety of factors, including: possible evolution in respect of the conflict between Russia and Ukraine and in the Middle East; the timing of bringing new oil and gas fields on stream; management's ability in carrying out industrial plans and in succeeding in commercial transactions; future levels of industry product supply; demand and oil and natural gas pricing; operational problems; general macroeconomic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; development and use of new technology; changes in public expectations and other changes in business conditions; the actions of competitors. ‌Eni at a glance A CLEAR STRATEGY DRIVING GROWTH AND RESILIENCE THROUGH THE CYCLE STRATEGY EXECUTION & KEY MILESTONES 2025: DELIVERING ON OUR STRATEGY 2025 OUTCOMES In 2025, Eni achieved significant progress in executing its transformation strategy, which combines the valorization of traditional activities with the development of transition businesses. E&P's outstanding results were driven by accretive production growth and cost management. Enilive and Plenitude delivered material value and growth, further diversifying and strengthening the Group's earnings. These achievements are based on solid pillars: organic growth, diversification, vertical integration, new technology developments, and the adoption of innovative business models. The strengthening of the portfolio, and the application of a disciplined capital allocation, contributed to increase the Group's resilience facing market volatility, also thanks to balance sheet strength and debt reduction, which have enabled increased shareholders' returns. Organic and profitable growth is at the heart of our sustainable value chain, driven by our industry-leading exploration, technological know-how in the upstream with fast time-to-market and our ability to open up new opportunities in the transition. Our growth strategy is balanced in terms of risk-rewards through our unique Dual Exploration and satellite model. E&P A DISTINCTIVE GROWTH ENGINE Outstanding exploration-led portfolio supporting a deep, diversified development pipeline with industry-leading time-to-market. TRANSITION CREATING DIVERSIFIED VALUE Scaling transition platforms delivering material growth and diversification through distinctive, self-funding business models. TECHNOLOGY ENABLING DIFFERENTIATION & NEW OPPORTUNITIES Technology leadership strengthening E&P competitiveness while enabling new opportunities in CCS, batteries and lower carbon energy. FINANCIAL MODEL SATELLITES AND FINANCIAL STRENGTH Satellite model unlocking value and attracting strategic partners, supported by strong financial discipline and a robust balance sheet. GLOBAL NATURAL RESOURCES UPSTREAM • 4% underlying production growth (6 main start-ups) top end of guidance (with 4 major FIDs) 900 mmboe new resources discovered 1.0 bbbl proved reserves additions, RRR 167% organic top performer vs. peers Agreements with YPF and XRG on Argentina LNG and Indonesia-Malaysia business combination with PETRONAS GGP • 15 MTPA LNG contracted volumes New LNG long-term agreements with Venture Global, TRANSITION & TRANSFORMATION PLENITUDE • Rising renewables generation integrated with clients, 5.8 GW (+41% y-o-y) ENILIVE • Biorefineries construction begun in Livorno, South Korea and Malaysia Sannazzaro project approved, Q8 partnership for construction of Priolo biorefinery VERSALIS • Transformation plan in execution, with closure of Brindisi and Priolo ahead of plan Gulf & Botas, and positive contracts renegotiation CCS • Closing of the transaction with GIP for the investment in Eni CCUS Holding CORPORATE ENI INDUSTRIAL EVOLUTION Launched new company for transformation RESULTS AHEAD • Stronger than expected cash generation NET CAPEX WELL BELOW GUIDANCE • €4.4 bln proforma ENHANCED BUY-BACK & DIVIDEND • €4.9 bln total distribution (~40% payout). Unique among peers in raising buy-back REDUCED GEARING • 15% from 18% YE 2024, 14% proforma PRODUCTION 1.73 mmboe/d GROUP CFFO ADJ €12.5 bln GGP PROFORMA ADJ EBIT ENILIVE PROFORMA ADJ EBITDA >€1.0 bln €1.0 bln CASH INITIATIVES €4 bln NET CAPEX €4.4 bln PLENITUDE PROFORMA ADJ EBITDA €1.1 bln SHAREHOLDERS REMUNERATION €1.05 dividend per share €1.8 bln buy-back ‌Main data KEY FINANCIAL DATA (€ million) 2025 2024 2023 2022 2021 2020 2019 2018 Net sales from operations 82,151 88,797 93,717 132,512 76,575 43,987 69,881 75,822 Operating profit (loss) 5,010 5,238 8,257 17,510 12,341 (3,275) 6,432 9,983 Exclusion of special items 2,589 4,676 4,986 3,440 (1,186) 3,855 2,388 1,161 Exclusion of inventory holding (gains) losses 745 434 562 (564) (1,491) 1,318 (223) 96 Adjusted operating profit (loss) (a) 8,344 10,348 13,805 20,386 9,664 1,898 8,597 11,240 Proforma adjusted operating profit (loss) (a) 12,223 14,322 17,809 25,333 - - - - Net profit (loss) (b) 2,608 2,624 4,771 13,887 5,821 (8,635) 148 4,126 Adjusted net profit (loss) (a)(b) 4,989 5,257 8,322 13,301 4,330 (758) 2,876 4,583 Net cash flow from operating activities 13,330 13,092 15,119 17,460 12,861 4,822 12,392 13,647 Capital expenditure 8,647 8,485 9,215 8,056 5,234 4,644 8,376 9,119 Shareholders' equity including non-controlling interests at year end 52,787 55,648 53,644 55,230 44,519 37,493 47,900 51,073 Net borrowings at year end before IFRS 16 (a) 9,386 12,175 10,899 7,026 8,987 11,568 11,477 8,289 Net borrowings at year end after IFRS 16 (a) 15,086 18,628 16,235 11,977 14,324 16,586 17,125 n.a. Gearing before lease liability ex IFRS 16 (a) (%) 15 18 17 11 17 24 19 14 Gearing after lease liability ex IFRS 16 (a) (%) 22 25 23 18 24 31 26 14 Net capital employed at year end 67,873 74,276 69,879 67,207 58,843 54,079 65,025 59,362 Adjusted ROACE (a) (%) 7.6 7.6 12.3 22.0 8.4 (0.6) 5.3 8.5 Non-GAAP measures. Attributable to Eni's shareholders. KEY MARKET INDICATORS 2025 2024 2023 2022 2021 2020 2019 2018 Average price of Brent dated crude oil in U.S. dollars (a) ($/barrel) 69.06 80.76 82.62 101.19 70.73 41.67 64.30 71.04 Average EUR/USD exchange rate (b) 1.130 1.082 1.081 1.053 1.183 1.142 1.119 1.181 Average price of Brent dated crude oil (€ barrel) 61.12 74.64 76.43 96.09 59.80 36.49 57.44 60.15 Standard Eni Refining Margin (SERM) (c) ($ barrel) 7.3 5.1 8.1 8.1 (0.9) 1.7 4.3 3.7 TTF (d) (€/MWh) 36 34 41 121 46 9 13 23 PSV (d) (€/MWh) 39 36 42 122 46 10 16 25 Source: S&P Global Energy. Source: BCE. Source: In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations. In €/MWh. Source: ICIS European Spot Gas Markets. SELECTED OPERATING DATA Climate 2025 2024 2023 2022 2021 2020 2019 2018 Net Scope 1+2 Upstream (a)(c) (Mt CO 2 eq.) 4.7 6.8 9.0 n.a. n.a. n.a. n.a. 14.5 Net Scope 1+2 Eni (a)(c) 21.4 23.8 26.7 n.a. n.a. n.a. n.a. 35.8 Intensity Net Scope 1+2+3 (b)(c) (gCO 2 eq./MJ) 59.0 59.2 60.1 n.a. n.a. n.a. n.a. 62.7 Direct GHG emissions (Scope 1) (d) (Mt CO 2 eq.) 18.6 21.2 22.7 25.0 26.9 25.7 28.3 30.8 Indirect GHG emissions (Scope 2) (d) 0.5 0.6 0.6 0.6 0.7 0.6 0.6 0.6 Methane direct emission (Scope 1) (d) (ktonnes CH 4 ) 14.8 16.0 16.6 26.4 29.6 33.5 36.1 69.1 Health, Safety and Environment (e) 2025 2024 2023 2022 2021 2020 2019 2018 Total Recordable Injury Rate (TRIR) (total recordable injuries/worked hours) x 1,000,000 0.55 0.70 0.57 0.51 0.49 0.48 0.42 0.40 of which: employees 0.60 0.73 0.66 0.41 0.55 0.51 0.27 0.41 contractors 0.51 0.68 0.52 0.56 0.46 0.46 0.47 0.40 Total volume of oil spills (>1 barrel) (barrels) 217 2,815 12,719 5,628 4,361 5,641 6,665 5,819 of which: due to sabotage and terrorism 0 2,140 5,094 5,253 3,053 4,861 6,245 3,602 operational 217 675 7,625 375 1,308 780 420 2,217 Freshwater withdrawals (mmcm) 114 127 109 101 113 107 122 112 Re-injected produced water (%) 56 51 42 43 46 40 45 46 Innovation 2025 2024 2023 2022 2021 2020 2019 2018 R&D expenditure (€ million) 207 178 166 164 177 157 194 197 First patent filing application (number) 42 39 28 23 30 25 34 43 Employees 2025 2024 2023 2022 2021 2020 2019 2018 Italy (number) 22,006 22,100 21,749 20,878 21,035 21,575 21,488 21,002 Outside Italy 10,343 10,392 11,393 11,310 11,654 9,920 10,565 40,699 Total Group 32,349 32,492 33,142 32,188 32,689 31,495 32,053 61,701 of which: Senior Managers 896 945 960 966 986 982 1,037 1,025 Middle Managers and Senior Staff 9,460 9,346 9,349 9,133 9,196 9,245 9,461 9,227 White collar workers 16,357 16,476 16,557 15,903 15,970 16,285 16,403 16,208 Blue collar workers 5,636 5,725 6,276 6,186 6,537 4,983 5,152 5,241 KPIs calculated on a consolidated basis. The 2024 and 2023 data are reported accordingly. KPI includes Scope 1+2 emissions (consolidated scope) and Scope 3 emissions from the use of products sold (Cat.11), estimated on the basis of Eni's equity share of upstream production. The 2024 and 2023 data are reported accordingly. KPIs reported in the Sustainability Report from 2025; data for the 2019-2022 period are not available. The 2018 data are presented solely as a baseline year for calibrating the targets associated with these KPIs. KPIs refer to 100% of the operated assets, consolidated and unconsolidated, with reference to the operatorship criteria expressed in the standards of the Sustainability Statement. KPIs refer to 100% of the operated assets, consolidated and unconsolidated. ‌ENI SHARE PERFORMANCE SHARE DATA 2025 2024 2023 2022 2021 2020 2019 2018 Net profit (loss) (a)(b) (€) 0.78 0.78 1.40 3.95 1.60 (2.42) 0.04 1.15 Dividend pertaining to the year 1.05 1.00 0.94 0.88 0.86 0.36 0.86 0.83 Dividend to Eni's shareholders pertaining to the year (c) (€ million) 3,176 3,094 3,034 2,972 3,055 1,286 3,078 2,989 Cash dividend to Eni's shareholders 3,080 3,068 3,046 3,009 2,358 1,965 3,018 2,954 Cash flow (a) (€) 4.41 4.13 4.58 5.01 3.61 1.35 3.45 3.79 Dividend yield (d) (%) 6.56 7.6 6.2 6.5 7.1 4.2 6.3 5.9 Net profit (loss) per ADR (a)(b)(e) ($) 1.76 1.69 3.03 8.32 3.78 (5.53) 0.09 2.72 Dividend per ADR (e) 2.42 2.16 2.02 1.84 1.92 0.86 1.89 1.89 Cash flow per ADR (a)(e) (%) 9.97 8.94 9.90 10.55 8.54 3.08 7.72 8.95 Dividend yield per ADR (d)(e) 6.6 7.6 6.2 6.5 7.1 4.2 6.3 5.9 Number of shares outstanding at period-end (f) (million) 2,957.7 3,081.4 3,218.8 3,345.4 3,539.8 3,572.5 3,572.5 3,601.1 Weighted average number of shares outstanding (f) 3,024.8 3,167.0 3,303.8 3,483.6 3,566.0 3,572.5 3,592.2 3,601.1 Total Shareholders Return (TSR) (%) 32 (9) 23 16 52 (34) 7 5 Fully diluted. Ratio of net profit/cash flow and average number of shares outstanding in the period. Dollar amounts are converted on the basis of the average EUR/USD exchange rate quoted by Reuters (WMR) for the period presented. Pertaining to Eni's shareholders. The amount of dividend for the year 2025 is based on the Board's proposal. Ratio between dividend of the year and average share price in December. One ADR represents 2 shares. Net profit, dividends and cash flow data were converted using average exchange rates. Dividends data were converted at the Noon Buying Rate of the pay-out date. Calculated by excluding own shares in portfolio. SHARE INFORMATION 2025 2024 2023 2022 2021 2020 2019 2018 Share price - Milan Stock Exchange High (€) 16.53 15.73 15.70 14.53 12.75 14.32 15.94 16.76 Low 11.23 12.70 12.16 10.64 8.20 5.89 13.04 13.33 Average 14.36 14.34 14.06 12.81 10.56 8.96 14.36 15.25 Year end 16.14 13.09 15.35 13.29 12.22 8.55 13.85 13.75 ADR price (a) - New York Stock Exchange High ($) 38.27 34.12 34.19 32.49 29.70 32.12 36.17 40.09 Low 25.19 26.32 25.80 20.44 19.97 13.71 28.84 30.00 Average 32.60 31.00 30.42 27.04 24.98 20.28 32.12 35.98 Year end 37.94 27.36 34.01 28.66 27.65 20.60 30.92 31.50 Average daily exchanged shares (million shares) 11.59 10.63 11.44 14.56 17.03 20.40 11.41 12.99 Value (€ million) 164 152 160 187 179 178 164 197 Weighted average number of shares outstanding (b) (million shares) 2,957.7 3,167.0 3,303.8 3,483.6 3,566.0 3,572.5 3,592.2 3,601.1 Market capitalization (c) EUR (billion) 47.7 40.4 49.6 47.5 44.1 31.1 50.3 50.0 USD 56.1 41.9 54.8 50.7 49.9 38.2 56.5 57.3 One ADR represents 2 Eni's shares. Excluding treasury shares. Number of outstanding shares by reference price at period end. DATA ON ENI SHARE PLACEMENT 2001 1998 1997 1996 1995 Offer price (€/share) 13.60 11.80 9.90 7.40 5.42 Number of share placed (million shares) 200.1 608.1 728.4 647.5 601.9 of which: through bonus share 39.6 24.4 15.0 1.9 Percentage of share capital (a) (%) 5.0 15.2 18.2 16.2 15.0 Proceeds (€ million) 2,721 6,714 6,869 4,596 3,254 (a) Refers to share capital at December 31, 2025. ENI SHARE PRICE IN MILAN (DECEMBER 31, 2017 - APRIL 30, 2026) € 35 30 25 20 15 10 5 2018 2019 2020 2021 2022 2023 2024 2025 April 30, 2026 Eni Indexed FTSE MIB to Eni share price Indexed Euro Stoxx 50 to Eni share price Source: Eni calculations based on BLOOMBERG data. ENI ADR PRICE IN NEW YORK (DECEMBER 31, 2017 - APRIL 30, 2026) US $ 100 90 80 70 60 50 40 30 20 10 2018 2019 2020 2021 2022 2023 2024 2025 April 30, 2026 Eni Indexed S&P 500 to Eni ADR price Source: Eni calculations based on BLOOMBERG data. SHAREHOLDERS DISTRIBUTION BY GEOGRAPHIC AREA (a) (%) 1.45 17.39 5.47 6.94 13.13 55.62 Italy UK Other EU states USA and Canada Rest of world Other (including treasury shares) SHARE CAPITAL STRUCTURE (a) (%) 0.01 45.39 5.46 17.30 31.84 Ministry of Economy and Finance and Cassa Depositi e Prestiti SpA Retail investors Identity of shareholders not provided Treasury shares Institutional shareholders (a) The update of the data is based on the nominative notices received as at March 18, 2026, relating to the registered recipients of the second tranche of the 2025 dividend. The figures shown in the graphs above do not take into account the free of charge shares granted to Eni's employees (as provided by the "Employee Stock Ownership Plan" approved by the Eni Shareholders' Meeting of May 15, 2024), the termination of the 2025 buyback program on February 18, 2026, and the subsequent cancellation of 118,782,928 treasury shares with no par value without reduction of share capital, resolved by the Extraordinary Shareholders' Meeting of May 14, 2025, which was executed on March 4, 2026. Therefore, as of the date of publication of this document, Eni's share capital is represented by 3,027,982,186 ordinary shares with no par value. The percentage of total shares held by the Ministry of Economy and Finance and CDP SpA is equal to 33.08% of the share capital, and the percentage of treasury shares held by Eni is equal to 2.87% of the share capital. DIVIDEND PER SHARE 0.94 1.00 0.83 0.86 6.3 7.7 0.86 7.1 0.88 7.6 6.5 6.6 5.9 6.2 0.36 5.4 5.6 5.4 4.2 5.1 3.8 4.6 5.0 1.05 Eni's Dividend yield (%) 2018 2019 2020 2021 2022 2023 2024 2025 Dividend yield - average of Oil & Gas petroleum companies (a) (%) Dividend (€/share) (a) Refers to: BP, Chevron, Repsol, ExxonMobil, Shell and TotalEnergies. TOTAL SHAREHOLDER RETURN (ENI VS. PEER GROUP AND BENCHMARK STOCK EXCHANGE INDEXES) 113.8 126.6 246.6 TSR Ftse Mib (%) TSR - average stock market indices (%) TSR Eni (%) 87.2 TSR - average Peer Group (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 ‌FINANCIAL DATA PROFIT AND LOSS ACCOUNT (€ million) 2025 2024 2023 2022 2021 2020 2019 2018 Sales from operations 82,151 88,797 93,717 132,512 76,575 43,987 69,881 75,822 Other income and revenues 1,478 2,417 1,099 1,175 1,196 960 1,160 1,116 Operating expenses (70,296) (74,544) (77,221) (105,497) (58,716) (36,640) (54,302) (59,130) Other operating income (expense) 641 (352) 478 (1,736) 903 (766) 287 129 Depreciation, depletion, amortization (7,349) (7,600) (7,479) (7,205) (7,063) (7,304) (8,106) (6,988) Net impairment reversals (losses) of tangible and intangible and right-of-use assets (1,582) (2,900) (1,802) (1,140) (167) (3,183) (2,188) (866) Write-off of tangible and intangible assets (33) (580) (535) (599) (387) (329) (300) (100) Operating profit (loss) 5,010 5,238 8,257 17,510 12,341 (3,275) 6,432 9,983 Finance income (expense) (819) (599) (473) (925) (788) (1,045) (879) (971) Income (expense) from investments 1,587 1,850 2,444 5,464 (868) (1,658) 193 1,095 Profit (loss) before income taxes 5,778 6,489 10,228 22,049 10,685 (5,978) 5,746 10,107 Income taxes (3,020) (3,725) (5,368) (8,088) (4,845) (2,650) (5,591) (5,970) Tax rate (%) 52.3 57.4 52.5 36.7 45.3 .. 97.3 59.1 Net profit (loss) 2,758 2,764 4,860 13,961 5,840 (8,628) 155 4,137 Attributable to: - Eni's shareholders 2,608 2,624 4,771 13,887 5,821 (8,635) 148 4,126 - Non-controlling interest 150 140 89 74 19 7 7 11 SUMMARIZED GROUP BALANCE SHEET (€ million) Dec. 31, 2025 Dec. 31, 2024 Dec. 31, 2023 Dec. 31, 2022 Dec. 31, 2021 Dec. 31, 2020 Dec. 31, 2019 Dec. 31, 2018 Fixed assets Property, plant and equipment 50,536 59,864 56,299 56,332 56,299 53,943 62,192 60,302 Right of use 5,184 5,822 4,834 4,446 4,821 4,643 5,349 Intangible assets 6,022 6,434 6,379 5,525 4,799 2,936 3,059 3,170 Inventories - Compulsory stock 1,187 1,595 1,576 1,786 1,053 995 1,371 1,217 Equity-accounted investments and other investments 14,484 15,545 13,886 13,294 7,181 7,706 9,964 7,963 Receivables and securities held for operating purposes 974 1,107 2,335 1,978 1,902 1,037 1,234 1,314 Net payables related to capital expenditure (1,337) (1,364) (2,031) (2,320) (1,804) (1,361) (2,235) (2,399) 77,050 89,003 83,278 81,041 74,251 69,899 80,934 71,567 Net working capital Inventories 5,143 6,259 6,186 7,709 6,072 3,893 4,734 4,651 Trade receivables 8,986 12,562 13,184 16,556 15,524 7,087 8,519 9,520 Trade payables (13,901) (15,170) (14,231) (19,527) (16,795) (8,679) (10,480) (11,645) Net tax assets (liabilities) 1,506 144 (2,112) (2,991) (3,678) (2,198) (1,594) (1,364) Provisions (14,580) (15,774) (15,533) (15,267) (13,593) (13,438) (14,106) (11,626) Other current assets and liabilities (1,572) (2,292) (892) 316 (2,258) (1,328) (1,864) (860) (14,418) (14,271) (13,398) (13,204) (14,728) (14,663) (14,791) (11,324) Provisions for employee benefits (596) (596) (748) (786) (819) (1,201) (1,136) (1,117) Assets held for sale including related liabilities 5,837 5,837 747 156 139 44 18 236 CAPITAL EMPLOYED, NET 67,873 79,973 69,879 67,207 58,843 54,079 65,025 59,362 Shareholders' equity attributable to: - Eni's shareholders 47,940 52,785 53,184 54,759 44,437 37,415 47,839 51,016 - Non-controlling interest 4,847 2,863 460 471 82 78 61 57 Shareholders' equity 52,787 55,648 53,644 55,230 44,519 37,493 47,900 51,073 Net borrowings before lease liabilities ex IFRS 16 9,386 12,175 10,899 7,026 8,987 11,568 11,477 8,289 Lease liabilities 5,700 6,453 5,336 4,951 5,337 5,018 5,648 Net borrowings after lease liabilities ex IFRS 16 15,086 18,628 16,235 11,977 14,324 16,586 17,125 8,289 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 67,873 74,276 69,879 67,207 58,843 54,079 65,025 59,362 Gearing before lease liabilities ex IFRS 16 0.15 0.18 0.17 0.11 0.17 0.24 0.19 0.14 Gearing post lease liabilities ex IFRS 16 0.22 0.25 0.23 0.18 0.24 0.31 0.26 0.14 SUMMARIZED GROUP CASH FLOW STATEMENT (€ million) 2025 2024 2023 2022 2021 2020 2019 2018 Net profit (loss) 2,758 2,764 4,860 13,961 5,840 (8,628) 155 4,137 Adjustments to reconcile net proflt (loss) to net cash provided by operating activities: - depreciation, depletion and amortization and other nnon-monetary items 7,209 9,951 7,781 4,369 8,568 12,641 10,480 7,657 - net gains on disposal of assets (99) (601) (441) (524) (102) (9) (170) (474) - dividends, interest, taxes and other changes 3,590 4,246 5,596 8,611 5,334 3,251 6,224 6,168 Changes in working capital related to operations 2,735 1,286 1,811 (1,279) (3,146) (18) 366 1,632 Dividends received by equity investments 1,785 1,946 2,255 1,545 857 509 1,346 275 Taxes paid (3,737) (5,826) (6,283) (8,488) (3,726) (2,049) (5,068) (5,226) Interests (paid) received (911) (674) (460) (735) (764) (875) (941) (522) Net cash provided by operating activities - continuing operations 13,330 13,092 15,119 17,460 12,861 4,822 12,392 13,647 Capital expenditure (8,647) (8,485) (9,215) (8,056) (5,234) (4,644) (8,376) (9,119) Investments and purchase of consolidated subsidiaries and businesses (878) (2,593) (2,592) (3,311) (2,738) (392) (3,008) (244) Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments 1,383 2,788 596 1,202 404 28 504 1,242 Other cash flow related to investing activities 183 (996) (348) 2,361 289 (735) (254) 942 Free cash flow 5,371 3,806 3,560 9,656 5,582 (921) 1,258 6,468 Net cash inflow (outflow) related to financial activities (1,339) (531) 2,194 786 (4,743) 1,156 (279) (357) Changes in short and long-term financial debt (2,555) (1,293) 315 (2,569) (244) 3,115 (1,540) 320 Repayment of lease liabilities (1,250) (1,205) (963) (994) (939) (869) (877) Dividends paid and changes in non-controlling interests and reserves 537 (4,522) (4,882) (4,841) (2,780) (1,968) (3,424) (2,957) Net issue (repayment) of perpetual hybrid bond (328) 1,640 (138) (138) 1,924 2,975 Effect of changes in consolidation and exchange differences of cash and cash equivalent (198) 83 (62) 16 52 (69) 1 18 NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENT 238 (2,022) 24 1,916 (1,148) 3,419 (4,861) 3,492 Adjusted net cash before changes in working capital at replacement cost 12,496 13,590 16,498 20,380 12,711 6,726 11,700 12,529 CHANGE IN NET BORROWINGS (€ million) 2025 2024 2023 2022 2021 2020 2019 2018 Free cash flow 5,371 3,806 3,560 9,656 5,582 (921) 1,258 6,468 Repayment of lease liabilities (1,250) (1,205) (963) (994) (939) (869) (877) Net borrowings of acquired companies (762) (631) (234) (512) (777) (67) (18) Net borrowings of divested companies 362 (155) 142 13 (499) Exchange differences on net borrowings and other changes (1,141) (364) (1,061) (1,352) (429) 759 (158) (367) Dividends paid and changes in non-controlling interest and reserves 537 (4,522) (4,882) (4,841) (2,780) (1,968) (3,424) (2,957) Net issue (repayment) of perpetual hybrid bond (328) 1,640 (138) (138) 1,924 2,975 CHANGE IN NET BORROWINGS BEFORE LEASE LIABILITIES 2,789 (1,276) (3,873) 1,961 2,581 (91) (3,188) 2,627 IFRS 16 first application effect (5,759) Repayment of lease liabilities 1,250 1205 963 994 939 869 877 Inception of new leases and other changes (497) (2,322) (1,348) (608) (1,258) (239) (766) Change in lease liabilities 753 (1,117) (385) 386 (319) 630 (5,648) CHANGE IN NET BORROWINGS AFTER LEASE LIABILITIES 3,542 (2,393) (4,258) 2,347 2,262 539 (8,836) 2,627 SALES BY GEOGRAPHIC AREA OF DESTINATION (€ million) 2025 2024 2023 2022 2021 2020 2019 2018 Italy 28,647 30,994 33,450 60,090 29,968 14,717 23,312 25,279 Other EU Countries 15,979 15,975 18,271 25,413 14,671 9,508 18,567 20,408 Rest of Europe 14,866 16,493 18,476 21,748 12,470 8,191 6,931 7,052 Americas 6,215 7,908 7,004 6,929 4,420 2,426 3,842 5,051 Asia 9,675 9,114 7,404 9,062 7,891 4,182 8,102 9,585 Africa 6,731 8,285 9,057 9,191 7,040 4,842 8,998 8,246 Other areas 38 28 55 79 115 121 129 201 Total outside Italy 53,504 57,803 60,267 72,422 46,607 29,270 46,569 50,543 82,151 88,797 93,717 132,512 76,575 43,987 69,881 75,822 SALES BY GEOGRAPHIC AREA OF ORIGIN (€ million) 2025 2024 2023 2022 2021 2020 2019 2018 Italy 59,076 59,028 62,145 90,479 52,815 29,116 46,763 51,733 Other EU Countries 10,271 10,810 11,405 16,171 9,022 5,508 7,029 8,004 Rest of Europe 437 2,835 3,102 7,157 1,946 1,226 1,909 2,496 Americas 3,930 5,662 5,546 5,329 3,577 1,838 3,290 3,627 Asia 1,513 1,961 1,671 1,931 1,170 846 1,068 1,165 Africa 6,884 8,468 9,776 11,224 7,777 5,271 9,587 8,599 Other areas 40 33 72 221 268 182 235 198 Total outside Italy 23,075 29,769 31,572 42,033 23,760 14,871 23,118 24,089 82,151 88,797 93,717 132,512 76,575 43,987 69,881 75,822 PURCHASES, SERVICES AND OTHER (€ million) 2025 2024 2023 2022 2021 2020 2019 2018 Production costs - raw, ancillary and consumable materials and goods 51,014 54,204 58,170 85,139 41,174 21,432 36,272 41,125 Production costs - services 12,433 12,217 11,512 10,303 10,646 9,710 11,589 10,625 Operating leases and other 1,356 1,512 1,432 2,301 1,233 876 1,478 1,820 Net provisions 1,117 1,397 1,369 2,985 707 349 858 1,120 Other expenses 1,694 2,073 1,746 2,069 1,983 1,317 879 1,130 less: capitalized direct costs associated with self-constructed tangible and intangible assets (558) (289) (393) (268) (194) (133) (202) (198) 67,056 71,114 73,836 102,529 55,549 33,551 50,874 55,622 PRINCIPAL ACCOUNTANT FEES AND SERVICES (€ thousand) 2025 2024 2023 2022 2021 2020 2019 2018 Audit fees 29,107 28,235 25,982 23,637 18,858 19,605 15,748 25,445 Audit-related fees 4,627 3,602 3,580 3,563 4,511 1,412 1,045 1,628 33,734 31,837 29,562 27,200 23,369 21,017 16,793 27,073 PAYROLL AND RELATED COSTS (€ million) 2025 2024 2023 2022 2021 2020 2019 2018 Wages and salaries 2,620 2,665 2,427 2,311 2,182 2,193 2,417 2,409 Social security contributions 541 527 497 465 455 458 449 448 Cost related to defined benefit plans and defined contribution plans 64 96 156 174 165 102 85 220 Other costs 135 123 196 194 204 239 213 170 less: capitalized direct costs associated with self-constructed tangible and intangible assets (131) (149) (140) (129) (118) (129) (168) (154) 3,229 3,262 3,136 3,015 2,888 2,863 2,996 3,093 FINANCE INCOME (EXPENSE) (€ million) 2025 2024 2023 2022 2021 2020 2019 2018 Finance income (expense) related to net borrowings (743) (656) (487) (939) (849) (913) (962) (627) - Interest expense on corporate bonds (774) (827) (667) (507) (475) (517) (618) (565) - Net income from financial activities held for trading 243 367 250 (53) 11 31 127 32 (8) 21 34 (2) - Interest expense for banks and other financing istitutions (252) (358) (207) (128) (94) (102) (122) (120) - Interest expense for lease liabilities (348) (314) (267) (315) (304) (347) (378) - Interest from banks 191 294 356 57 4 10 21 18 - Interest and other income from receivables and securities for non-financing operating activities 205 161 14 9 9 12 8 8 Income (expense) from derivative financial instruments (80) 278 (61) 13 (306) 351 (14) (307) - Derivatives on exchange rate (86) 310 (63) (70) (322) 391 9 (329) - Derivatives on interest rate 6 (32) 2 81 16 (40) (23) 22 - Options 2 Exchange differences, net 133 (38) 255 238 476 (460) 250 341 Other finance income (expense) (251) (405) (274) (275) (177) (96) (246) (430) - Interest and other income from receivables and securities for financing operating activities 39 44 153 128 67 97 112 132 - Finance expense due to the passage of time (accretion discount) (250) (261) (341) (199) (144) (190) (255) (249) - Other finance income (expense) (40) (188) (86) (204) (100) (3) (103) (313) (941) (821) (567) (963) (856) (1,118) (972) (1,023) Finance expense capitalized 122 222 94 38 68 73 93 52 (819) (599) (473) (925) (788) (1,045) (879) (971) INCOME (EXPENSE ON) FROM INVESTMENTS (€ million) 2025 2024 2023 2022 2021 2020 2019 2018 Share of profit of equity-accounted investments 1,414 1,202 1,622 2,163 202 38 161 409 Share of loss of equity-accounted investments (252) (316) (281) (285) (1,294) (1,733) (184) (430) Gains on disposals 77 562 430 483 1 19 22 Dividends 242 227 255 351 230 150 247 231 Decreases (increases) in the provision for losses on investments from equity accounted investments (1) (20) (5) (37) 1 (38) (65) (47) Other income (expense), net 107 195 423 2,789 (8) (75) 15 910 1,587 1,850 2,444 5,464 (868) (1,658) 193 1,095 CAPITAL EXPENDITURE BY GEOGRAPHIC AREA OF ORIGIN (€ million) 2025 2024 2023 2022 2021 2020 2019 2018 Italy 1,829 2,009 2,006 1,475 1,333 1,198 1,402 1,424 Other European Union Countries 673 673 485 415 199 152 306 267 Rest of Europe 231 308 235 205 202 119 9 538 Africa 3,170 3,276 4,105 3,163 1,604 1,443 3,902 4,533 Americas 260 556 609 1,266 659 441 1,017 534 Asia 2,367 1,519 1,471 1,390 1,203 1,267 1,685 1,782 Other areas 117 144 304 142 34 24 55 41 Total outside Italy 6,818 6,476 7,209 6,581 3,901 3,446 6,974 7,695 Capital expenditure 8,647 8,485 9,215 8,056 5,234 4,644 8,376 9,119 ALTERNATIVE PERFORMANCE INDICATORS (NON-GAAP MEASURES) Management evaluates underlying business performance on the basis of Non-GAAP financial measures, which are not provided by IFRS ("Alternative performance measures"), such as adjusted operating profit, adjusted net profit, which are arrived at by excluding from reported results certain gains and losses, defined special items, which include, among others, asset impairments, including impairments of deferred tax assets, gains on disposals, risk provisions, restructuring charges, the accounting effect of fair-valued derivatives used to hedge exposure to the commodity, exchange rate and interest rate risks, which lack the formal criteria to be accounted as hedges, and analogously evaluation effects of assets and liabilities utilized in a relation of natural hedge of the above mentioned market risks. Furthermore, in determining the business segments' adjusted results, finance charges on finance debt and interest income are excluded (see below). In determining adjusted results, inventory holding gains or losses are excluded from base business performance, which is the difference between the cost of sales of the volumes sold in the period based on the cost of supplies of the same period and the cost of sales of the volumes sold calculated using the weighted average cost method of inventory accounting as required by IFRS, except in those business segments where inventories are utilized as a lever to optimize margins. Finally, the same special charges/gains are excluded from the Eni's share of results at JVs and other equity accounted entities, including any profit/loss on inventory holding. Management is disclosing Non-GAAP measures of performance to facilitate a comparison of base business performance across periods, and to allow financial analysts to evaluate Eni's trading performance on the basis of their forecasting models. Non-GAAP financial measures should be read together with information determined by applying IFRS and do not stand in for them. Other companies may adopt different methodologies to determine Non-GAAP measures. Follows the description of the main alternative performance measures adopted by Eni. The measures reported below refer to the performance of the reporting periods disclosed in this report: Adjusted operating and net profit Adjusted operating and net profit are determined by excluding inventory holding gains or losses, special items and, in determining the business segments' adjusted results, finance charges on finance debt and interest income. The adjusted operating profit of each business segment reports gains and losses on derivative financial instruments entered into to manage exposure to movements in foreign currency exchange rates, which impact industrial margins and translation of commercial payables and receivables. Accordingly, also currency translation effects recorded through profit and loss are reported within business segments' adjusted operating profit. The taxation effect of the items excluded from adjusted operating or net profit is determined based on the specific rate of taxes applicable to each of them. Finance charges or income related to net borrowings excluded from the adjusted net profit of business segments are comprised of interest charges on finance debt and interest income earned on cash and cash equivalents not related to operations. Therefore, the adjusted net profit of business segments includes finance charges or income deriving from certain segment operated assets, i.e., interest income on certain receivable financing and securities related to operations and finance charge pertaining to the accretion of certain provisions recorded on a discounted basis (as in the case of the asset retirement obligations in the Exploration & Production segment). Inventory holding gain or loss This is the difference between the cost of sales of the volumes sold in the period based on the cost of supplies of the same period and the cost of sales of the volumes sold calculated using the weighted average cost method of inventory accounting as required by IFRS. Special items These include certain significant income or charges pertaining to either: (i) infrequent or unusual events and transactions, being identified as non-recurring items under such circumstances; (ii) certain events or transactions which are not considered to be representative of the ordinary course of business, as in the case of environmental provisions, restructuring charges, asset impairments or write ups and gains or losses on divestments even though they occurred in past periods or are likely to occur in future ones. Exchange rate differences and derivatives relating to industrial activities and commercial payables and receivables, particularly exchange rate derivatives to manage commodity pricing formulas which are quoted in a currency other than the functional currency are reclassified in operating profit with a corresponding adjustment to net finance charges, notwithstanding the handling of foreign currency exchange risks is made centrally by netting off naturally-occurring opposite positions and then dealing with any residual risk exposure in the derivative market. Finally, special items include the accounting effects of fair-valued commodity derivatives relating to commercial exposures, in addition to those which lack the criteria to be designed as hedges, also those which are not eligible for the own use exemption, including the ineffective portion of cash flow hedges, as well as the accounting effects of commodity and exchange rates derivatives whenever it is deemed that the underlying transaction is expected to occur in future reporting periods. Correspondently, special charges/gains also include the evaluation effects relating to assets/liabilities utilized in a natural hedge relation to offset a market risk, as in the case of accrued currency differences at finance debt denominated in a currency other than the reporting currency, where the cash outflows for the reimbursement are matched by highly probable cash inflows in the same currency. The deferral of both the unrealized portion of fair-valued commodity and other derivatives and evaluation effects are reversed to future reporting periods when the underlying transaction occurs. As provided for in Decision No. 15519 of July 27, 2006 of the Italian market regulator (CONSOB), non-recurring material income or charges are to be clearly reported in the management's discussion and financial tables. Proforma adjusted EBIT Is the measure adding the operating margin of the equity accounted entities to the adjusted EBIT, introduced by the management to reflect the increasing contribution from the JV/associates also in connection with the Eni satellite model. Proforma adjusted EBITDA Earnings Before Interest, Taxes, Depreciation and Amortization, is calculated summing up the adjusted operating profit and DD&A, adding the contribution of the equity-accounted entities. Represents the company's profitability as a result of operations management. Gearing Gearing is calculated as the ratio between net borrowings and capital employed net and measures how much of capital employed net is financed recurring to third-party funding. Gearing ex-IFRS 16 is calculated by excluding lease liabilities and right-of-use assets from numerator and denominator, respectively. Cash flow from operations before changes in working capital at replacement cost This is defined as net cash provided from operating activities before changes in working capital at replacement cost. It also excludes certain non-recurring charges such as extraordinary credit allowances and, considering the high market volatility, changes in the fair value of commodity derivatives lacking the formal criteria to be designed as hedges, including derivatives which were not eligible for the own use exemption, the ineffective portion of cash flow hedges, as well as the effects of certain settled commodity derivatives whenever it is deemed that the underlying transaction is expected to occur in future reporting periods. Free cash flow Free cash flow represents the link existing between changes in cash and cash equivalents (deriving from the statutory cash flows statement) and in net borrowings (deriving from the summarized cash flow statement) that occurred from the beginning of the period to the end of period. Free cash flow is the cash in excess of capital expenditure needs. Starting from free cash flow it is possible to determine either: (i) changes in cash and cash equivalents for the period by adding/deducting cash flows relating to financing debts/ receivables (issuance/repayment of debt and receivables related to financing activities), shareholders' equity (dividends paid, net repurchase of own shares, capital issuance) and the effect of changes in consolidation and of exchange rate differences; (ii) changes in net borrowings for the period by adding/deducting cash flows relating to shareholders' equity and the effect of changes in consolidation and of exchange rate differences. Net borrowings Net borrowings is calculated as total finance debt less cash, cash equivalents and certain very liquid investments not related to operations, including among others non-operating financing receivables and securities not related to operations. Financial activities are qualified as "not related to operations" when these are not strictly related to the business operations. Adjusted ROACE Is the return on average capital invested, calculated as the ratio between net income before minority interests, plus net financial charges on net financial debt, less the related tax effect and net average capital employed. Profit per boe Measures the return per oil and natural gas barrel produced. It is calculated as the ratio between Results of operations from E&P activities (as defined by FASB Extractive Activities - Oil and Gas Topic 932) and production sold. Opex per boe Measures efficiency in the Oil & Gas development activities, calculated as the ratio between operating costs (as defined by FASB Extractive Activities - Oil and Gas Topic 932) and production sold. Finding & Development cost per boe Represents Finding & Development cost per boe of new proved or possible reserves. It is calculated as the overall amount of exploration and development expenditure, the consideration for the acquisition of possible and probable reserves as well as additions of proved reserves deriving from improved recovery, extensions, discoveries and revisions of previous estimates (as defined by FASB Extractive Activities - Oil and Gas Topic 932). The following tables report the group operating profit and Group adjusted net profit and their breakdown by segment, as well as is represented the reconciliation with net profit attributable to Eni's shareholders of continuing operations. Coverage Financial discipline ratio, calculated as the ratio between operating profit and net finance charges. Current ratio Measures the capability of the company to repay short-term debt, calculated as the ratio between current assets and current liabilities. Debt coverage Rating companies use the debt coverage ratio to evaluate debt sustainability. It is calculated as the ratio between net cash provided by operating activities and net borrowings, less cash and cash-equivalents, securities held for non-operating purposes and financing receivables for non-operating purposes. Debt/EBITDA Net Debt/adjusted EBITDA is the ratio between the profit available to cover the debt before interest, taxes, amortizations and impairment. This index is a measure of the company's ability pay off its debt and gives an indication as to how long a company would need to operate at its current level to pay off all its debt. BREAKDOWN OF SPECIAL ITEMS (€ million) 2025 2024 2023 2022 2021 2020 2019 2018 Special items of operating profit (loss) 2,589 4,676 4,986 3,440 (1,186) 3,855 2,388 1,161 - impairment losses (impairments reversals), net 1,582 2,900 1,802 1,140 167 3,183 2,188 866 - impairment of exploration projects 140 2 247 - environmental charges 560 31 648 2,056 271 (25) 338 325 - gains on disposal of assets (21) (38) (11) (41) (100) (9) (151) (452) - risk provisions 325 44 39 87 142 149 3 380 - provision for redundancy incentives 72 73 158 202 193 123 45 155 - commodity derivatives (26) 1,056 1,255 (389) (2,139) 440 (439) (133) - exchange rate differences and derivatives (334) 258 (16) 149 183 (160) 108 107 - reinstatement of Eni Norge amortization charges (375) - other 431 212 1,111 234 (150) 154 296 288 Net finance (income) expense 279 (155) 30 (127) (115) 152 (42) (85) of which: - exchange rate differences and derivatives reclassified to operating profit (loss) 334 (258) 16 (149) (183) 160 (108) (107) Net income (expense) from investments (158) (319) (698) (2,834) 851 1,655 188 (798) of which: - gains on disposals of assets (78) (539) (834) (2,990) (46) (909) - impairments/revaluation of equity investmentss (113) 851 1,207 148 67 Income taxes (790) (1,941) (1,180) (683) 19 1,278 351 110 Total special items of net profit (loss) 1,920 2,261 3,138 (204) (431) 6,940 2,885 388 attributable to: - Eni's shareholders 1,873 2,325 3,149 (185) (431) 6,940 2,885 388 - Non-controlling interest 47 (64) (11) (19) RECONCILIATION TABLE OF NON-GAAP RESULTS VS. TO GAAP RESULTS FOR THE YEARS 2018-2025 (€ million) 2025 2024 2023 2022 2021 2020 2019 2018 Reported operating profit (loss) 5,010 5,238 8,257 17,510 12,341 (3,275) 6,432 9,983 Exclusion of inventory holding (gains) losses 745 434 562 (564) (1,491) 1,318 (223) 96 Exclusion of special items: environmental charges 560 31 648 2,056 271 (25) 338 325 impairment losses (impairments reversals), net 1,582 2,900 1,802 1,140 167 3,183 2,188 866 impairment of exploration projects 140 2 247 gains on disposal of assets (21) (38) (11) (41) (100) (9) (151) (452) risk provisions 325 44 39 87 142 149 3 380 provision for redundancy incentives 72 73 158 202 193 123 45 155 commodity derivatives (26) 1,056 1,255 (389) (2,139) 440 (439) (133) exchange rate differences and derivatives (334) 258 (16) 149 183 (160) 108 107 other 431 212 1,111 234 (150) 154 296 (87) Special items of operating profit (loss) 2,589 4,676 4,986 3,440 (1,186) 3,855 2,388 1,161 Adjusted operating profit (loss) 8,344 10,348 13,805 20,386 9,664 1,898 8,597 11,240 Net finance (expense) income (a) (540) (754) (443) (1,052) (903) (893) (921) (1,056) Net income (expense) from investments (a) 1,429 1,531 1,746 2,630 (17) (3) 381 297 Income taxes (a) (4,023) (5,792) (6,708) (8,608) (4,398) (1,753) (5,174) (5,887) Tax rate (%) 43,6 52,1 44,4 39,2 50,3 175,0 64,2 56,2 Adjusted net profit (loss) 5,210 5,333 8,400 13,356 4,349 (751) 2,883 4,594 of which attributable to: - Eni's shareholders 4,989 5,257 8,322 13,301 4,330 (758) 2,876 4,583 - non-controlling interest 221 76 78 55 19 7 7 11 Reported net profit (loss) attributable to Eni's shareholders 2,608 2,624 4,771 13,887 5,821 (8,635) 148 4,126 Exclusion of inventory holding (gains) losses 508 308 402 (401) (1,060) 937 (157) 69 Exclusion of special items 1,873 2,325 3,149 (185) (431) 6,940 2,885 388 Adjusted net profit (loss) attributable to Eni's shareholders 4,989 5,257 8,322 13,301 4,330 (758) 2,876 4,583 (a) Excluding special items. NET BORROWINGS (€ million) Debt and bonds Cash and cash equivalents Financial assets measured at fair value thorugh profit or loss Financing receivables held for non-operating purposes Lease Liabilities Total 2025 Short-term debt 8,363 (8,242) (6,991) (3,845) 1,263 (9,452) Long-term debt 20,101 4,437 24,538 28,464 (8,242) (6,991) (3,845) 5,700 15,086 2024 Short-term debt 8,820 (8,183) (6,797) (3,193) 1,279 (8,074) Long-term debt 21,528 5,174 26,702 30,348 (8,183) (6,797) (3,193) 6,453 18,628 2023 Short-term debt 7,013 (10,193) (6,782) (855) 1,128 (9,689) Long-term debt 21,716 4,208 25,924 28,729 (10,193) (6,782) (855) 5,336 16,235 2022 Short-term debt 7,543 (10,155) (8,251) (1,485) 884 (11,464) Long-term debt 19,374 4,067 23,441 26,917 (10,155) (8,251) (1,485) 4,951 11,977 2021 Short-term debt 4,080 (8,254) (6,301) (4,252) 948 (13,779) Long-term debt 23,714 4,389 28,103 27,794 (8,254) (6,301) (4,252) 5,337 14,324 2020 Short-term debt 4,791 (9,413) (5,502) (203) 849 (9,478) Long-term debt 21,895 4,169 26,064 26,686 (9,413) (5,502) (203) 5,018 16,586 2019 Short-term debt 5,608 (5,994) (6,760) (287) 889 (6,544) Long-term debt 18,910 4,759 23,669 24,518 (5,994) (6,760) (287) 5,648 17,125 2018 Short-term debt 5,783 (10,836) (6,552) (188) (11,793) Long-term debt 20,082 20,082 25,865 (10,836) (6,552) (188) 8,289 ‌QUARTERLY INFORMATION MAIN FINANCIAL DATA (a) 2025 (€ million) I quarter II quarter III quarter IV quarter Full Year Net sales from operations 22,565 18,767 20,204 20,615 82,151 Operating profit (loss) 2,328 1,162 1,344 176 5,010 Adjusted operating profit (loss) 2,600 1,889 2,073 1,782 8,344 Net (loss) profit (b) 1,172 543 803 90 2,608 Capital expenditure 1,819 1,954 2,017 2,857 8,647 Investments 251 100 229 298 878 Net borrowings before lease liabilities ex IFRS 16 10,334 10,198 9,931 9,386 9,386 Net borrowings after lease liabilities ex IFRS 16 16,535 15,906 15,449 15,086 15,086 2024 (€ million) I quarter II quarter III quarter IV quarter Full Year Net sales from operations 22,936 21,715 20,658 23,488 88,797 Operating profit (loss) 2,670 1,581 1,360 (373) 5,238 Adjusted operating profit (loss) 3,027 3,185 2,442 1,694 10,348 Net (loss) profit (b) 1,211 661 522 230 2,624 Capital expenditure 1,931 2,021 2,001 2,532 8,485 Investments 1,761 547 76 209 2,593 Net borrowings before lease liabilities ex IFRS 16 12,882 12,113 11,627 12,175 12,175 Net borrowings after lease liabilities ex IFRS 16 18,296 17,454 16,753 18,628 18,628 2023 (€ million) I quarter II quarter III quarter IV quarter Full Year Net sales from operations 27,185 19,591 22,319 24,622 93,717 Operating profit (loss) 2,513 1,762 3,126 856 8,257 Adjusted operating profit (loss) 4,641 3,381 3,014 2,769 13,805 Net (loss) profit (b) 2,388 294 1,916 173 4,771 Capital expenditure 2,119 2,557 1,873 2,666 9,215 Investments 645 1,165 60 722 2,592 Net borrowings before lease liabilities ex IFRS 16 7,796 8,215 8,679 10,899 10,899 Net borrowings after lease liabilities ex IFRS 16 12,634 12,941 13,578 16,235 16,235 2022 (€ million) I quarter II quarter III quarter IV quarter Full Year Net sales from operations 32,129 31,556 37,302 31,525 132,512 Operating profit (loss) 5,352 5,970 6,611 (423) 17,510 Adjusted operating profit (loss) 5,191 5,841 5,772 3,582 20,386 Net (loss) profit (b) 3,583 3,815 5,862 627 13,887 Capital expenditure 1,364 1,829 2,099 2,764 8,056 Investments 1,194 73 978 1,066 3,311 Net borrowings before lease liabilities ex IFRS 16 8,623 7,872 6,444 7,026 7,026 Net borrowings after lease liabilities ex IFRS 16 13,993 12,777 11,533 11,977 11,977 (a) Quarterly data are unaudited. (b) Net profit attributable to Eni's shareholders. MAIN FINANCIAL DATA (a) 2021 (€ million) I quarter II quarter III quarter IV quarter Full Year Net sales from operations 14,494 16,294 19,021 26,766 76,575 Operating profit (loss) 1,862 1,995 2,793 5,691 12,341 Adjusted operating profit (loss) 1,321 2,045 2,492 3,806 9,664 Net (loss) profit (b) 856 247 1,203 3,515 5,821 Capital expenditure 1,139 1,248 1,200 1,647 5,234 Investments 520 351 553 1,314 2,738 Net borrowings before lease liabilities ex IFRS 16 12,239 10,040 11,309 8,987 8,987 Net borrowingsafter lease liabilities ex IFRS 16 17,507 15,323 16,622 14,324 14,324 2020 (€ million) I quarter II quarter III quarter IV quarter Full Year Net sales from operations 13,873 8,157 10,326 11,631 43,987 Operating profit (loss) (1,095) (2,680) 220 280 (3,275) Adjusted operating profit (loss) 1,307 (434) 537 488 1,898 Net (loss) profit (b) (2,929) (4,406) (503) (797) (8,635) Capital expenditure 1,590 978 889 1,187 4,644 Investments 222 42 95 33 392 Net borrowings before lease liabilities ex IFRS 16 12,920 14,329 14,525 11,568 11,568 Net borrowings after lease liabilities ex IFRS 16 18,681 19,971 19,853 16,586 16,586 2019 (€ million) I quarter II quarter III quarter IV quarter Full Year Net sales from operations 18,540 18,440 16,686 16,215 69,881 Operating profit (loss) 2,518 2,231 1,861 (178) 6,432 Adjusted operating profit (loss) 2,354 2,279 2,159 1,805 8,597 Net (loss) profit (b) 1,092 424 523 (1,891) 148 Capital expenditure 2,239 1,997 1,899 2,241 8,376 Investments 30 21 2,931 26 3,008 Net borrowings before lease liabilities ex IFRS 16 8,665 7,856 12,714 11,477 11,477 Net borrowings after lease liabilities ex IFRS 16 14,496 13,591 18,517 17,125 17,125 2018 (€ million) I quarter II quarter III quarter IV quarter Full Year Net sales from operations 17,932 18,139 19,695 20,056 75,822 Operating profit (loss) 2,399 2,639 3,449 1,496 9,983 Adjusted operating profit (loss) 2,380 2,564 3,304 2,992 11,240 Net (loss) profit (b) 946 1,252 1,529 399 4,126 Capital expenditure 2,541 1,961 1,830 2,787 9,119 Investments 37 94 26 87 244 Net borrowings at period end 11,278 9,897 9,005 8,289 8,289 Quarterly data are unaudited. Net profit attributable to Eni's shareholders. KEY MARKET INDICATORS 2025 I quarter II quarter III quarter IV quarter Full Year Average price of Brent dated crude oil (a) ($/barrel) 75.66 67.82 69.07 63.69 69.06 Average EUR/USD exchange rate (b) 1.052 1.134 1.168 1.163 1.130 Average price in euro of Brent dated crude oil (€/barrel) 71.92 59.81 59.14 54.75 61.12 Standard Eni Refining Margin (SERM) (c) ($/barrel) 3.8 4.8 8.9 11.7 7.3 PSV (d) (€/MWh) 48 38 36 32 39 TTF (d) 47 35 32 30 36 2024 I quarter II quarter III quarter IV quarter Full Year Average price of Brent dated crude oil (a) ($/barrel) 83.24 84.94 80.18 74.69 80.76 Average EUR/USD exchange rate (b) 1.086 1.077 1.098 1.067 1.082 Average price in euro of Brent dated crude oil (€/barrel) 76.65 78.88 73.00 70.00 74.64 Standard Eni Refining Margin (SERM) (c) ($/barrel) 8.7 6.4 1.7 3.7 5.1 PSV (d) (€/MWh) 29 33 38 45 36 TTF (d) 27 32 35 43 34 2023 I quarter II quarter III quarter IV quarter Full Year Average price of Brent dated crude oil (a) ($/barrel) 81.27 78.39 86.76 84.05 82.62 Average EUR/USD exchange rate (b) 1.073 1.089 1.088 1.075 1.081 Average price in euro of Brent dated crude oil (€/barrel) 75.74 71.99 79.71 78.17 76.40 Standard Eni Refining Margin (SERM) (c) ($/barrel) 11.0 5.6 11.7 4.3 8.1 PSV (d) (€/MWh) 57 37 34 41 42 TTF (d) 54 35 33 41 41 2022 I quarter II quarter III quarter IV quarter Full Year Average price of Brent dated crude oil (a) ($/barrel) 101.40 113.79 100.85 88.71 101.19 Average EUR/USD exchange rate (b) 1.122 1.065 1.007 1.021 1.053 Average price in euro of Brent dated crude oil (€/barrel) 90.40 106.84 100.15 86.93 96.09 Standard Eni Refining Margin (SERM) (c) ($/barrel) (0.9) 17.2 4.1 13.6 8.1 PSV (d) (€/MWh) 99 97 197 95 122 TTF (d) 96 96 196 94 121 In USD per barrel. Source: S&P Global Energy. Source: ECB. In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations. In €/MWh. Source: ICIS European Spot Gas Markets. KEY MARKET INDICATORS 2021 I quarter II quarter III quarter IV quarter Full Year Average price of Brent dated crude oil (a) ($/barrel) 60.90 68.83 73.47 79.73 70.73 Average EUR/USD exchange rate (b) 1.205 1.206 1.179 1.144 1.183 Average price in euro of Brent dated crude oil (€/barrel) 50.54 57.07 62.33 69.73 59.80 Standard Eni Refining Margin (SERM) (c) ($/barrel) (0.6) (0.4) (0.4) (2.2) (0.9) PSV (d) (€/MWh) 19 25 46 93 46 TTF (d) 19 25 47 92 46 2020 I quarter II quarter III quarter IV quarter Full Year Average price of Brent dated crude oil (a) ($/barrel) 50.26 29.20 43.00 44.23 41.67 Average EUR/USD exchange rate (b) 1.103 1.101 1.169 1.193 1.142 Average price in euro of Brent dated crude oil (€/barrel) 45.56 26.51 36.78 37.08 36.49 Standard Eni Refining Margin (SERM) (c) ($/barrel) 3.6 2.3 0.7 0.2 1.7 PSV (d) (€/MWh) 11 7 9 14 10 TTF (d) 10 5 8 15 9 2019 I quarter II quarter III quarter IV quarter Full Year Average price of Brent dated crude oil (a) ($/barrel) 63.20 68.82 61.94 63.25 64.30 Average EUR/USD exchange rate (b) 1.136 1.124 1.112 1.107 1.119 Average price in euro of Brent dated crude oil (€/barrel) 55.65 61.25 55.70 57.13 57.44 Standard Eni Refining Margin (SERM) (c) ($/barrel) 3.4 3.7 6.0 4.2 4.3 PSV (d) (€/MWh) 21 17 12 15 16 TTF (d) 18 13 10 13 13 2018 I quarter II quarter III quarter IV quarter Full Year Average price of Brent dated crude oil (a) ($/barrel) 66.76 74.35 75.27 67.76 71.04 Average EUR/USD exchange rate (b) 1.229 1.191 1.163 1.141 1.181 Average price in euro of Brent dated crude oil ($/barrel) 54.32 62.40 64.72 59.37 60.15 Standard Eni Refining Margin (SERM) (c) ($/barrel) 3.0 4.1 4.5 3.4 3.7 PSV (d) (€/MWh) 22 23 26 26 25 TTF (d) 21 21 25 25 23 In USD per barrel. Source: S&P Global Energy. Source: ECB. In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations. In €/MWh. Source: ICIS European Spot Gas Markets. MAIN OPERATING DATA 2025 I quarter II quarter III quarter IV quarter Full Year Liquids production (kbbl/d) 786 825 860 890 840 Natural gas production (mmcf/d) 4,502 4,415 4,687 4,966 4,644 Hydrocarbons production (kboe/d) 1,647 1,668 1,756 1,839 1.728 Sales of natural gas to third parties (bcm) 10.69 7.75 7.84 11.87 38.15 Own consumption of natural gas 1.43 1.26 1.34 1.54 5.57 Total sales and own consumption of natural gas (GGP) 12.12 9.01 9.18 13.41 43.72 Gas sales to end customers (Plenitude) 2.39 0.68 0.47 1.75 5.29 Power sales to end customers (Plenitude) (TWh) 4.90 4.09 4.84 4.80 18.63 Thermoelectric production (Enipower) 5.41 4.53 4.83 5.76 20.53 Sales of refined products - retail in Italy (Enilive) (mmtonnes) 1.25 1.40 1.49 1.40 5.54 2024 I quarter II quarter III quarter IV quarter Full Year Liquids production (kbbl/d) 797 777 775 786 784 Natural gas production (mmcf/d) 4,937 4,888 4,638 4,862 4,831 Hydrocarbons production (kboe/d) 1,741 1,712 1,661 1,716 1,707 Sales of natural gas to third parties (bcm) 14.08 8.24 9.38 13.80 45.50 Own consumption of natural gas 1.37 1.14 1.41 1.46 5.38 Total sales and own consumption of natural gas (GGP) 15.45 9.38 10.79 15.26 50.88 Gas sales to end customers (Plenitude) 2.56 0.73 0.49 1.73 5.51 Power sales to end customers (Plenitude) (TWh) 4.64 4.14 4.88 4.62 18.28 Thermoelectric production (Enipower) 5.05 4.18 5.33 5.60 20.16 Sales of refined products - retail in Italy (Enilive) (mmtonnes) 1.26 1.34 1.43 1.37 5.40 2023 I quarter II quarter III quarter IV quarter Full Year Liquids production (kbbl/d) 780 757 758 781 769 Natural gas production (mmcf/d) 4,608 4,491 4,590 4,851 4,635 Hydrocarbons production (kboe/d) 1,656 1,616 1,635 1,708 1,655 Sales of natural gas to third parties (bcm) 13.53 9.85 9.57 12.17 45.12 Own consumption of natural gas 1.31 1.30 1.34 1.44 5.39 Total sales and own consumption of natural gas (GGP) 14.84 11.15 10.91 13.61 50.51 Gas sales to end customers (Plenitude) 2.91 0.87 0.53 1.74 6.06 Power sales to end customers (Plenitude) (TWh) 4.61 4.20 4.57 4.60 17.98 Thermoelectric production (Enipower) 5.27 5.07 5.18 5.14 20.66 Sales of refined products - retail in Italy (Enilive) (mmtonnes) 1.26 1.32 1.42 1.32 5.32 MAIN OPERATING DATA 2022 I quarter II quarter III quarter IV quarter Full Year Liquids production (kbbl/d) 780 740 707 776 751 Natural gas production (mmcf/d) 4,638 4,447 4,583 4,426 4,523 Hydrocarbons production (kboe/d) 1,654 1,586 1,578 1,617 1,610 Sales of natural gas to third parties (bcm) 16.71 12.11 12.02 14.26 55.10 Own consumption of natural gas 1.55 1.27 1.31 1.29 5.42 Total sales and own consumption of natural gas (GGP) 18.26 13.38 13.33 15.55 60.52 Gas sales to end customers (Plenitude) 3.42 0.95 0.61 1.86 6.84 Power sales to end customers (Plenitude) (TWh) 5.10 4.49 4.77 4.43 18.79 Thermoelectric production (Enipower) 6.07 4.99 5.36 4.95 21.37 Sales of refined products - retail in Italy (Enilive) (mmtonnes) 1.20 1.35 1.46 1.38 5.39 2021 I quarter II quarter III quarter IV quarter Full Year Liquids production (kbbl/d) 814 779 805 852 813 Natural gas production (mmcf/d) 4,726 4,339 4,688 4,700 4,613 Hydrocarbons production (kboe/d) 1,704 1,597 1,688 1,737 1,682 Sales of natural gas to third parties (bcm) 15.51 15.48 15.49 17.14 63.62 Own consumption of natural gas 1.52 1.46 1.65 1.74 6.37 Sales to third parties and own consumption 17.03 16.94 17.14 18.88 69.99 Sales of natural gas of Eni's affiliates (net to Eni) 0.45 0.01 0.00 0.00 0.46 Total sales and own consumption of natural gas (GGP) 17.48 16.95 17.14 18.88 70.45 Gas sales to end customers (Plenitude) 3.52 1.08 0.63 2.62 7.85 Power sales to end customers (Plenitude) (TWh) 3.66 3.89 4.22 4.72 16.49 Thermoelectric production (Enipower) 5.12 5.08 5.81 6.35 22.36 Sales of refined products - retail in Italy (Enilive) (mmtonnes) 1.04 1.27 1.45 1.36 5.12 2020 I quarter II quarter III quarter IV quarter Full Year Liquids production (kbbl/d) 892 853 817 809 843 Natural gas production (mmcf/d) 4,768 4,653 4,694 4,800 4,729 Hydrocarbons production (kboe/d) 1,790 1,729 1,701 1,713 1,733 Sales of natural gas to third parties (bcm) 14.37 11.95 13.96 16.17 56.45 Own consumption of natural gas 1.53 1.44 1.58 1.58 6.13 Sales to third parties and own consumption 15.90 13.39 15.54 17.75 62.58 Sales of natural gas of Eni's affiliates (net to Eni) 0.69 0.46 0.44 0.82 2.41 Total sales and own consumption of natural gas (GGP) 16.59 13.85 15.98 18.57 64.99 Gas sales to end customers (Plenitude) 3.63 0.88 0.66 2.51 7.68 Power sales to end customers (Plenitude) (TWh) 3.28 2.74 3.07 3.40 12.49 Thermoelectric production (Enipower) 5.46 4.88 5.43 5.18 20.95 Sales of refined products - retail in Italy (Enilive) (mmtonnes) 1.12 0.89 1.41 1.14 4.56 MAIN OPERATING DATA 2019 I quarter II quarter III quarter IV quarter Full Year Liquids production (kbbl/d) 887 867 893 926 893 Natural gas production (mmcf/d) 5,157 5,230 5,379 5,379 5,287 Hydrocarbons production (kboe/d) 1,832 1,825 1,888 1,921 1,871 Sales of natural gas to third parties (bcm) 18.96 15.75 14.61 14.82 64.14 Own consumption of natural gas 1.62 1.43 1.65 1.55 6.25 Sales to third parties and own consumption 20.58 17.18 16.26 16.37 70.39 Sales of natural gas of Eni's affiliates (net to Eni) 0.75 0.62 0.59 0.72 2.68 Total sales and own consumption of natural gas (GGP) 21.33 17.80 16.85 17.09 73.07 Gas sales to end customers (Plenitude) 3.99 1.41 0.74 2.48 8.62 Power sales to end customers (Plenitude) (TWh) 2.75 2.47 2.75 2.95 10.92 Thermoelectric production (Enipower) 5.56 5.18 5.86 5.06 21.66 Sales of refined products - retail in Italy (Enilive) (mmtonnes) 1.38 1.48 1.53 1.42 5.81 2018 I quarter II quarter III quarter IV quarter Full Year Liquids production (kbbl/d) 885 881 886 897 887 Natural gas production (mmcf/d) 5,358 5,359 5,008 5,321 5,261 Hydrocarbons production (kboe/d) 1,867 1,863 1,803 1,872 1,851 Sales of natural gas to third parties (bcm) 19.98 16.03 15.20 16.38 67.59 Own consumption of natural gas 1.59 1.34 1.58 1.60 6.11 Sales to third parties and own consumption 21.57 17.37 16.78 17.98 73.70 Sales of natural gas of Eni's affiliates (net to Eni) 0.87 0.71 0.69 0.74 3.01 Total sales and own consumption of natural gas (GGP) 22.44 18.08 17.47 18.72 76.71 Gas sales to end customers (Plenitude) - - - - 9.13 Power sales to end customers (Plenitude) (TWh) - - - - 8.39 Thermoelectric production (Enipower) 5.50 4.67 5.88 5.57 21.62 Sales of refined products - retail in Italy (Enilive) (mmtonnes) 1.40 1.48 1.55 1.48 5.91 ‌ENI FACT BOOK 2025 ENI AT A GLANCE OPERATING REVIEW ANNEX 27 Operating review GLOBAL NATURAL RESOURCES Exploration & Production 28 Global Gas & LNG Portfolio and Power 57 TRANSITION BUSINESSES Enilive and Plenitude 65 INDUSTRIAL TRANSFORMATION Refining and Chemicals 77 Environmental activities 88 ‌Exploration & Production SELECTED OPERATING DATA 2025 2024 2023 TRIR (Total Recordable Injury Rate) (a) (total recordable injuries/worked hours) x 1,000,000 0.55 0.46 0.43 of which: employees 0.73 0.18 0.48 contractors 0.50 0.52 0.41 Sales from operations (b) (€ million) 50,367 54,440 55,773 Operating profit (loss) of subsidiaries 6,302 6,715 8,693 Proforma adjusted EBIT 11,163 13,022 13,538 Adjusted net profit (loss) 4,875 4,777 5,648 Capital expenditure 6,253 6,055 7,135 Profit per boe (c) ($/boe) 7.80 3.69 8.58 Opex per boe (e) 9.2 9.2 8.6 Cash Flow per boe 20.5 17.3 19.4 Finding & Development cost per boe (d)(e) 17.0 22.7 26.3 Average hydrocarbons realizations 53.64 57.56 59.35 Hydrocarbons production (e) (kboe/d) 1,728 1,707 1,655 Net proved hydrocarbon reserves (mmboe) 6,885 6,497 6,614 Reserves life index (years) 10.9 10.4 10.6 Organic reserves replacement ratio (%) 167 124 69 Employees at year end (number) 9,141 9,188 9,840 of which: outside Italy 5,101 5,171 5,927 Direct GHG emissions (Scope 1) (a) (Mt CO 2 eq.) 4.6 6.7 7.6 Volumes of hydrocarbon sent to routine flaring (a) (billion Sm³) 0.0 0.1 0.2 Total volume of oil spills (>1 barrel) (a) (barrels) 4 2,163 5,132 Re-injected production water (a) (%) 56 51 42 KPIs refer to 100% of the operated assets, consolidated and unconsolidated, with reference to the operatorship criteria expressed in the standards for Sustainability Statement. Before elimination of intragroup sales. Related to consolidated subsidiaries. Three-year average. Includes Eni's share in joint ventures and equity-accounted entities. In 2025, Exploration & Production delivered excellent results, among the best in the industry, driven by production growth through the addition of more valuable barrels, as well as by selective and strict discipline in capital allocation and operating expenditures. Oil & gas production grew 4% from 2024, leading to an increase of more than 7% over 2022-2025, excluding portfolio effects. The start-up of six major projects in Norway, Indonesia, Angola and Congo enabled production to reach 1.73 million boe/d. We also strengthened the pipeline, taking FIDs on four major projects, three of which are operated, reinforcing our medium-term outlook, thus reaching an organic reserve replacement ratio of more than 160%. Exploration once again confirmed its role as a key value-creation lever, delivering another year of excellent results, with approximately 900 million boe of resources, further reinforcing the Group's global leadership. Proprietary technologies and know-how are critical enablers of growth also in the upstream business. High-performance computing, including HPC6, together with proprietary algorithms and artificial intelligence applications, supports the Group's ability to effectively manage oil and gas demand. The business combination with PETRONAS, focused on the LNG market in Indonesia and Malaysia, is underway, with a production target of over 500 thousand boe/day by 2028. The company is on track to start operations by mid-2026.The large-scale integrated Argentina LNG project, developed in partnership with YPF and XRG, is progressing towards the final investment decision. This project will aim at monetizing the shale gas resources of Vaca Muerta. In line with Eni's strategy focused on the rationalization of the upstream activities by rebalancing its portfolio and divesting non-strategic assets, Eni closed the divestment of an asset in Congo while finalized farm-in agreement with acquisition of additional interest in Norway (via Vår Energi), in the United Kingdom (through Ithaca Energy) as well as in Algeria and Nigeria. In addition, in January 2026 signed a binding agreement with SOCAR, the State Oil Company of the Republic of Azerbaijan, for the sale of an additional 10% stake in the Baleine project in Côte d'Ivoire. ACTIVITY AREAS Italy Eni has been operating in Italy since 1926. In 2025, Eni's oil and gas production amounted to 65 kboe/d. Total developed and undeveloped acreage were 10,538 square kilometers (8,838 square kilometers net to Eni). The cancellation of the PiTESAI in 2024 brought the legislative mining right (Titoli minerari) back to the original text, allowing in 2025 the total or partial reassignment of 10 exploration permits and 3 extension applications. In addition, in compliance with EU Regulation 2024/1787 on the methane gas emissions reduction in the energy sector, activities to quantify methane emissions were completed in 2025 and reported to the Italian Authority MASE (Ministero dell'Ambiente e della Sicurezza Energetica). This included fugitive emissions monitoring by means of Leak Detection and Repair type 2 for each operational site as well as for shut-in and abandoned wells. Eni's production activities in Italy are regulated by concession contracts (23 onshore and 43 offshore) and are deployed in the Adriatic and Ionian Seas, the Central Southern Apennines, mainland and offshore Sicily. In 2025, 30% of Eni's domestic hydrocarbon production came from fields in the Adriatic and Ionian Seas, 45% from the Central Southern Apennines and approximately 25% from Sicily. ADRIATIC AND IONIAN SEAS Production Main fields are Cervia-Arianna, Luna, Barbara, Emilio-Donata, Clara NW and Hera Lacinia. Production is operated by means of approximately 40 fixed platforms in use and is carried by sealine to the mainland where it is input in the national gas network. The platforms and sealine facilities are subject continuously to rigorous safety control to assess their integrity. Development Development activities concerned: (i) the production start-up of new wells in the Cervia Mare (the Cervia field) and Fauzia concessions; (ii) the installation of a new compressor facility in the Falconara gas treatment plant; (iii) optimization activities at the Antonella platform; (iv) a plug-and-abandon campaign for no longer productive wells, including those for the Ravenna CCS project, is ongoing; and (v) local development initiatives, including the third edition of ORA! Outpost Ravenna for Energy Transition, with open innovation projects and programs in the health and social sectors in partnership with stakeholders and local authorities. In Marina di Ravenna, the collaboration with the Local Health Authority of Romagna area progressed to enhance primary healthcare services. In addition, district upgrading, economic enhancement, educational support and environmental protection interventions were carried out in the Municipality of Crotone through Eni's voluntary contributions. CENTRAL SOUTHERN APENNINES Production Eni is the operator of the Val d'Agri concession in the Basilicata Region. Production from the Monte Alpi, Monte Enoc and Cerro Falcone fields is treated by the Viggiano Oil Center and is subsequently sent by pipeline to the Taranto Refinery for final processing. Development The activities of the year in the Val d'Agri Concession concerned: (i) the filing of "Variazione Programma Lavori" to the relevant authorities for the development program of the northern part of the field; and (ii) production optimization actions to mitigate production decline. In addition activities of the New Memorandum of Intent between Eni, Shell and the Basilicata Region progressed and included "non-oil" projects for local development as well as initiatives defined with the agreement with the Basilicata Region within the LucAS (Lucani Ambiente e Salute) project. SICILY Production Eni operates 11 production concessions onshore and 3 offshore in Sicily. The main production fields are Argo/Cassiopea, Gela, Giaurone and Bronte. Development Within the development program of the Argo Cassiopea project in the Sicilian offshore, the activities of the year concerned: (i) the completion of the Cassiopea onshore plants; and (ii) the "Variazione Programma Lavori" for the Gemini development project has been submitted to the relevant authorities. In addition, activities have been launched to assess exploration potential of the permit nearby to the Argo Cassiopea concession, including the Panda discovery. Within local support initiatives: (i) the Implementation Agreement for renovation program in the Gela area was signed; (ii) the Cooperation Agreement with Banco Alimentare has been renewed, in continuity from 2023, supporting the disadvantages communities; and (iii) the "Musei in Rete - Digitalizzare I Beni Culturali" project was launched in collaboration with the Eni Enrico Mattei Foundation and local stakeholders. Rest of Europe NORWAY Eni has been present in Norway since 1965 and the activities are conducted through the Vår Energi associate (Eni's interest 63.1%). Activities are performed in the Norwegian Sea, in the North Sea and in the Barents Sea, on a total developed and undeveloped acreage of 38,196 square kilometers (9,146 square kilometers net to Eni). Exploration and production activities are regulated by concession contracts (Production License, PL). According to a PL, the holder is entitled to perform seismic surveys and drilling and production activities for a given number of years with possible extensions. Production Eni's production amounted to 214 kboe/d in 2025. In 2025, an additional participation stake was acquired in the Ekofisk producing project in the PL018F development license and thus Vår Energi's interest to approximately 52% in the Greater Ekofisk Area. The transaction is subject to the necessary approvals. Development During 2025, production start-up was achieved at: (i) the Johan Castberg oil fields which includes the Skrugard, Havis and Drivis discoveries made between 2011 and 2014. The field will be producing for 30 years, with an expected production peak of 220 kbbl/d; (ii) the Balder-X oil field in Norwegian offshore with a peak production of about 80 kboe/d already reached during 2025; (iii) the Askeladd West gas field to ensure full capacity of the Hammerfest LNG plant in the next years. Exploration Exploration activity yielded positive results with five commercial discoveries, in particular with: (i) the Vidsyn exploration well in the PL586 license in the Norwegian Sea; (ii) the Drivis Tubåen exploration well in the PL532 license in the Barents Sea nearby to the Johan Castberg field; (iii) the Goliat Ridge discoveries, adjacent to the Goliat producing field in the Barents Sea. Evaluation activities are underway for fast-track development; (iv) the F Sør exploration well in the PL090 license in the North Sea and of the Smørbukk Midt exploration well in the PL094 license in the Norwegian Sea, the latter already in production leveraging on the existing facilities in the area. NETHERLANDS Eni has been present in Netherlands since 2024 as part of the Neptune Energy acquisition. Eni's activities are carried out in the North Sea including 29 offshore facilities with 4 major treatment hubs. The total developed and undeveloped acreage was 4,137 square kilometers (1,514 square kilometers net to Eni). Exploration and production activities are regulated by license contracts (Production License, Exploration License) that authorize the holder to carry out seismic surveys, drilling and production activities until the contractual expiry, with the possibility of renewal. Production Eni's production amounted to 13 kboe/d in 2025 and mainly comes from the F3, G-blocks, K2b-A, K9ab-B, L12-L15, L10/K12, L5 hub, Q13a-A and K6-D fields. Development The activities of the year concerned: (i) the Final Investment Decision (FID) of the L7-F gas development project, production start-up is expected in 2026; (ii) the drilling of the L10-M4 development well, with production expected in 2026. UNITED KINGDOM Eni has been present in United Kingdom since 1964 and the activities are conducted through the Ithaca Energy joint venture (Eni's interest 35.92%). Total developed and undeveloped acreage was 9,767 square kilometers (4,178 square kilometers net to Eni). Exploration and production activities in the UK are regulated by concession contracts. Production Eni's production amounted to 45 kboe/d in 2025. The Ithaca Energy joint venture holds interests in 39 fields, of which 10 operated, located in the North Sea. Development During 2025, the farm-in agreements were completed in: (i) the Seagull field with acquisition of 15% interest and in the Cygnus field with an additional stake acquisition of 46%; (ii) the Tobermory gas discovery to acquire 50% interest in the West of Shetland basin. Development activities concerned: (i) production start-up of additional wells at the Captain, Cygnus and Seagull producing fields; (ii) production optimization activities in the J-Area project; and (iii) the development program of the Rosebank project. North Africa ALGERIA Eni has been present in Algeria since 1981. Developed and undeveloped acreage was 59,575 square kilometers (21,309 square kilometers net to Eni). In 2025, Eni signed a petroleum contract with Sonatrach for the exploration and development of the Zemoul El Kbar area. The contract, with a duration of 30 years, covers a development and exploration area of about 4,200 square kilometers and includes neighboring assets previously under separate contracts. This new agreement follows the recent award, in the context of 2024 Algeria Bid Round, of the Reggane II block to Eni in partnership with PTTEP. Exploration and production activities in Algeria are regulated by Production Sharing Agreements (PSAs) and concession contracts. Production Eni's production amounted to 131 kboe/d in 2025 and mainly comes from the blocks: (i) Blocks 403a/d, Block ROM North, Blocks 401a/402a, Block 403 and Block 405b; (ii) the Sif Fatima II, Zemlet El Arbi and Ourhoud II blocks in the Berkine North basin; (iii) Berkine South block; and (iv) In Amenas and In Salah concessions located in the Southern Sahara, as well as Touat concession in the Western Sahara. During the year, an additional stake in the Touat license was acquired, increasing Eni's interest to 42.9%. Development Development activities mainly concerned the start-up of new producing wells and production optimization activities by means of workover program and plant upgrading of existing facilities. EGYPT Eni has been present in Egypt since 1954. Developed and undeveloped acreage was 36,486 square kilometers (12,449 square kilometers net to Eni). In 2025 signed agreements with Cyprus and Egypt counterparties to develop gas reserves of the Chronos discovery in the Block 6 offshore Cyprus, to be exported to international markets through Eni's existing facilities located in Egypt. The agreements are an important milestone on the path to the sanctioning of the project, and they foresee treatment and liquefaction through the processing plants facilities of the Zohr field and the liquefaction capacity at the Damietta LNG plant. Exploration and production activities in Egypt are regulated by Production Sharing Agreements. Production In 2025, Eni's production amounted to 242 kboe/d and mainly comes from: (i) the Shorouk block in the Mediterranean offshore with the giant Zohr gas field; (ii) the Sinai concession, mainly in the Belayim Marine-Land, Abu Rudeis and Sinai Ras Gharra fields; (iii) the Western Desert in the Melehia, East Obayed and South West Meleiha concessions; and (iv) Baltim, North El Hammad, Nile Delta, North Port Said and Temsah concessions. In addition, Eni participates in the Ras el Barr and South Ghara concessions. Gas production from the Nile Delta, Temsah, North Port Said and Ras el Barr is supplied to the plant owned by United Gas Derivatives Co (Eni 33.33%) where, after condensate extraction, the residual gas is fed back into the GASCO national grid. Development Development activities mainly concerned: (i) production optimization and drilling activities in the Mediterranean offshore; and (ii) ongoing construction activities of the gas plant in the Western Desert area as provided by the development plan. In 2025, Zohr production was optimized through activities of reservoir and network management. The drilling campaign performed in 2025 was successfully executed and new optimization opportunities are under definition for 2026. Local development initiatives concerned: (i) the University Education project in Energy Engineering Technology, carried out in collaboration with the Politecnico di Milano and Eni Corporate University in the Port Said area; (ii) in the healthcare sector, the Advanced Professional Training Center, established in collaboration with the Ministry of Health and Population (MoHP) in Port Said, provided training of local staff to fill key gaps in medical specialties and to enhance the clinical skills of healthcare staff at the national level; (iii) projects in the agricultural sector in the Governorates of South Sinai and Matrouh for communities in areas with high desertification, as well as the Towards Organic Agriculture project to support small farmers in the transition to organic farming. Exploration Exploration activity yielded positive results in the Western Desert concessions. The discoveries were already put into production and achieving production ramp-up in the area. In addition, in April 2026, Eni announced a significant gas and condensate discovery with the successful drilling of the Denise W 1 exploration well in the Temsah Concession, located offshore in the Eastern Mediterranean. Preliminary estimates indicate about 2 trillion cubic feet (Tcf) of gas in place and 130 mmbbl of associated condensates. The discovery is nearby existing production facilities providing significant synergies for fast-track development. LNG business Eni holds interest in the Damietta liquefaction plant with a capacity of 5.2 mmtonnes/y of LNG associated to approximately 283 bcf/y of feed gas. LIBYA Eni has been present in Libya since 1959. Exploration and production activity is carried out in the Mediterranean Sea facing Tripoli and in the Libyan Desert area. Developed and undeveloped acreage were 80,048 square kilometers (24,644 square kilometers net to Eni). In 2025, a relatively stabler sociopolitical environment than in previous years, allowed continuity to production operations and to develop projects, despite the political landscape of the Country has remained split between the Government of National Unity installed in Tripoli and recognized by the UN and the self-appointed National Stability Government installed in the east of the Country and has resulted in several disputes and reciprocal claims. For further information see "Risk factors and uncertainties" in the Annual Report 2025. Exploration and production activities in Libya are regulated by Exploration and Production Sharing Agreement contracts (EPSA). Production In 2025, Eni's production amounted to 162 kboe/d and represented approximately 10% of the Group's total production. Production mainly comes from 6 contract areas: (i) Area C, with the Bouri oil field and Area D, with Block NC 41 in the offshore area; and (ii) Area A, consisting in the former concession 82; Area B, former concessions 100 (Bu-Attifel field) and the NC 125 Block; Area E, with the El Feel field; and Area D with Block NC 169 in the onshore area. Development In 2025 development activities mainly concerned: (i) in the Sabratha Compression project to support current production of the Bahr Essalam field, offshore activities advanced with the installation of the compression unit in the Sabratha platform; (ii) the Bouri Gas Utilization Project is ongoing as provided for the development plan, with start-up expected in 2026; and (iii) the drilling activities at the A&E Structures project as well as the construction activities of the Structure A platform were started. In addition during the year: (i) the professional training project progressed in partnership with the International Organization for Migration to increase employment opportunities; (ii) a project for the preservation and promotion of cultural heritage was launched; (iii) in the healthcare sector, a program was started in the Jalo area to strength and improve the quality of services. Exploration Exploration activities yielded positive results in March 2026 with the Bahr Essalam South 2 (BESS 2) and Bahr Essalam South 3 (BESS 3) offshore discoveries. Preliminary estimates indicate that these discoveries jointly contain more than 1 Tcf of gas in place. Their proximity to the existing production facilities of the Bahr Essalam field will ensure a fast-track development. In February 2026 Eni was awarded the O1 offshore exploration license through a consortium with another partner. Eni will be the operator. TUNISIA Eni has been present in Tunisia since 1961. Eni's activities are located mainly in the Southern Desert areas and in the Mediterranean offshore facing Hammamet, over a developed and undeveloped acreage of 5,776 square kilometers (2,106 square kilometers net to Eni). Exploration and production in this Country are regulated by concessions. Production In 2025, Eni's production amounted to 6 kboe/d and mainly comes from the Adam, Oued Zar and Djebel Grouz onshore concessions. In addition, Eni holds interest in the MLD and El Borma concessions. Development In 2025, Eni was awarded a 35% stake in the Sabeh concession. The activities of the year mainly concerned: (i) the development activities of the Sabeh concession; (ii) a production optimization program in the Adam, MLD and El Borma concessions; (iii) the start of development drilling activities in the Djebel Grouz concession; and (iv) the program to support local development, mainly with the installation of photovoltaic panels in 14 public schools. Sub-Saharan Africa ANGOLA Eni has been present in Angola since 1980 and operates through Azule Energy, the equally owned joint venture by bp and Eni. Azule Energy holds interests in 17 blocks (of which 9 exploration blocks) and one exploration license in Namibia as well as in the Angola LNG JV and Solenova, a solar company jointly held with Sonangol which is operating in the renewable energy business and in decarbonization initiatives. In particular, Solenova operates the 25 MW photovoltaic plant in Caraculo, located in the province of Namibe. Activities are performed over a developed and undeveloped acreage of 50,890 square kilometers (9,421 square kilometers net to Eni). Exploration and production activities in Angola are regulated by concessions, PSAs, and Risk Service Contract. Production In 2025 production amounted to 106 kboe/d net to Eni. In 2025, Azule signed a farm-out agreement to sell its 20% stake in Block 14 and 10% in Block 14K/A-IMI. The transaction is subject to approval by the relevant authorities. In the year, production started at the operated Agogo Integrated West Hub project, in block 15/06, offshore Angola. The project consists in the development of two fields, Agogo and Ndungu, with an expected production plateau of 180 kboe/d. In February 2026 full-field production start-up was achieved at the Ndungu field, just six months after Agogo FPSO first oil. The project comprises seven production wells and four injection wells, with an expected oil production peak of 60 kbbl/d. Development The development activities concerned: (i) the NGC (New Gas Consortium) project to develop the Quiluma and Maboqueiro fields. The project, the first non-associated gas development in the Country, completed the installation and commissioning of two offshore production platforms as well as the gas and condensate treatment and export plant to the A-LNG plant. The estimated production plateau is approximately 330 mmCF/d and 18 kbbl/d of condensates. First gas production into plant was reached in February 2026 and in March 2026 the start of gas delivery from the Quiluma field; (ii) the Greater PAJ project to develop the southern area of the two operated blocks 31 and 31/21. The project's final approval by the partners is expected in 2026. During 2025, programs to support local development progressed by means of certain initiatives on promoting access to water and sanitation, community health, education, social inclusion, economic diversification, access to solar energy, environmental protection and demining. In particular: (i) in the educational field, 3 new schools were opened and 10 schools were renovated; (ii) extension agreement was signed to support the cardiological care improvement in the country's healthcare facilities, as well as 2 new medical facilities were inaugurated while the renovation of 9 others was completed; (iii) international healthcare capacity building programs progressed to enhance the skills of hospital healthcare staff by means of specialized training activities in five hospitals in Luanda, involving Italian Centers of Excellence; and (iii) projects for environmental protection have been implemented. Exploration The exploration activity yielded positive results: (i) with the first dedicated gas exploration well, Gajajeira-01; and (ii) in February 2026, with the Algaita-01 oil well in the offshore Block 15/06. Preliminary estimates indicate oil in place of around 500 million barrels. Existing production facilities further enhance the value of this discovery. CONGO Eni has been present in Congo since 1968. Eni's activities are concentrated in the conventional and deep offshore facing Pointe-Noire and onshore Koilou region over a developed and undeveloped acreage of 1,838 square kilometers (978 square kilometers net to Eni). In March 2025, Eni and Vitol agreed on the economic terms of the possible farm-out of a 25% stake held by Eni in the operated Congo FLNG project. The closing of the transaction is subject to customary regulatory approvals and other conditions. During the year, Eni closed the divestment of onshore producing licenses in the country, in line with strategy of rationalizing the upstream portfolio. Exploration and production activities in Congo are regulated by Production Sharing Agreements. Production In 2025, Eni's production amounted to 69 kboe/d and mainly comes from the Néné-Banga Marine and Litchendjili (Block Marine XII), Kitina and Yanga Sendji fields as well as the Congo LNG project to monetize the Block Marine XII resources. Development It was inaugurated the new Yasika logistics platform, a strategic infrastructure within the Phase 2 development program of the Congo LNG project. The platform supports the operations for the two floating liquefaction units: Tango FLNG (0.6 mmtonnes/year), which began production in December 2023, and Nguya FLNG (2.4 mmtonnes/year), with production start-up achieved at the end of 2025, marking the completion of the Phase 2 to enhance the gas potential of the Marine XII permit and to increase the production capacity to 3 MTPA. Within the local development initiatives: (i) the Oyo Center of Excellence for Renewable Energy and Energy Efficiency (CEO) reached full operational capacity during the year; (ii) awareness programs on the deployment of renewable energy technologies progressed to support the Country's socio economic development; (iii) the integrated program in the HINDA district progressed targeting interventions for rural communities by means of education and health initiatives, access to water resources, and supporting the agricultural sector. CÔTE D'IVOIRE Eni has been present in Côte d'Ivoire since 2015 and activities are concentrated in the offshore of the Country, with a developed and undeveloped acreage of 13,183 square kilometers (10,760 square kilometers net to Eni). Within Eni's strategy of optimizing its upstream portfolio by accelerating the monetization of exploration discoveries through the divestment of equity stakes, in September 2025 Eni finalized the sale of a 30% stake in the Baleine project to Vitol and in January 2026 Eni signed a binding agreement with SOCAR, the State Oil Company of the Republic of Azerbaijan, for the sale of an additional 10% stake in the project. In October 2025, Eni signed an exploration contract for the CI-707 offshore block, geologically continuous with the nearby CI-205 block, where Eni announced the discovery of Calao in March 2024. This proximity offers an opportunity for future synergistic developments. In 2025 Eni and Petroci announced a significant increase in gas supply for Côte d'Ivoire's power generation system. The produced gas, up to 70 mmcf/d, will be entirely allocated to meet local demand, ensuring a reliable supply for the Country's power generation needs and further reinforcing Côte d'Ivoire's role as a regional energy hub. Exploration and production activities in the Country are regulated by Production Sharing Agreements. Production In 2025 Eni's production amounted to 50 kboe/d and comes from the Baleine offshore project which is located in the CI-101 and CI-802 blocks. Development The development activities of the year included: (i) the completion of the Phase 2 project at the Baleine field; and (ii) the Phase 3 concept definition activities of the Baleine development program. The final investment decision (FID) is expected to be sanctioned in 2026. The Phase 3 project provides for increasing production capacity to an expected peak of 150 kbbl/d and approximately 200 mmcf/d of associated gas for domestic needs. In addition, within the Baleine project, local development activities concerned: (i) initiatives to support 20 healthcare centers including facilities renovation, energy infrastructure development, and medical and equipment supply; (ii) professional training programs to promote youth employment, particularly through collaboration with the Iveco Group; (iii) economic diversification, access to education, and school equipment supply initiatives. Exploration Exploration activity yielded positive results: (i) with the drilling of the Cachalot-1X well, which confirmed the eastern extension of the Baleine field; and (ii) in February 2026, with the offshore Murene South-1X gas and condensate well (Eni operator with a 90% interest) confirming the exploration potential of the Calao gas complex with estimated volumes of 5 Tcf of gas and 450 million barrels of condensates. GHANA Eni has been present in Ghana since 2009. Developed and undeveloped acreage in deep offshore was 1,172 square kilometers (502 square kilometers net to Eni). Eni is the operator with a 44.44% interest of the Offshore Cape Three Points (OCTP) permit which is regulated by a concession agreement and also operates with a 42.47% interest the offshore exploration license Cape Three Points Block 4 (CTP-4). Production In 2025 Eni's production amounted to 35 kboe/d and comes from the Sankofa field in the OCTP permit. In September 2025, Eni and its Offshore Cape Three Points (OCTP) project partners, Vitol and the Ghana National Petroleum Corporation (GNPC), signed a Memorandum of Intent with the Government of Ghana, finalized to the country's oil and gas production increase and new sustainable initiatives. The collaboration focuses also on the evaluation of exploration activities and the new potential development of the Eban-Akoma field. In particular, the development project provides for the linkage to the existing facilities in the OCTP permit and was submitted for approval by the Country's authorities at the end of 2025. Development Development activities of the year mainly concerned the OCTP producing permit: (i) workover activities at the wells of the Sankofa East field; (ii) the debottlenecking activities of the non-associated gas system were completed and thus increasing capacity; (iii) tenders were launched for awarding contracts of the linkage of the new GyeNyame non-associated gas well to existing FPSO; (iv) the Afforestation Project progressed within environmental protection initiatives; and (v) access to water and sanitation programs as well as healthcare initiatives including community awareness campaigns, particularly in the western area of the Country. Exploration Exploration yielded positive results with the Eban 2A well and thus marking the close of the appraisal campaign Eban-Akoma field in the Cape Three Points 4 block with the formalization to the Government. MOZAMBIQUE Eni has been present in Mozambique since 2006, following the award of the exploration license relating to Area 4 offshore the Rovuma Basin block, located in the north of the Country. The Rovuma Basin represents a new frontier in the oil and gas industry thanks to extraordinary gas discoveries made during intense only three-year exploration campaign. To date, resource base reached 85 Tcf. Developed and undeveloped acreage is 3,912 square kilometers (916 square kilometers net to Eni). Production Production comes from the Coral South project located in the Area 4 block, first production start-up in the Country to develop gas discovery in the Rovuma offshore area. In 2025 production amounted to 25 kboe/d net to Eni. Production is sent to the Coral Sul Floating Liquefied Natural Gas (FLNG) vessel for the treatment, liquefaction, storage and export, with a capacity of approximately 3.4 mmtonnes/y of LNG. The Coral Sul FLNG was designed to high standards in terms of safety and sustainability, demonstrating Eni's commitment to ensure the safety of people, the protection of the surrounding environment and local communities as well as asset integrity. The vessel was implemented with an energy-efficiency approach and CO 2 emission reduction. In particular, the Coral Sul FLNG achieves also zero flaring during normal operations and uses gas efficient turbines to power generation. Development In October 2025, Eni and its partners reached the Final Investment Decision (FID) to develop the Coral North FLNG project which will put in production the gas volumes from the northern part of Area 4 Coral gas reservoir. In January 2026, the sail away of the Coral North floating LNG was achieved, fully in line with the project schedule, with 3.6 MTPA production capacity, bringing the Country's total LNG production to 7 MTPA.The project will leverage Eni's fast-track approach and expertise from the Coral South project and is expected to achieve start-up at the end of 2028. During the year initiatives to support local communities progressed with: (i) programs to promote schooling and youth employment in the Pemba district, as well as initiatives to improve access to drinking water in the districts of Pemba, Mecufi, and Metuge; (ii) activities to enhance social and health services, also by means of training programs. In particular, a new Intensive Care unit and a CT scanner were put into operation in the Cabo Delgado Province, and renovation activities progressed with two maternity wards and facilities providing accommodation for pregnant women, and three ambulances were supplied in the Maputo Province; and (iii) economic development programs in the agricultural and fisheries sectors in the provinces of Cabo Delgado and Manica, as well as biodiversity protection initiatives in the Mecufi district. NIGERIA Eni has been present in Nigeria since 1962. Total developed and undeveloped acreage was 18,306 square kilometers (4,358 square kilometers net to Eni). In March 2026, Eni signed an agreement between the Federal Government of Nigeria and Eni on the conversion of Oil Prospecting Licence 245 (OPL 245). The agreement includes the mutually satisfactory settlement of all claims related to OPL 245 and the discontinuation of the international arbitration proceeding; as a consequence, it allows the conversion of the existing license into two development licences, Petroleum Mining Leases (PML) 102 and 103, and two exploration licences, Petroleum Prospecting Leases (PPL) 2011 and 2012, to Nigerian Agip Exploration Limited (NAE) as operator, alongside its partners Nigerian National Petroleum Company Limited (NNPC) and Shell Nigeria Exploration and Production Company Limited (SNEPCO). Exploration and production activities in Nigeria are regulated by Production Sharing Agreements and concession contracts. Production In 2025 Eni's production amounted to 48 kboe/d and comes from the Abo field (OML 125), the Bonga field (OML 118) and as partners of Renaissance Africa Energy Company Limited JV (RAEC JV; former SPDC JV), Eni holds a 5% interest in 18 blocks. In November 2025, Eni acquired an additional 2.5% stake in the Production Sharing Contract (PSC) OML 118, exercising its preemption right. Development The development activities of the year concerned the Bonga North project in the OML 118 block, which includes the linkage of new subsea wells to the existing FPSO. LNG business Eni holds a 10.4% stake in Nigeria LNG Ltd, which owns and runs the Bonny natural gas liquefaction plant in the Eastern Niger Delta. The plant has a production capacity of 22 mmtonnes/y of LNG associated, corresponding to approximately 1,270 bcf/y of feed gas. The natural gas supplies to the plant are currently provided under a gas supply agreement from the RAEC JV (former SPDC JV), TEPNG JV and Oando Energy Resources Nigeria Limited JV. The volumes treated by the plant during 2025 amounted to approximately 830 bcf. LNG production is sold under long-term contracts in the United States, Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG Ltd as well as is sold FOB by means of the fleet owned by third parties. Kazakhstan Eni has been present in Kazakhstan since 1992. Eni's activities are performed mainly in the Kashagan and Karachaganak producing fields, over a developed and undeveloped acreage of 4,896 square kilometers (1,273 square kilometers net to Eni). In 2025 Eni's production amounted to 161 kboe/d. KASHAGAN Eni holds interest in the North Caspian Sea Production Sharing Agreement (NCSPSA). The NCSPSA defines terms and conditions for the exploration and development of the giant Kashagan field, which was discovered in the Northern section of the contractual area in the year 2000. Production The liquid production is stabilized at the Bolashak plant and then marketed. Gas production is partly processed and sold to the national oil company, while the raw gas volumes (approximately 50%)...

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