History and development of the Company Eni, the former Ente Nazionale Idrocarburi, a public law agency, established by Law No. 136 of February 10, 1953, was transformed into a joint stock company by Law Decree No. 333 published in the Official Gazette of the Republic of Italy No. 162 of July 11, 1992 (converted into law on August 8, 1992, by Law No. 359, published in the Official Gazette of the Republic of Italy No. 190 of August 13, 1992). The Shareholders’ Meeting of August 7, 1992 resolved that the company be called Eni SpA. Eni is registered at the Companies Register of Rome, register tax identification number 00484960588, R.E.A. Rome No. 756453. Eni is expected to remain in existence until December 31, 2100; its duration can however be extended by resolution of the shareholders. The Company shares are listed at the main Italian stock exchange, which is the primary trading market for the Company, and at the New York Stock Exchange where the Company’s ADRs are traded under the ticker symbol “E”. The SEC maintains an Internet site that contains reports, proxy and information statements of the Company, and other information regarding Eni that we file electronically with the SEC at http://www.sec.gov, searching for: ENI SPA (E, EIPAF) (CIK 0001002242). The same reports and information are available at the Company’s website: www.eni.com. Eni’s registered head office is located at Piazzale Enrico Mattei 1, Rome, Italy (telephone number: +39-0659821). Eni branches are located in: San Donato Milanese (Milan), Via Emilia, 1; and San Donato Milanese (Milan), Piazza Ezio Vanoni, 1. Internet address: eni.com The name of the agent of Eni in the United States is Marco Margheri, Washington DC – USA 601, 13th street, NW 20005. Eni Spa is the parent company of Eni’s group companies. Eni SpA together with its subsidiaries and through several participated entities engages in producing and selling energy products and services to worldwide markets, with operations in the traditional businesses of exploring for, developing, extracting, and marketing crude oil and natural gas, manufacturing and marketing oil-based fuels and chemicals products and gas-fired power as well as energy products from renewable sources. The Company is implementing a strategy designed to improve profitability and shareholders’ returns leveraging on maximizing the value of its assets’ portfolio, through organic exploration, fast reserve development, production growth and by applying the satellite model to unlock asset value, while restructuring and revamping the businesses operating in challenged sectors. This strategy aims to gradually reduce the Company’s carbon footprint, with the goal of reaching carbon neutrality by mid-century. Group description of business activities and operating data as disclosed in Item 4 and financial data requested by accounting standards for segmental reporting as disclosed in Item 5 are presented based on the operating segments tracked by the chief operating decision maker to evaluate profit centers financial performance and resources allocation, as follows: ● Exploration & Production: engages in oil and natural gas exploration and field development and production, as well as in LNG operations, in 33 countries, most notably Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, Mexico, the United States, Kazakhstan, Algeria, Iraq, Indonesia, Ghana, Mozambique, Qatar, Côte d'Ivoire and the United Arab Emirates. In certain geographies, mainly Angola, Norway and the UK, the business activities are conducted through equity-accounted entities. The business also engages in oil and products trading activities, designed to perform supply balancing transactions in the market with a view of ensuring the requested slate of crudes to the refining business and to stabilize or hedge commercial margins. ● Global Gas & LNG Portfolio and Power: engages in the wholesale activity of supplying and marketing gas via pipeline and LNG, maximizing supply of equity gas/LNG, wholesale marketing of electricity and international transport activity. It also comprises gas, LNG, and power trading activities targeting both hedging and stabilizing the Group’s commercial margins and optimizing the gas asset portfolio. This operating segment also includes the results of operations of the Power business, engaged in the production of power produced by a fleet of thermoelectric plants located in Italy and in providing back-up capacity to the Italian grid. 18 Table of Contents ● Enilive engages in the manufacturing of biofuels at the Italian plants of Venice and Gela and through the Chalmette JV in the USA, whilst advancing expansion plans in Italy and South-East Asia. It manages an extensive network of service stations in Italy and selected European markets, also providing services and non-fuel products to drivers. ● Plenitude engages in the activities of retail marketing of gas, power and related services and a large customer base in Italy and in the Rest of Europe. It engages in the renewable energy business (solar photovoltaic and wind facilities both onshore and offshore), which comprises building, commissioning, and managing renewable energy producing installations and wholesale marketing of electricity and managing and expanding a network of charging stations for electric vehicles distributed throughout the European territory, in particular in Italy. ● Refining and Chemicals: the Refining business engages in refining crude oil to manufacture fuels and in wholesale marketing activities, which mainly consist of the inter-company supply of refined products to the Group subsidiary Enilive and in sales to large accounts. In the Chemical business Eni, through its wholly owned subsidiary Versalis, engages in the production and marketing of basic chemical products, plastics and elastomers. Versalis is developing the business of manufacturing chemical products from renewable raw materials, bioplastics and bio-based products. Activities are concentrated in Italy and in Europe. The results of operations of the Refining business and the Chemical business have been combined in a single reporting segment because the businesses exhibit similar economic characteristics. ● Corporate and Other activities: include the costs of the main business support functions, as well as the results of the Group environmental clean-up and remediation activities performed by the subsidiary Eni Rewind and of the businesses engaged in developing the projects for CO2 capture and storage and/or utilization and agricultural hubs to ensure supply of bio-feedstock to the Group’s biorefineries. A list of Eni’s subsidiaries is provided in “Item 18 – Note 37 – Other information about investments – of the Notes on Consolidated Financial Statements”. Strategy The Company is executing a strategy designed to grow the business and to maximize value creation, leveraging organic opportunities in our asset portfolio and the satellite model, with a view to ensuring competitive shareholders’ returns, while delivering on Eni’s stated long-term goal of reducing the carbon footprint of its products and industrial processes. This strategy aims to address the current issues in the global energy markets of ensuring stable, affordable and increasingly decarbonized supplies to the world economy. Against this backdrop, we intend to continue supplying our customers the energy products they require, while progressing the Company’s transformation to adapt to and to prosper in a low-carbon economy. We plan to monetize the value of our oil&gas businesses and to speed up the growth plans of the new businesses related to the energy transition, where we expect higher growth rates than in traditional activities. Deployment of our “satellite strategy” and dual exploration model will be utilized by the management to anticipate asset monetization and to achieve an optimal risk-reward balance considering scale and reach of our growth plans. This strategy will be underpinned by continued capital discipline to select the best investment opportunities, a drive to reduce costs and improve efficiency and use of proprietary technologies to enhance efficacy of legacy businesses and to reap new opportunities in the transition. The strategic guidelines that are driving our plans are: 19 Table of Contents  To actively contribute to the achievement of the 17 UN SDGs, which are reflected in Eni’s mission, particularly the goals of tackling climate change and securing universal access to reliable, affordable, and clean energy.  To grow the oil&gas business mainly by gradually expanding natural gas production and the proportion of natural gas reserves in our portfolio leveraging recent discoveries and our expertise in floating production of LNG, based on our expectations that natural gas will be the transition fuel to a low-carbon economy. Downstream integration with LNG trading activities is expected to boost profitability by capturing a larger proportion of margins along the gas value chain.  To accelerate the development of our new businesses related to the transition, managed by our subsidiaries Enilive and Plenitude, leveraging our distinctive satellite model designated to attract aligned capital to make those entities increasingly independent from a financial standpoint and able to pursue their own growth plans. As part of this, in 2025 we completed a couple of landmark deals with private equity funds KKR, which made an investment to acquire a 30% non-controlling interest in the share capital of Enilive; and Ares with a 20% non-controlling investment in Plenitude. Previously another private equity fund completed a two-tranche non-controlling investment in Plenitude by acquiring a 10% interest (of which 3% in 2025 and the other in 2024). Those transactions delivered €6.5 billion proceeds to the parent company of which €5.9 billion in 2025. Eni has retained control of those subsidiaries in 2025. Those funds will help develop the manufacturing capacity of biofuels at Enilive and the renewable capacity of Plenitude. Furthermore, a new transition-related satellite for our business of carbon capture and storage “CCS” has been established in joint venture with equity fund GIP, which acquired a 49.99% interest in the entity, in view of developing and valorizing our ongoing projects in UK, where we are making substantial progress to achieve start-up.  To upgrade the oil&gas portfolio by creating geographically focused entities in joint venture with local partners which are able to grow independently without making recourse to shareholders financial support, and to distribute shareholders significant dividends streams, as well as by divesting non-strategic properties. In 2025, replicating the previous successes of Azule Energy in Angola, Var Energi in Norway and Ithaca Energy in the UK continental shelf, we signed a binding agreement with Petronas to combine the two shareholders’ gas assets in Indonesia/Malaysia. This business combination is intended to establish an important gas and LNG-focused player in a fast-growing region with an expected long-term production plateau of 500 Kboepd to be achieved by developing the large mineral potential of the combined assets through a self-funded plan. This entity is expected to start operations by mid-2026 and to be accounted under the equity method. Furthermore, in line with our dual exploration model, we divested a 30% interest in our flagship Baleine oilfield under development off Côte d’Ivoire to a third party with net proceeds of €1.1 billion to Eni. A further 10% stake is expected to be divested in 2026 and other transactions are planned to be completed.  To execute an industrial plan to restructure and transform our loss-making businesses of downstream oil refining and petrochemicals production leveraging our proprietary technologies and selected expenditures to upgrade existing plants to biorefineries or activities linked to the transition and the circular economy and to develop chemicals from bio-feedstock and specialties. In 2025, we made substantial progress in those restructuring plans. The two loss-making cracking plants of Brindisi and Priolo have been definitively shut down, and projects are ongoing to reconvert those hubs to the manufacturing of low-carbon products and renewable solutions. Construction works are ongoing at the refining hub of Livorno to upgrade the plant into a biorefinery, and a similar project is underway at Sannazzaro.  To maximize the benefits of integration of the portfolio along the entire energy value chain.  To retain financial discipline by selecting investment opportunities that fit with our strict return criteria and by executing a divestment plan to balance growth expenditures and to maintain solid financial metrics.  To ensure competitive and progressive returns to shareholders by gradually increasing the dividend and by retaining share repurchases as a flexible tool to distribute growing amount of cash in case of upside in the underlying business performance or in the scenario.  To leverage our proprietary technologies to underpin the development of new businesses or the restructuring of businesses still tied to the oil cycle. Our financial plans for the next five-year period 2026-2030 provide execution of this strategy with the support of a gross capital expenditures program of around €29 billion, and the continuing valorization of our asset portfolio through divestments and equity transactions to balance the cash requirements of the growth plan and to maintain a solid financial structure and to ensure competitive returns to our shareholders, under assumptions of an average Brent price of around 70 $/bbl in the five-year period (in real terms 2025). Our future performance will be driven by: profitable production growth in E&P, continued margin optimizations at our GGP business (by leveraging integration with upstream equity LNG projects), steady and growing results of our businesses focused on the transition through expansion of biofuels manufacturing capacity and renewable generation capacity, and finally a gradual recovery of profitability at our oil downstream and chemicals businesses (see Item 5 in the looking forward section). We plan to remain financially disciplined and to retain a solid balance sheet and indebtedness ratio, measured as ratio of net debt to equity plus net debt (in both cases excluding IFRS 15 liabilities) which is projected to remain in a range of 0.1-0.15 in the next five-year plan (see Item 5 in the looking forward section). 20 Table of Contents TCFD disclosures on carbon neutrality by 2050 With a view of achieving a significant reduction in its carbon footprint in line with societal demands for cleaner energy products, Eni is implementing an industrial transformation to gradually reduce the carbon intensity of its products and industrial processes in the long-term. To ensure transparency to its stakeholders, Eni has long been committed to promoting comprehensive and effective climate change disclosure. Eni confirms its commitment to the recommendations of the Financial Stability Board's Task Force on Climate-Related Financial Disclosure (TCFD), which it has adopted since 2017, the first applicable reporting year. Therefore, this disclosure is structured according to the four thematic areas outlined by the TCFD: Governance, Risk Management, Strategy, Metrics, and Targets; presented below. For further discussion, see "Eni for - A Just Transition" and Eni's response to the CDP Climate Change 2023 questionnaire. In addition, Eni is undergoing a monitoring exercise on the development of soft and hard law regulations related to climate risk, aimed at assessing its tools' resilience and possible adaptation (with particular attention to the recently updated (June 2023) OECD Guidelines, the CSRD and ESRS, and the CS3D proposal). This exercise may lead to integrating new tools for corporate climate disclosure. Climate change-related risk management Societal demand for action on climate change increased after the 2018 Intergovernmental Panel on Climate Change (IPCC) Special Report, which established the more ambitious 1.5°C goal of the Paris Agreement as the default target. While recent geopolitical and economic disruptions have reduced momentum for climate initiatives and energy transition, mid- to long-term risks remain. Ongoing governmental actions, along with pressure from civil society and the financial sector, continue to drive the need to maintain our decarbonization plans. The energy transition and stricter greenhouse gas (GHG) regulations could pose risks to the Group’s financial performance and business prospects, as the Company still relies substantially on its legacy Exploration & Production business. The potential impact and likelihood of exposure for Eni could vary across different time horizons, depending on specific risk components. Identifying and assessing climate-related risks is part of Eni’s Integrated Risk Management Model, which ensures decisions consider risks in a comprehensive and forward-looking perspective. The process guarantees the detection, consolidation, and analysis of risks. It also helps the BoD verify that the risk profile aligns with medium to long term strategic objectives by monitoring risk evolution and identifying de-risking actions. Risks, including those related to climate change, are assessed considering both their probability of occurrence and their quantitative or qualitative impacts on Eni's objectives within a defined time horizon. Risks are represented in probability and impact matrices to facilitate comparison and prioritization. Climate change-related risks are analyzed, assessed, and managed by considering both energy transition risks (regulatory, legal, market, technological, and reputational) and physical risks (acute and chronic). This analysis follows an integrated, transversal approach that involves all relevant functions and business lines. Furthermore, Eni considers the risks related to implementing strategic actions to mitigate climate change. Government energy transition policies significantly influence Eni’s operating context. These policies define how countries fulfill their Paris Agreement commitments, particularly in light of the COP28 Global Stocktake, which explicitly references the need to "transition away from fossil fuels." Commitments to carbon neutrality and changes in consumer preferences could lead to a structural decline in hydrocarbon demand in the medium to long term and higher operating costs for the oil & gas sector. Uncertainties surrounding demand trends and the economic feasibility of decarbonization technologies increase the risk of long-term investment decisions. In addition, increasing polarization in the climate change debate and heightened stakeholder scrutiny could lead to restricted access to capital and challenge companies’ "license to operate". In response to these emerging trends, Eni is implementing a repositioning strategy to diversify its portfolio, growing its share on renewable energy, biofuels, sustainable chemicals, and the development of emission capture/abatement technologies and lower-carbon energy carriers. A description of the main climate-related risks is presented below. a) Regulatory risk: increasing worldwide efforts to tackle climate change may lead to adopting stricter regulations to curb carbon emissions, which could increase short-term expenditures and potentially reduce demand for our products over medium to long term. At the global level, countries' decarbonization commitments may prompt new carbon pricing mechanisms and minimum market shares for renewable or lower-carbon fuels in the medium to long term. In Europe, Eni is subject to the EU Emission Trading Scheme (EU ETS) and the UK Emission Trading Scheme (UK ETS), covering about half of its direct GHG emissions. Under these mechanisms, the company must purchase allowances for emissions above its free allocations. In the non-EU area, several developing economies have announced plans to implement carbon pricing, though initial CO2 prices are expected to be low and have little impact on Eni's activities. In addition, potential measures to reduce hydrocarbon consumption or restrict mining could limit Eni’s traditional business growth, accelerating the need for portfolio diversification. 21 Table of Contents b) Market/Technological risk: in the long term, major investments in renewable energies supported by government policies, along with rising electric vehicle adoption and the development of green hydrogen and other low-carbon technologies, may materially reduce hydrocarbon demand. Currently, the market faces high uncertainty due to geopolitical tensions, uneven decarbonization policies (geographically), and fluctuating supply and demand. This scenario accentuates the complexity of investment decisions and decreases the predictability of the energy transition. Additionally, technological innovation plays a crucial role in the transition plans of Oil & Gas companies. In the medium to long term, several low-carbon technologies, such as advancements in electric mobility, renewable energy storage, and novel energy carriers, may reach commercial use. Eni is developing new technologies and energy carriers to transform its portfolio, including carbon capture and storage, hydrogen production/transport, and magnetic confinement fusion. Failure to anticipate shifts in supply and demand trends or in fundamental technologies for the energy transition could significantly affect growth prospects, operating results, cash flow, and shareholder returns. c) Legal risk: Oil & Gas companies face lawsuits in various jurisdictions over alleged human rights and environmental violations; such legal actions, if filed against us, could lead to financial penalties, reputational harm, or operational restrictions. Several public and private entities have initiated legal proceedings against major Oil & Gas companies, alleging liability for climate change damages, human rights violations, and other unlawful practices. Some institutional investors and civil society members have obtained judgments condemning oil companies for failing to adopt faster decarbonization plans (although appeals are still pending). Others have held Boards accountable for climate strategy or have promoted shareholder resolutions interfering with corporate plans. These actions demonstrate that some institutions and stakeholders are directly challenging oil companies’ “licenses to operate”, perceiving them as slow or reluctant to adapt their business models and capital allocation to a decarbonized scenario. This landscape increases the risk of new litigation. d) Reputational risk: financial market participants may view Oil & Gas companies as poor environmental investments, thereby reducing the attractiveness of their securities or limiting their access to capital markets. Activist investors have been seeking to interfere in company plans and strategies through shareholder resolutions. In the context of increasing climate change polarization, various segments of civil society (environmental movements, NGOs, younger generations), governmental institutions, and other stakeholders often hold Oil & Gas companies responsible. This debate pressures oil company boards to accelerate transition strategies and pushes the financial sector (asset managers, banks, and insurers) to align portfolios with "Net Zero" targets. Some large European banks and financial institutions have also announced they will stop financing new Oil & Gas projects. A scenario in which a larger share of the financial world disengages from hydrocarbons could make it more difficult to access capital markets, resulting in increased pressure on Oil & Gas companies' stock prices, higher financing costs, and greater equity risk. e) Physical risk: extreme weather phenomena, allegedly caused by climate change, may disrupt our operations. Studies in the scientific community attribute the increased frequency of acute and chronic weather and climate events, such as hurricanes, floods, droughts, desertification, rising ocean levels, and melting glaciers, to climate change. These extreme weather events could have a significant economic and community impact. For companies, they may cause prolonged disruptions to industrial operations and damage to facilities and infrastructure, leading to losses in productivity and cash flow, higher repair and maintenance costs, and supply chain interruptions. Eni has adopted a structured risk management process to identify and analyze assets exposed to potential changes in natural events (acute and chronic) over the medium to long term, which may impact asset operability and safety. This process considers different climate scenarios, consistent with varying emission projections and time horizons of short (5/10 years), medium (10/20 years), and long-term (20/30 years). We assess the inherent risk of assets, defined as the exposure to specific natural events based solely on location and climate evolution, and the residual risk, which is the exposure after considering existing or planned mitigation measures. Assets still at risk after mitigation actions are further analyzed as part of the Asset Integrity process. 22 Table of Contents Governance of climate-related risk Role of the BoD. Eni's decarbonization strategy is a key component of its overall business strategy, implemented through a structured Corporate Governance system, where the BoD and the CEO play central roles in addressing climate change issues. Specifically, the BoD reviews and approves the Strategic Plan proposed by the CEO, which sets strategies and targets, including those related to climate change and energy transition. Since 2019, the BoD has also reviewed and approved Eni’s medium/long-term plan, which outlines and monitors progress on decarbonization targets and their economic and business sustainability through to 2050. Moreover, the BoD assesses Eni's economic and financial exposure to carbon pricing risk before approving individual investments and monitors the project portfolio every six months. Annually, the BoD reviews the impairment test results for major Cash Generating Units, based on the International Energy Agency (IEA) Net Zero Emissions (NZE) scenario. The Board also receives quarterly updates on the assessment and monitoring of Eni’s top risks, including climate change. Since 2014, the Eni BoD has been supported by the Sustainability and Scenarios Committee (SSC). This committee was established on a voluntary basis and assists the BoD in performing its duties. The SSC periodically examines the integration of strategy, development scenarios, and the medium/ long-term sustainability of the business, with a focus on energy transition and climate change. Role of management. In 2024, the Company reorganized its business activities into three structures to maximize operational effectiveness and accelerate the implementation of the carbon neutrality strategy: (i) “Chief Transition & Financial Officer” aimed at maximizing the value of transition-related businesses; (ii) “Global Natural Resources”, tasked with optimizing margins across the entire oil & gas value chain, including power and trading. (iii) Industrial Transformation, focused on accelerating the conversion of downstream oil and the restructuring of the chemicals sector. The strategic commitment to reducing carbon footprint is reflected in the Variable Incentive Plans for the CEO, General Managers, Managers with strategic responsibilities, and other Executive Managers. In particular, the Long-Term Stock-based Incentive Plan includes environmental sustainability and energy transition targets, accounting for a total weight of 35%, related to “Net GHG emissions upstream (scope 1 and 2)” (20%) and Biojet fuel production capacity (15%). The Short-Term Incentive Plan is also aligned with Eni's strategic transformation objectives, including an environmental sustainability target focused on “Net GHG emissions upstream (scope 1 and 2),” which is consistent with the Long-Term Incentive Plan. For the CEO, this objective carries an overall weight of 20%, while for the Company management, the weight is allocated based on the assigned responsibilities. An equally important aspect of the transition journey is the dialogue with policymakers. Eni actively engages both directly and indirectly through industry associations, drawing on its expertise as an international energy company. The company contributes to defining strategies and regulations, always respecting roles and responsibilities, to promote the path toward Carbon Neutrality. Decarbonization strategy To address risks from the energy transition, the Company has developed a strategy to stay competitive and profitable in a low-carbon economy. Our medium- and long-term plans aim to drive a gradual reduction in greenhouse gas (GHG) emissions, in line with Eni’s Net Zero by 2050 objective, introduced five years ago. Starting with the 2025 reporting cycle, and in response to regulatory changes and evolving standards, Eni will recalibrate its decarbonization plan and targets to ensure sector-wide alignment and comparability. The updated approach has the following boundaries and targets:  For Scopes 1 and 2 emissions, a financial-control boundary is used, replacing the previous equity-based approach. Net Zero targets are confirmed for Upstream by 2030, and for Eni overall for 2035. The 2025 intermediate Scope 1 and 2 Upstream target of a 65% reduction from 2018 has already been met.  For Scopes 1, 2, and 3, Scope 3 is now included in accordance with the GHG Protocol, replacing the previous Lifecycle methodology. The target is expressed only in terms of emission intensity to highlight energy portfolio diversification. The Net-Zero intensity target is confirmed for 2050, with 15% and 50% reductions from 2018 levels by 2030 and 2040, respectively. The Company plans to utilize carbon credits certified under internationally recognized voluntary market standards, such as the Verified Carbon Standard (VCS) by Verra or the Gold Standard (GS), to offset residual emissions. To achieve the Net-Zero intensity target by 2050, Eni intends to use carbon credits after reducing its GHG emissions by 90-95%. Currently, carbon credits are generated from initiatives that reduce CO2 emissions that would potentially be released into the atmosphere (i.e., Natural Climate Solutions that promote forest conservation and sustainable land management, as well as technological solutions such as clean cooking systems). Eni’s strategy envisages a progressive increase in the share of credits generated from so-called Carbon Dioxide Removal (CDR) projects. These projects include NCS or technological solutions that remove CO₂ directly from the atmosphere (i.e., agroforestry, ecosystem restoration, direct air capture, bioenergy with carbon capture and storage). Our plans to achieve Net-Zero intensity by 2050 will leverage a range of industrial and technological solutions, aligned with market trends and societal energy needs. We remain committed to providing our customers with secure and affordable energy. 23 Table of Contents Significant effort has been made in recent years to upgrade our business portfolio to align it with our long-term goals, including:  Rebalancing our upstream portfolio towards the gas component, thanks to recent business combinations (e.g., Neptune Energy), asset divestments (Alaska, Nigeria, and Congo), and capital projects (e.g., the FLNG project in Congo, the planned development of gas reserves in Indonesia, Cyprus, Mozambique, and Libya). Through these actions, we aim to reach 60% gas production (including condensates) by 2030 and exceed 90% after 2040. We are initiating projects engineered for Net Zero scopes 1 and 2 emissions from the start (like the Argo-Cassiopea project in Italy and the Baleine oil project offshore Côte d’Ivoire), to drive achievement of our E&P goal by 2030;  Expanding our biofuel manufacturing capacity by upgrading and reconverting the Livorno refinery and enhancing the Venice refinery in Italy, as well as by building two biorefineries in East Asia through joint ventures with local operators in South Korea and Malaysia. Earlier this year we confirmed the FID of a biorefining line at our Sannazzaro conventional refinery and we announced the partnership with Q8 to develop a new biorefinery in Priolo. Our goal is to reach an organic refining capacity of more than 5 million tons by 2030, with an intermediate target of more than 3 million tons by 2028;  Reaching, through Plenitude, 5.8 GW of installed renewable capacity, with the goal of installing more than 15 GW by 2030, eventually rising to 60 GW by 2050. This growth supports the plan to expand the customer base to around 20 million by 2050;  Becoming, with Plenitude’s Be Charge, a leading provider of charging services for electric vehicles in Italy and Europe. The goal is to install 40,000 charging points by 2030, then about 160,000 by 2050;  Increasing electricity production from new energy carriers (e.g., power with CCS) and nuclear fusion. Eni is collaborating with partners to develop magnetic fusion technology, aiming for the first operational plant by the early 2030s;  Acquiring leadership positions in the UK, Italy, and other regions to develop CO2 storage hubs for hard-to-abate emissions. Eni is steadily increasing investments in new energy products and services to support the shift toward a decarbonized product portfolio. We expect to gradually reduce the share of spending allocated to Oil & Gas activities, as we align major investment projects with emission reduction targets and phase out investments in highly emissive “unabated” activities or products. Approximately 30% of total expenditures will be allocated to lower carbon activities in the Group’s 2026-2030 financial plan. This evolution is crucial for achieving carbon neutrality by mid-century. Sensitivity of Oil & Gas asset book values to stress-test scenarios Our oil and gas portfolio features a large share of natural gas, the fossil energy source with the lowest GHG emissions. As of December 31, 2025, natural gas proved reserves represented approximately 52% of Eni’s total proved reserves, including its subsidiary and joint ventures. Other conventional projects in our oil and gas portfolio mitigate the risk of stranded assets, with low CO2 intensity and low Brent breakeven price. The low breakeven price of our reserves results from our exploration and development model, which includes: i) an organic reserve replacement through effective exploration, focusing on near-field and proven/mature plays, leveraging existing infrastructures to quickly bring new reserves into production, and reducing development expenses and time-to-market; ii) a focus on low-complexity developments; and iii) a phased approach to production, starting up early and ramping up to reduce financial exposure and accelerate time-to-market and payback. These drivers have gradually reduced our breakeven price and improved resilience to low-carbon scenarios. Going forward, the emission profiles of our assets are expected to mitigate the risk of stranded reserves. Stranded asset risk may emerge if hydrocarbon demand declines structurally due to the transition risks described in previous paragraphs. Eni reviews its portfolio exposure to these risks annually, considering changes in GHG regulatory regimes, consumer preferences, technological developments, and physical conditions to identify emerging risks. As part of this review, management stress-tested the recoverability of the book values for the Company’s oil & gas assets in the 2025 financial statements. This test uses the IEA Net Zero (NZE) scenario and other lowered price assumptions and excludes management’s actions, such as capex rescheduling, cost reductions or curtailments, or other adaptation measures. Since the IEA NZE scenario lacks short-term pricing assumptions, we utilized crude oil pricing and other assumptions from our 2026-2030 industrial plan and interpolated up to 2035, the first available IEA pricing year. The purpose of these stress tests is to evaluate the reasonableness of the asset impairment review regularly performed by management, which uses its own oil pricing, costs, and other assumptions and considers proved reserves and some unproven reserves as the “base case”. The stress tests covered all oil & gas cash generating units (CGUs) regularly tested for impairment in accordance with IAS 36. These tests also address the risk of stranded assets that could emerge if transition pathways outpace management forecasts. Under the IEA NZE scenario, the tests showed a value loss and potential asset write-downs, but management deemed these impacts immaterial, confirming Eni’s asset resilience. The stress tests updated pricing and CO2 cost assumptions in management’s cash flow projections, while other factors, such as cost levels, volumes, and discount rates, were unchanged. Sensitivity testing applied alternative commodity price scenarios for each asset over its lifecycle to evaluate impacts more broadly. The stress-tests results are disclosed in “Item 18 - Note No.15 to the Consolidated Financial Statements”. 24 Table of Contents Key performance indicators Climate and HSE 2025 2024 CLIMATE Net Scope 1+2 Upstream (a) (million tonnes CO2eq) 4.7 6.8 Net Scope 1+2 Eni (a) 21.4 23.8 Intensity Net Scope 1+2+3 (b) (gCO2eq./MJ) 59.0 59.2 Direct GHG emissions (Scope 1) (c) (million tonnes CO2eq) 18.6 21.2 Indirect GHG emissions (Scope 2) (c) 0.5 0.6 Direct methane emissions (Scope 1) (c) (ktonnes CH4) 14.8 16.0 (a) KPIs calculated on a consolidated basis. The 2024 data are reported accordingly. (b) 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 data are reported accordingly. (c) 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. 2025 2024 HEALTH, SAFETY AND ENVIRONMENT (a) Total Recordable Injury Rate (TRIR) (total recordable injuries/worked hours) x 1,000,000 0.55 0.70 employees 0.60 0.73 contractors 0.51 0.68 Total volume of oil spills (> 1 barrel) (barrels) 217 2,815 of which: due to sabotage 0 2,140 operational 217 675 Fresh water withdrawals (mmcm) 114 127 Re-injected produced water (%) 56 51 (a) KPIs refer to 100% of the operated assets, consolidated and unconsolidated. Significant business and portfolio developments ● March 2026 - Eni initiated a reorganization of the shareholding structure of its subsidiary Plenitude, involving noncontrolling shareholders Ares Alternative Credit (affiliates of Ares Management Corporation) and Energy Infrastructure Partners, with the aim to establish a new governance framework based on joint control between Eni and Ares, which upon completion will result in the derecognition of Plenitude from Eni's consolidated financial statements. The transaction is subject to the approval of the competent authorities. ● March 2026 - Exploration activities yielded positive results in the Bahr Essalam South 2 (BESS 2) and Bahr Essalam South 3 (BESS 3) offshore discoveries, in Libya. Their proximity to the Bahr Essalam field will ensure a fast-track development through tie-back to existing production facilities. ● March 2026 - Eni announced the start of gas delivery from the Quiluma field, offshore Angola. ● March 2026 - Eni achieved the Final Investment Decisions (FIDs) for the Gendalo and Gandang gas project (South Hub) and for the Geng North and Gehem fields (North Hub) in Indonesia, only 18 months after the approval of the Projects of Development (PODs) in 2024. ● February 2026 – Final investment decision (FID) has been approved for Eni's plan to convert certain units of the Sannazzaro de’ Burgondi refinery (Pavia, Lombardy) into a biorefinery. The new biorefinery will introduce additional biofuel production from renewable raw materials, further diversifying the range of products available to the market. ● February 2026 - Eni announced the start-up of the Ndungu full-field, part of the Agogo Integrated West Hub Project (IWH), in the western area of Block 15/06, offshore Angola. ● February 2026 - Eni announced a discovery within the Calao channel complex with Murene South-1X well in Block CI-501, offshore Côte d'Ivoire. 25 Table of Contents ● February 2026 - Eni, YPF and XRG signed a binding Joint Development Agreement (JDA) to advance Argentina LNG. ● February 2026 - Eni was awarded the O1 offshore exploration license in Libya through a consortium with other partners. Eni will operate the concession. ● January 2026 – Eni announced with Q8 Italy a strategic investment in the ongoing project for the construction of a new biorefinery in Priolo, Sicily. The transformation plan for the Versalis site in Priolo received formal approval from Eni and Kuwait Petroleum Corporation Board of Directors, which follows the official binding offer submitted by Q8. The project has completed the engineering phase. ● January 2026 – Plenitude signed a four-year PPA (Power Purchase Agreement) with Zanasi Group, Official Ferrari Service and historic company specialized in coachwork, mechanics, painting and restoration of luxury cars, for the supply of 4.38 GWh/year of energy from renewables. ● January 2026 - Eni signed a binding agreement with Socar, the State Oil Company of the Republic of Azerbaijan, for the sale of a 10% stake in the Baleine Project in Côte d’Ivoire. ● January 2026 – Eni and its partners, China National Petroleum Corporation (CNPC), ENH, Kogas and XRG announced the hull launch of the Coral North FLNG that will be the second floating LNG facility to be deployed in the Rovuma Basin waters, north of Mozambique, and will bring to production the gas from the northern part of Coral gas reservoir. ● January 2026 – Eni transferred the Refining Evolution & Transformation business unit to the new company Eni Industrial Evolution S.p.A., which will aim to ensure the management of traditional assets and to consolidate the path of industrial transformation. ● December 2025 – Versalis signed with Prysmian a strategic partnership to give new life to plastic cable scrap, through an innovative chemical recycling process, developing a dedicated supply chain. ● December 2025 - Eni and Global Infrastructure Partners (GIP) announced the closing of the sale of a 49.99% stake in Eni CCUS Holding. ● December 2025 - Plenitude inaugurated the Caparacena solar project in Chimeneas, Granada. The project covers 264 hectares and includes three photovoltaic parks of 50 MW each. The complex has a total installed capacity of 150 MWp. ● December 2025 - Eni announced a significant gas discovery in Indonesia, in the Konta-1 exploration well, drilled in the Muara Bakau PSC, in the Kutei Basin, offshore East Kalimantan. ● December 2025 - Eni entered into a long-term LNG sale agreement with Thailand’s Gulf Development Company to supply 0.8 MTPA of LNG for 10 years to Gulf, one of Thailand's largest private power producers. The LNG will be delivered at regasification terminals located in the country starting from 2027. This contract follows a 2-year deal signed by the two corporations in 2024. The agreement represents Eni’s first long term LNG supply to Thailand. ● December 2025 - Plenitude signed with Acea S.p.A. a binding agreement for the acquisition of a 100% equity stake in Acea Energia, a company fully owned by the Acea Group that operates in the energy retail market. The transaction also includes a 50% share in the capital of Umbria Energy S.p.A. The finalization of the transaction is conditional, upon authorization by the relevant Antitrust authorities. ● December 2025 - Eni signed a long-term LNG sale agreement with Turkish company Botas. This contract follows a 3-year deal signed by the two corporations in September 2025. ● December 2025 – Eni launched the Phase 2 of the Congo LNG project ahead of schedule. ● November 2025 - Eni, through its satellite company Azule Energy, inaugurated the NGC Gas Treatment Plant in Soyo, northern Angola. ● November 2025 – Plenitude started the construction of the "Tarsia Ovest" wind farm, located in the province of Cosenza, with a total capacity of about 13 MW. ● November 2025 - Eni signed an agreement to acquire from YPF a 50% stake in the OFF-5 block, offshore Uruguay, with an operator role. The completion of the agreement is subject to the approval of the Uruguayan authorities. ● November 2025 - Eni inaugurated the photovoltaic plant installed at the “Lycée de Tataouine” in southern Tunisia. The event marked the completion of the company’s program to install solar panels in public schools across the Tataouine region, involving 14 primary and secondary institutions. 26 Table of Contents ● November 2025 - Eni, through its subsidiary Nigeria Agip Exploration Limited (NAE), announced the acquisition from TotalEnergies EP Nigeria Limited of an additional 2.5% stake in the Production Sharing Contract (PSC) OML 118. ● November 2025 - Five agritech startups were awarded at the conclusion of the third edition of the Kenya Agribusiness Entrepreneurship Program (KAEP), the entrepreneurial development initiative promoted by Eni Natural Energies (ENE) Kenya and Joule, Eni’s business school, in collaboration with the E4Impact foundation. These five projects were selected for their potential in terms of scalability and impact and received a financial award of €10,000. ● November 2025 - Plenitude signed an agreement to acquire from Neoen, a leading renewable energy company, a portfolio of 52 operating assets, including 37 photovoltaic plants, 14 wind farms, and one operating battery storage facility, located throughout France. The completion of the agreement is subject to the approval of the competent authorities. ● November 2025 - Eni celebrated thirty years of listing on the New York Stock Exchange. ● November 2025 - Construction of the new biorefinery of Petronas, Enilive and Euglena in Pengerang, Johor, Malaysia has begun. ● November 2025 - Plenitude and Avis, the Association of Italian Blood Volunteers ODV, announced the signing of a framework agreement aimed at the possible development of joint initiatives for the energy efficiency of Avis offices throughout the country. ● November 2025 - Plenitude completed the sale of a 20% stake in the share capital of Plenitude S.p.A. to the Ares Alternative Credit funds, affiliated with Ares Management Corporation (NYSE: ARES). The stake corresponds to a value of €2 billion, based on an equity value of the company of €10 billion, and an enterprise value of over €12 billion. The transaction has been approved by the relevant authorities. ● November 2025 - Eni and YPF, Argentina's leading energy company, have signed a non-binding agreement with XRG, a company part of the ADNOC group, relating to the UAE's possible participation in the 12 MTPA liquefied natural gas (LNG) phase of the Argentina LNG (ARGLNG) upstream-midstream integrated project. ● November 2025 - Eni signed an Investment Agreement with Petronas to establish a new joint venture satellite company, NewCo, through the integration of their respective Upstream assets in Indonesia and Malaysia. The agreement creates a new entity that will manage 19 assets, of which 14 in Indonesia and 5 in Malaysia. ● October 2025 - Eni has been recognized for its commitment to reporting emissions, which have been rated "Gold Standard" for the highest levels of data quality by the Oil and Gas Methane Partnership 2.0 (OGMP 2.0). ● October 2025 - Eni and the Bioenergy Association for Sustainable Development signed a cooperation agreement for the preparation of a feasibility study aimed at the construction of biogas production units based on the treatment of animal and agricultural waste. ● October 2025 - Plenitude and Coesa, an Italian Energy Service Company (ESCo), signed an agreement to offer companies a service that involves the design and installation of photovoltaic systems to be included in the national WeCER Renewable Energy Community, developed by Coesa. ● October 2025 - Eni and the Argentina YPF signed the Final Technical Project Description (FTPD), a step towards the Final Investment Decision for the 12 MTPA integrated upstream-midstream Argentina LNG (ARGLNG) project intended to monetize the gas reserves of the Vaca Muerta basin. ● October 2025 – Started the authorization process for the transformation of the Priolo site. The proposed project includes a new biorefinery and a chemical recycling plant for plastics based on Versalis’ proprietary Hoop® technology. The new biorefinery will have a production capacity of 500 ktonnes/year. In addition to the Ecofining™ plant, the project includes a biogenic feedstock pre-treatment unit and a plant to produce hydrogen. Completion is scheduled by the end of 2028. The Versalis Hoop® plant will have a processing capacity of 40 ktonnes/year. 27 Table of Contents ● October 2025 - Eni and its partners CNPC, ENH, Kogas, and XRG reached the Final Investment Decision 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 the Rovuma basin, through a floating LNG facility with 3.6 MTPA production capacity. ● October 2025 - Eni signed a new exploration contract in Côte d'Ivoire 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. ● October 2025 - Plenitude signed with A.N.FI.R (Associazione Nazionale delle Finanziarie Regionali) a Framework Agreement for the construction of plants for renewable energy production. ● September 2025 - Versalis signed an agreement with Veritas, an Italian multi-utility, to promote the circular economy, mainly focusing on developing joint initiatives to valorize post-consumer and post-industrial plastics. ● September 2025 - GreenIT, the Italian joint venture between Plenitude and CDP Equity (CDP Group), obtained a funding of €370 mln for renewable energy projects, by the European Investment Bank and leading European financial institutions. ● 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 the Cape Three Points Block 4. ● September 2025 - Eni signed with Commonwealth Fusion Systems (CFS) a power offtake agreement worth more than $1 bln, expanding a longstanding strategic partnership between the companies to bring to industrial scale the magnetic fusion to produce power. ● September 2025 - Eni started the authorization process to convert selected units at the Sannazzaro de’ Burgondi (Pavia) refinery into a biorefinery. The project is intended to convert the existing Hydrocracker (HDC2) unit, using Ecofining™ technology and constructing a pre-treatment unit for waste and residues, used by Enilive to produce HVO biofuels. ● September 2025 - Eni Storage Systems, a joint venture between Eni and Fib, a Seri Industrial subsidiary, started operations to build a plant for the production of stationary lithium batteries as part of the reconversion plan of the Brindisi petrochemicals hub which has undergone shutdown. ● September 2025 - Eni finalized the sale of a 30% stake in the Baleine project in Côte d’Ivoire, to Vitol. The Baleine project is the country’s main offshore development and is owned by Eni (47.25%), Vitol (30%) and Petroci (22.75%). The transaction is in line with Eni's strategy of optimizing its upstream portfolio by accelerating the monetization of exploration discoveries through the divestment of equity stakes. ● September 2025 - Plenitude started operations at the 50 MW Solar Power Plant in Kazakhstan. The plant is a part of an innovative project led by Eni and KazMunayGas (KMG), the first large-scale of its kind, for the realization of a 247 MW Hybrid Power Plant which integrates solar, wind and gas power generation. ● September 2025 - Eni signed a three-year deal with Botas for the sale of total 1.5 bcm of LNG to Turkey. ● August 2025 - production started at the Agogo Integrated West Hub project, operated by the JV Azule Energy in block 15/06, offshore Angola. Agogo IWH involves the development of two fields, Agogo and Ndungu. ● August 2025 - LG-Eni BioRefining, the LG Chem and Enilive joint venture, started construction works for the South Korea’s first hydrotreated vegetable oil (HVO) and Sustainable Aviation Fuel (SAF) production plant in Seoul. The plant is scheduled for completion in 2027. ● August 2025 - Eni signed a Sale and Purchase Agreement (SPA) with Global Infrastructure Partners, a leading global infrastructure investor, affiliate of the BlackRock fund, relating to a stake of 49.99% in Eni CCUS Holding, which is expected to establish joint control of the counterparties over the post-close entity. The Eni’s subsidiary operates the Liverpool Bay and Bacton CCS projects in the UK, is committed to the L10-CCS project in the Netherlands and owns a pre-emptive right to acquire a 50% stake held by Eni in the Ravenna CCS project in Italy. Furthermore, it has access to several options within a broader platform of ongoing CCUS initiatives in the medium to long-term. ● August 2025 - The Nguya floating liquefied natural gas (FLNG) unit sailed away, and it is set to significantly boost LNG production as part of Phase 2 of the Congo LNG project in the Marine XII concession, offshore the Republic of Congo. ● July 2025 - Plenitude started the construction of Entrenúcleos, a new 200 MW photovoltaic project located in the province of Seville (Andalusia). ● July 2025 - Eni signed a new hydrocarbons contract with its partner Sonatrach for the exploration and development of the Zemoul El Kbar area. The contract, with a duration of 30 years, also 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. ● July 2025 - As part of the strategic partnership between Italy and the United Arab Emirates, Eni signed with Khazna Data Centers a memorandum to set up a Joint Venture for the development of an “AI Data Center Campus” with a total IT capacity of 500 MW at Eni’s hub of Ferrera Erbognone. 28 Table of Contents ● July 2025 - Eni signed a long-term liquefied natural gas (LNG) supply agreement with Venture Global, covering the purchase of 2 MTPA for 20 years from 2030. The agreement is Eni’s first long term LNG supply from the United States and represents a milestone in Eni’s strategy to expand and diversify its global LNG footprint, enhancing portfolio flexibility in order to reach its target of 20 MTPA of contracted LNG supply by 2030. ● July 2025 - Eni signed with the European Investment Bank (EIB) a €500 mln 15-year finance contract to support the conversion of Eni's Livorno refinery in Tuscany into a biorefinery. Eni's project involves the construction of new plants to produce hydrogenated biofuels at the Livorno refinery site, including a biogenic pre-treatment unit and a 500 ktonnes/year Ecofining™ plant. ● July 2025 - Versalis signed a Memorandum of Understanding (MoU) with Acea Ambiente covering initiatives in the field of recycling post-consumer and post-industrial plastics. The agreement foresees the assessment of chemical recycling solutions, including the proprietary Hoop® technology. ● June 2025 - Vår Energi announced first oil from the Balder X development, offshore Norway. ● June 2025 - Eni signed an agreement with YPF for the massive Argentina LNG (ARGLNG) project in the wake of the MoU signed the last April to define the milestones to reach a final investment decision to build gas production, treatment, transportation and liquefaction facilities, including installation of floating units, for a total capacity of 12 mmtonnes/year of LNG destined to international markets. ● June 2025 - Eni in collaboration with Advanced Micro Devices (AMD), Hewlett Packard Enterprise (HPE), and the CINECA Consortium, with the support of Plug and Play, launched the "HPC Call4Innovators" initiative, offering startups, SMEs, academic institutions, and research centers direct access to HPC6’s supercomputing resources. This initiative will allow participants to test their computational models and collaborate with the Eni experts to significantly accelerate the development of decarbonization technologies and promote innovative computational methodologies applied to the energy transition. ● June 2025 - Eni Congo launched the new Yasika logistics platform, a strategic infrastructure within the Congo LNG project. The platform, built to enhance the gas potential of the Marine XII permit, will support operations for the two floating liquefaction units: Tango FLNG (0.6 MTPA), which began production in December 2023, and Nguya FLNG (2.4 MTPA), scheduled to start up production by the end of 2025. ● June 2025 - Eni signed a framework agreement with Petronas to establish a jointly controlled venture to combine the two partners’ gas-rich assets of Indonesia and Malaysia, featuring two very complementary portfolios able to generate operational and financial synergies. In line with Eni’s satellite model of setting geographically focused, independent ventures, the new Company will be a financially self-sufficient entity which will develop the huge gas mineral potential of the combined portfolio to deliver in the medium term a sustainable production plateau of 500 kboe/d, targeting 50 TCF of low-risk exploration potential. ● June 2025 - Versalis, at the Mantua plant, started up the demonstration plant of Hoop® technology, for the chemical recycling of mixed plastic waste. This technology, complementary to mechanical recycling, allows the transformation of mixed plastic waste into raw material for the production of new plastic products. ● June 2025 - Eni signed an agreement with Ares Management Alternative Credit funds (“Ares”), affiliates of leading global alternative investment manager Ares Management Corporation (NYSE: ARES), for the sale of a 20% stake in the share capital of Plenitude, for a purchase price of approximately €2 bln, based on an equity value of the Company of €10 bln, corresponding to an enterprise value greater than €12 bln. The completion of the transaction is subject to the clearance by the competent authorities. ● June 2025 - Plenitude signed an agreement with Modine, a company specialized in thermal management systems and components, for the construction of a new solar power plant in Pocenia (Udine). ● June 2025 - Eni and BMW Italia signed a Letter of Intent (LOI) to develop joint initiatives aimed at supporting the energy transition of the road transport sector. ● June 2025 - Eni signed a Letter of Intent (LoI) with the Italian Agency for Development Cooperation (AICS) to create positive synergies and maximize the impact of the parties’ actions to improve the well-being of communities in Côte d'Ivoire. ● June 2025 - Eni launched the first vegetable oil extraction plant in the Republic of the Congo in Loudima. The plant has a capacity of 30 ktonnes/year of vegetable oil and its production will be destined to Enilive’s biorefineries, where it will be transformed into biofuel to help decarbonize transport sectors, as part of Eni’s sustainable mobility strategy. ● June 2025 - Plenitude started operations at the Northern block of its Renopool photovoltaic plant, located in the Extremadura region (Spain), with an installed capacity of 130 MW. ● June 2025 - Eni Next and Azimut Group signed a collaboration agreement, under which Azimut will launch a new European Long Term Investment Fund (ELTIF) of venture capital, leveraging also Eni Next’s consulting and expertise on technological developments in the energy sector. ● June 2025 - Eni was listed in the FTSE4Good Developed stock market index for the nineteenth consecutive year. This confirms Eni’s position among the top 5 in the Oil&Gas sector. ● June 2025 - Eni started the first export of vegetable oil from Côte d'Ivoire, produced from rubber tree residues, in line with the company's decarbonization strategy and the sustainable development of local agricultural supply chains. 29 Table of Contents ● May 2025 - Eni started gas production at the Merakes East field, in East Sepinggan block (Eni 85%, operator) in the Kutei basin, offshore Indonesia. ● May 2025 - Eni signed an agreement to enter into a period of exclusivity with GIP (Global Infrastructure Partners) an investor affiliated with BlackRock private equity, finalized to complete due diligence and negotiations related to a possible sale of an interest of 49.99% awarding joint control to the investor related to Eni CCUS Holding, Eni’s company which includes and operates the HyNet and Bacton CCS projects in the UK, L10 in the Netherlands and also future rights to acquire the Ravenna project, in Italy. According to the final agreement under negotiation, in addition to the initial acquisition of a 49.99% stake in Eni CCUS Holding, GIP will support funding the development of Eni’s ongoing CCUS projects. ● May 2025 - Plenitude signed an agreement with Marelli, an automotive industry component supplier company, for the construction of three photovoltaic plants and an Energy Community. The plants will be located at Marelli’s production sites in Italy (Potenza, L’Aquila and Turin) with a total installed capacity of 5.4 MW. ● May 2025 - started workover activities of the Sankofa East field in Ghana. The drilling operations are close to the John Agyekum Kufour FPSO, as part of the broader Sankofa field’s development plan. ● May 2025 - Eni Foundation and Eni Natural Energies (ENE) Angola signed two Memorandums of Understanding (MoU) with the Angolan Ministry of Health. The first MoU includes a new pediatric healthcare initiative focused on strengthening neonatal and pediatric intensive care services. The second MoU concerns the development of a digital interface to improve coordination between hospitals in Luanda. Both projects aim to improve the quality of healthcare and accessibility for patients across the country. ● April 2025 - Plenitude signed a 10-year Power Purchase Agreement with Autostrade per l'Italia for the sale of the entire output of a wind power plant owned by Plenitude in Basilicata (Italy) with a capacity of 16 MW. ● April 2025 - Eni and KKR closed the transaction contemplated by the investment agreement for the increase of KKR's stake in Enilive through the purchase of Enilive’s shares from Eni representing 5% of the share capital, for a consideration of approximately €601 million. Upon completion of the transaction, KKR owns an overall 30% stake of Enilive’s share capital, considering the transaction agreed in October 2024 providing an investment of 25% by KKR in Enilive with cash proceeds to Eni of about €2.97 bln. ● April 2025 – Eni signed a Memorandum of Understanding (MoU) with YPF, the energy company of the Republic of Argentina, to evaluate a large-scale upstream and midstream integrated gas development project, designed to develop the resources of the Vaca Muerta onshore gas field. The project includes two Floating LNG units of 6 MTPA each. ● April 2025 - Eni reached financial close with the UK Government’s Department of Energy Security and Net Zero (DESNZ) for the Liverpool Bay CCS project, where Eni is the operator of the CO2 transport and storage system (T&S) of the HyNet industrial Cluster. The financial close allows the Liverpool Bay CCS project to move into the construction phase, unlocking key investments in supply chain contracts, the majority of which will be spent locally. ● April 2025 - Eni’s jointly participated Azule Energy (Eni 50%) confirmed a discovery at the Capricornus 1-X well, in Namibia's Orange basin. Appraisal studies are ongoing. ● April 2025 – Eni launched FPSOs for the development of the Agogo fields, operated by Azule off the Angolan Coast, and Balder operated by Vår Energi in Norway. ● March 2025 - Saipem and Divento, a partnership between Copenhagen Infrastructure Partners (CIP, through the “flagship” fund Copenhagen Infrastructure V), GreenIT, a joint venture between Plenitude (a Company controlled by Eni) and CDP Equity (CDP Group), 7 Seas Wind Power and NiceTechnology, have signed a collaboration agreement involving the application of STAR 1, Saipem's proprietary technology for floating wind, in favour of the 7 Seas Med projects in Sicily and Ichnusa Wind Power in Sardinia. ● March 2025 - Eni and Petroci announced a significant increase in gas supply for Côte d'Ivoire’s power generation system. The gas produced, 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. Launched in December 2024, Phase 2 of the Baleine project marks another step forward in the company’s commitment to strengthening the country’s energy sector and industrial development. ● March 2025 - Eni’s 63% owned associate Vår Energi announced that production had begun from the Johan Castberg oilfield in the Barents Sea. The field, in which Vår Energi has a 30% non-operated stake, has a gross capacity of 220 kbbl/d. ● March 2025 - Versalis permanently closed the steam cracker at its Brindisi plant in line with the transformation plan. ● March 2025 - Eni and Saipem extended the collaboration agreement signed between the two companies in November 2023 aimed at the construction of new biorefineries, conversion of traditional refineries into biorefineries and, generally, the development of new initiatives by Eni in the field of industrial transformation. For significant business and portfolio developments that occurred from January 2025 to the beginning of March 2025 see also the Annual Report on Form 20-F 2024 filed to SEC on April 4, 2025. 30 Table of Contents BUSINESS OVERVIEW Exploration & Production Competitive trends in the industries where the Company operates In the Exploration & Production segment, Eni is facing competition from both international and state-owned oil companies for obtaining exploration and development rights and developing and applying new technologies to maximize hydrocarbon recovery. Because of the larger size of some other international oil companies, Eni may face a competitive disadvantage when bidding for large scale or capital intensive projects and it may be exposed to the risk of obtaining lower cost savings in a deflationary environment compared to its larger competitors given its potentially smaller market power with respect to suppliers, whereas in case of rising input costs due to a shortage of materials, labor and other productive factors Eni may experience higher pressure from its suppliers to raise the price of goods and services to the Company compared to Eni’s larger competitors. Due to those competitive pressures, Eni may fail to obtain new exploration and development acreage, to apply and develop new technologies and to control costs. Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as in LNG operations, in 33 countries, most notably Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Mexico, the United States, Kazakhstan, Algeria, Iraq, Indonesia, Ghana, Mozambique, Qatar, Côte d'Ivoire and the United Arab Emirates. In 2025, Eni average daily production amounted to 1,594 KBOE/d on an available-for-sale basis. Profit per barrel of oil equivalent was 7.80 $/bbl1 (compared to 3.69 $/bbl2 in 2024 and 8.58 $/bbl in 2023); the increase of this performance indicator in 2025 compared to 2024 was driven by an improved production mix due to an increasing contribution of more valuable barrels, the effects of divestments as well as lower impairment losses and exploration wells write-offs. As of December 31, 2025, Eni’s total proved reserves amounted to 6,885 mmBOE; proved reserves of subsidiaries totaled 4,830 mmBOE; Eni’s share of reserves of equity-accounted entities was 2,055 mmBOE. “Eni’s strategy and short-to-medium term targets in its Exploration & Production segment are disclosed in Item 5 – Business trends and Management’s expectations of operations.” Disclosure of reserves Overview The Company has adopted comprehensive classification criteria for the estimates of proved, proved developed and proved undeveloped oil&gas reserves in accordance with applicable U.S. Securities and Exchange Commission (SEC) regulations, as provided for in Regulation S-X, Rule 4-10. Proved oil&gas reserves are those quantities of liquids (including condensates and natural gas liquids) and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Oil and natural gas prices used in the estimate of proved reserves are obtained from the official survey published by S&P Global Energy, except when their calculation derives from existing contractual conditions. Prices are calculated as the unweighted arithmetic average of the first-day-of- the-month price for each month within the 12-month period prior to the end of the reporting period. Prices include consideration of changes in existing prices provided only by contractual arrangements. Engineering estimates of the Company’s oil&gas reserves are inherently uncertain. Although authoritative guidelines exist regarding engineering criteria that have to be met before estimated oil&gas reserves can be designated as “proved”, the accuracy of any reserves estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. Consequently, the estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revisions may be made to the initial booking of reserves due to analysis of new information. Proved reserves to which Eni is entitled under concession contracts are determined by applying Eni’s equity interest to total proved reserves of the contractual area, until expiration of the relevant mineral right. Eni’s proved reserves entitlements at PSAs are calculated so that the sale of production entitlements cover expenses incurred by the Group for field development (Cost Oil) and recognize a share of profit set contractually (Profit Oil). A similar scheme applies to service contracts. 1 Results of operations from oil and gas producing activities of consolidated subsidiaries, divided by actual sold production, in each case prepared in accordance with IFRS to meet ongoing U.S. reporting obligations under Topic 932. See the unaudited supplemental oil and gas information in “Item 18 – Notes to the Consolidated Financial Statements” for a calculation of results of operations from oil and gas producing activities. 31 Table of Contents Reserves governance Eni retains rigorous control over the process of booking proved reserves, through a centralized model of reserves governance. The Reserves Department of the Exploration & Production segment is in charge of: (i) ensuring the periodic certification process of proved reserves; (ii) updating the Company’s guidelines on reserves evaluation and classification and the internal procedures; and (iii) providing training of staff involved in the process of reserves estimation. Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which stated that those guidelines comply with the SEC rules2. D&M has also stated that the Company guidelines provide reasonable interpretation of facts and circumstances in line with generally accepted practices in the industry whenever SEC rules may be less precise. When participating in exploration and production activities operated by other entities, Eni estimates its share of proved reserves on the basis of the above guidelines, while for certain joint ventures and associates Eni relies on the annual certification of independent petroleum engineering companies. The process for estimating reserves, as described in the internal procedure, involves the following roles and responsibilities: (i) the business unit managers (geographic units) and Local Reserves Evaluators (LRE) are in charge with estimating and classifying gross reserves including assessing production profiles, capital expenditure, operating expenses and costs related to asset retirement obligations; (ii) the petroleum engineering department and the operations unit at the head office verify the production profiles of such properties where significant changes have occurred and operating expenses, respectively; (iii) geographic area managers verify the commercial conditions and the progress of the projects; (iv) the Planning and Control Department provides the economic evaluation of reserves; and (v) the Reserves Department, through the Headquarter Reserves Evaluators (HRE), provides independent reviews of fairness and correctness of classifications carried out by the above-mentioned units and aggregates worldwide reserves data. Eni’s Head of Reserves holds a Master's degree in Petroleum Engineering from the Polytechnic of Turin and 5-years Degree in Civil Hydraulic Engineering from the Alma Mater Studiorum - University of Bologna. He has more than 20 years of experience in the upstream industry and in reserves evaluation. Staff involved in the reserves evaluation process fulfils the professional qualifications requested by the role and complies with the required level of independence, objectivity and confidentiality in accordance with professional ethics. Reserves Evaluators qualifications comply with international standards defined by the Society of Petroleum Engineers. Reserves independent evaluation Eni has its proved reserves audited on a rotational basis by independent oil engineering companies. The description of qualifications of the persons primarily responsible for the reserves audit is included in the third-party audit report. In the preparation of their reports, independent evaluators rely upon information furnished by Eni, without independent verification, with respect to property interests, production, current costs of operations and development, sales agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies, technical analysis relevant to field performance, development plans, future capital and operating costs. In order to calculate the net present value of Eni’s equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements and other pertinent information are provided by Eni to third-party evaluators. The volumes and monetary values of the reserves of certain joint venture and affiliated companies are certified on their behalf in a similar manner by independent petroleum engineering companies and provided to Eni3. In 20254, Ryder Scott Company and Sproule, for consolidated subsidiaries, and DeGolyer and MacNaughton, for equity accounted entities, provided an independent evaluation of approximately 36%5 of Eni’s total proved reserves at December 31, 2025, confirming, as in previous years, the reasonableness of Eni internal evaluation. In the 2023-2025 three-year period, 82% of Eni total proved reserves were subject to an independent evaluation. 2 See “Item 19 – Exhibits” in the Annual Report on Form 20-F 2009. 3 In 2025 Azule Energy and Vår Energi. 4 See "Item 19 - Exhibits". 5 Includes Azule Energy and Vår Energi for which Eni received a Third Party Letter. 32 Table of Contents Summary of proved oil and gas reserves The tables below provide a summary of proved oil and gas reserves of the Group companies and its equity-accounted entities by geographic area for the three years ended December 31, 2025, 2024 and 2023. The break-down of proved reserves by geographic area complies with disclosure criteria as regulated by U.S. Securities and Exchange Commission (SEC) Regulation S-K, Item 1202. HYDROCARBONS (mmBOE) Italy Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Total reserves Consolidated subsidiaries Dec. 31, 2025 320 15 1,483 570 824 1,480 127 11 4,830 developed 223 9 829 412 789 449 91 7 2,809 undeveloped 97 6 654 158 35 1,031 36 4 2,021 Dec. 31, 2024 (a) 368 10 1,479 638 876 881 145 36 4,433 developed 262 10 805 418 823 385 92 5 2,800 undeveloped 106 674 220 53 496 53 31 1,633 Dec. 31, 2023 (b) 374 60 1,658 809 933 733 238 37 4,842 developed 261 56 935 482 872 379 184 11 3,180 undeveloped 113 4 723 327 61 354 54 26 1,662 Equity-accounted entities Dec. 31, 2025 617 53 781 381 223 2,055 developed 427 53 346 223 1,049 undeveloped 190 435 381 1,006 Dec. 31, 2024 (a) 572 50 819 379 244 2,064 developed 311 50 305 244 910 undeveloped 261 514 379 1,154 Dec. 31, 2023 (b) 425 8 494 378 267 1,572 developed 235 8 305 267 815 undeveloped 190 189 378 757 Consolidated subsidiaries and equity accounted entities Dec. 31, 2025 320 632 1,536 1,351 824 1,861 350 11 6,885 developed 223 436 882 758 789 449 314 7 3,858 undeveloped 97 196 654 593 35 1,412 36 4 3,027 Dec. 31, 2024 (a) 368 582 1,529 1,457 876 1,260 389 36 6,497 developed 262 321 855 723 823 385 336 5 3,710 undeveloped 106 261 674 734 53 875 53 31 2,787 Dec. 31, 2023 (b) 374 485 1,666 1,303 933 1,111 505 37 6,414 developed 261 291 943 787 872 379 451 11 3,995 undeveloped 113 194 723 516 61 732 54 26 2,419 (a) Reserves volumes of the Rest of Europe area for 2024 were affected by the business combination with Ithaca Energy where the reserves divested in the consolidated subsidiary Eni UK were offset by the acquisition of an interest in the reserves of the equity-accounted entity resulting from the combination. (b) Effective January 1, 2023, Eni has updated the conversion rate of gas produced to 5,232 cubic feet of gas equals to 1 barrel of oil (it was 5,263 cubic feet of gas per barrel in previous reporting period). The effect of this update on the change in the initial reserves balance as of January 1, 2023 amounted to 21 mmBOE. 33 Table of Contents LIQUIDS (mmBBL) Italy Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Total reserves Consolidated subsidiaries Dec. 31, 2025 197 517 252 556 713 111 2,346 developed 123 339 202 523 274 80 1,541 undeveloped 74 178 50 33 439 31 805 Dec. 31, 2024 (a) 213 458 268 591 578 127 2,235 developed 129 291 187 539 233 81 1,460 undeveloped 84 167 81 52 345 46 775 Dec. 31, 2023 211 27 523 334 637 485 213 2,430 developed 136 24 326 225 576 240 163 1,690 undeveloped 75 3 197 109 61 245 50 740 Equity-accounted entities Dec. 31, 2025 381 5 192 111 20 709 developed 295 5 112 20 432 undeveloped 86 80 111 277 Dec. 31, 2024 (a) 391 8 226 110 23 758 developed 207 8 103 23 341 undeveloped 184 123 110 417 Dec. 31, 2023 326 6 207 110 26 675 developed 167 6 107 26 306 undeveloped 159 100 110 369 Consolidated subsidiaries and equity accounted entities Dec. 31, 2025 197 381 522 444 556 824 131 3,055 developed 123 295 344 314 523 274 100 1,973 undeveloped 74 86 178 130 33 550 31 1,082 Dec. 31, 2024 (a) 213 391 466 494 591 688 150 2,993 developed 129 207 299 290 539 233 104 1,801 undeveloped 84 184 167 204 52 455 46 1,192 Dec. 31, 2023 211 353 529 541 637 595 239 3,105 developed 136 191 332 332 576 240 189 1,996 undeveloped 75 162 197 209 61 355 50 1,109 (a) Reserves volumes of the Rest of Europe area for 2024 were affected by the business combination with Ithaca Energy where the reserves divested in the consolidated subsidiary Eni UK were offset by the acquisition of an interest in the reserves of the equity-accounted entity resulting from the combination. 34 Table of Contents NATURAL GAS (BCF) Italy Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Total reserves Consolidated subsidiaries Dec. 31, 2025 651 81 5,052 1,664 1,399 4,009 80 62 12,998 developed 524 45 2,562 1,099 1,396 920 56 37 6,639 undeveloped 127 36 2,490 565 3 3,089 24 25 6,359 Dec. 31, 2024 (a) 817 54 5,338 1,931 1,489 1,583 94 190 11,496 developed 693 52 2,692 1,206 1,486 799 56 23 7,007 undeveloped 124 2 2,646 725 3 784 38 167 4,489 Dec. 31, 2023 859 174 5,935 2,479 1,546 1,303 131 192 12,619 developed 653 167 3,181 1,350 1,546 725 107 58 7,787 undeveloped 206 7 2,754 1,129 578 24 134 4,832 Equity-accounted entities Dec. 31, 2025 1,229 249 3,077 1,418 1,063 7,036 developed 692 249 1,222 1,063 3,226 undeveloped 537 1,855 1,418 3,810 Dec. 31, 2024 (a) 939 222 3,103 1,411 1,159 6,834 developed 545 222 1,054 1,159 2,980 undeveloped 394 2,049 1,411 3,854 Dec. 31, 2023 515 14 1,501 1,406 1,260 4,696 developed 359 14 1,036 1,260 2,669 undeveloped 156 465 1,406 2,027 Consolidated subsidiaries and equity accounted entities Dec. 31, 2025 651 1,310 5,301 4,741 1,399 5,427 1,143 62 20,034 developed 524 737 2,811 2,321 1,396 920 1,119 37 9,865 undeveloped 127 573 2,490 2,420 3 4,507 24 25 10,169 Dec. 31, 2024 (a) 817 993 5,560 5,034 1,489 2,994 1,253 190 18,330 developed 693 597 2,914 2,260 1,486 799 1,215 23 9,987 undeveloped 124 396 2,646 2,774 3 2,195 38 167 8,343 Dec. 31, 2023 859 689 5,949 3,980 1,546 2,709 1,391 192 17,315 developed 653 526 3,195 2,386 1,546 725 1,367 58 10,456 undeveloped 206 163 2,754 1,594 1,984 24 134 6,859 (a) Reserves volumes of the Rest of Europe area for 2024 were affected by the business combination with Ithaca Energy where the reserves divested in the consolidated subsidiary Eni UK were offset by the acquisition of an interest in the reserves of the equity-accounted entity resulting from the combination. Proved reserves of natural gas liquids are immaterial to the Group operations. Volumes of oil and natural gas applicable to long- term supply agreements with foreign governments in mineral assets where Eni is operator were marginal as of December 31, 2025 (were marginal as of December 31, 2024 and amounted to 2 mmBOE as of December 31, 2023). Said volumes are not included in reserves volumes shown in the table herein. Subsidiaries Equity-accounted entities (mmBOE) 2025 2024 2023 2025 2024 2023 Revisions of previous estimates 305 323 303 82 83 9 Improved recovery 33 1 Extensions and discoveries 581 38 105 52 329 Purchases of minerals-in-place 7 89 44 29 230 2 Sales of minerals-in-place (70) (381) (58) (4) (1) Total additions to proved reserves 856 70 394 163 638 10 Production for the year (a) (459) (479) (485) (172) (146) (119) (a) The difference compared to production sold of 566 mmBOE (565 mmboe in 2024 and 546 mmboe in 2023) reflected hydrocarbons volumes of 65 mmBOE consumed in operations, changes in inventories and other factors (60 mmBOE in 2024 and 58.2 mmBOE in 2023). 35 Table of Contents Subsidiaries and equity-accounted entities (%) 2025 2024 2023 Proved reserves replacement ratio of subsidiaries and equity-accounted entities, all sources 162 113 67 Proved reserves replacement ratio of subsidiaries and equity-accounted entities, organic 167 124 69 Eni’s proved reserves as of December 31, 2025 totaled 6,885 mmBOE (liquids 3,055 mmBBL; natural gas 20,034 BCF). Eni’s proved reserves reported an increase from December 31, 2024 (up by 388 mmBOE, or approximately 6% from 2024) due to progress made in the year in exploring and developing new reserves and property acquisitions net of property sales. Portfolio activities provided net negative additions of 34 mmBOE and comprised: (i) the sale of a 30% stake in the Baleine project in Côte d’Ivoire and the disposal of an asset in Congo (negative for 70 mmBOE); (ii) assets acquisition in Norway (via Vår Energi) and in the United Kingdom (through Ithaca Energy) as well as additional interest in Touat in Algeria and in Bonga in Nigeria (overall positive for 36 mmBOE). All sources additions to proved reserves booked in 2025 were 1,019 mmBOE; of which 856 mmBOE came from Eni’s subsidiaries, while 163 mmBOE from Eni’s equity-accounted entities. The net effect of price changes was a negative 12 mmBOE in 2025 (of which a net positive revision of 9 mmBOE recorded at Eni’s subsidiaries and a net negative revision of 21 mmBOE recorded at Eni’s equity-accounted entities) due to a lower Brent crude oil reference price used in the reserve estimation process of 70 $/barrel in 2025, compared to 81 $/barrel used in 2024. This price change led to the removal of reserves which have become uneconomical in the 2025 scenario (negative revision of 51 mmBOE) and net lower reserves entitlements under PSA contracts (positive revision of 39 mmBOE). The methods (or technologies) used in Eni’s proved reserves assessment in 2024 depend on stage of development, quality and completeness of data, and production history availability. The methods include volumetric estimates, analogies, reservoir modelling, decline curve analysis or a combination of such methods. The data considered for these analyses are obtained from a combination of reliable technologies that produce consistent and repeatable results including well or field measurements (i.e. logs, core samples, pressure information, fluid samples, production test data and performance data) and indirect measurements (i.e. seismic data). However, for each reservoir assessment the most suitable combination of technologies and methods is applied providing a high degree of confidence in establishing reliable reserves estimates. The all sources reserves replacement ratio reported by Eni’s subsidiaries and equity-accounted entities was 162% in 2025 (113% in 2024 and 67% in 2023). The organic reserves replacement ratio was 167% in 2025 (124% in 2024 and 69% in 2023) which excluded sales and purchases of minerals-in-place. The all sources reserve replacement ratio during the three-year period ended December 31, 2025, which included a net decrease of 113 mmBOE related to sales and purchases, was 115%. The all sources reserves replacement ratio was calculated by dividing additions to proved reserves including sales and purchases of mineral-in-place by total production, each as derived from the tables of changes in proved reserves prepared in accordance with FASB Extractive Activities – Oil & Gas (Topic 932) (see the supplemental oil and gas information in “Item 18 – Consolidated Financial Statements”). The reserves replacement ratio is a measure used by management to assess the extent to which produced reserves in the year are replaced by booked reserves total additions. Management considers the reserve replacement ratio to be an important indicator of the Company’s ability to sustain its growth prospects. However, this ratio measures past performances and is not an indicator of future production because the ultimate recovery of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructures, reservoir performance, application of new technologies to improve the recovery factor as well as changes in oil&gas prices, political risks and geological and environmental risks. See “Item 3 – The Group is exposed to significant operational and economic risks associated with the exploration and production of crude oil and natural gas – Uncertainties in estimates of oil and natural gas reserves”. The average reserves life index of Eni’s proved reserves was 10.9 years as of December 31, 2025, which included reserves of both subsidiaries and equity-accounted entities. 36 Table of Contents Eni’s subsidiaries Eni’s subsidiaries added 856 mmBOE of proved oil and gas reserves in 2025. Additions comprised an increase of 323 mmBBL of liquids and of 2,797 BCF of natural gas. The breakdown of total additions to proved reserves was the following: (i) new discoveries and extensions of 581 mmBOE mainly as a result of the progression of projects in the Kutei basin in Indonesia and in Sarb field in the United Arab Emirates; (ii) revisions of previous estimates were positive for 305 mmBOE. The main positive revisions were related to the licence renewals in Sinai Area in Egypt and in Zek Area in Algeria and the ongoing development activities in Baleine field in Côte d'Ivoire and the Lower Zakum field in the United Arab Emirates. The negative revisions were reported in Blacktip field in Australia and in the Adriatic Sea and offshore Sicily in Italy. Revisions also included net positive price effects of 9 mmBOE; (iii) improved recovery of 33 mmBOE were reported in Iraq and Côte d'Ivoire; (iv) purchase of minerals-in-place of 7 mmBOE and mainly related to increase of equity interest in the Bonga field in Nigeria (Eni’s interest from 12.5% to 15%); and (v) sales of minerals-in-place of 70 mmBOE mainly due to the sale of the sale of 30% stake in the Baleine project in Côte d'Ivoire and of an asset in Congo. Further information and explanations of significant changes with respect to each line item of the movements in net proved reserves are provided in “Item 18 – Notes to the Consolidated Financial Statement - Supplemental oil and gas information”. Eni’s share of equity-accounted entities Eni’s share of equity-accounted entities added 163 mmBOE of proved oil and gas reserves in 2025. Additions comprised an increase of 46 mmBBL of liquids and of 602 BCF of natural gas. The breakdown of total additions to proved reserves is the following: (i) new discoveries and extensions of 52 mmBOE related to booking of reserves at the Vår Energi in Norway, Ithaca Energy in the United Kingdom and Azule Energy in Angola; (ii) revisions of previous estimates were positive for 82 mmBOE and mainly related to increase in Norway (through Vår Energi) and in Coral North and South in Mozambique. Revisions also included net negative price effects of 21 mmBOE; (iii) purchase of minerals-in-place of 29 mmBOE related to the Vår Energi assets in Norway, Ithaca Energy in the United Kingdom and the acquisition of additional stake in Touat field in Algeria. Further information and explanations of significant changes with respect to each line item of the movements in net proved reserves are provided in “Item 18 – Notes to the Consolidated Financial Statement - Supplemental oil and gas information”. Proved undeveloped reserves Proved undeveloped reserves as of December 31, 2025 totaled 3,027 mmBOE. At year-end, proved undeveloped reserves of liquids amounted to 1,082 mmBBL and of natural gas amounted to 10,169 BCF, mainly concentrated in Africa and Asia. Proved undeveloped reserves of consolidated subsidiaries amounted to 805 mmBBL of liquids and 6,359 BCF of natural gas. The table below provide a summary of changes in total proved undeveloped reserves for 2025. Subsidiaries and equity-accounted entities (mmBOE) 2025 Proved undeveloped reserves as of December 31, 2024 2,787 Transfers to proved developed reserves (370) Extensions and discoveries 585 Revisions of previous estimates 23 Improved recovery 26 Portfolio (24) Proved undeveloped reserves as of December 31, 2025 3,027 During 2025, Eni matured 370 mmBOE of proved undeveloped reserves to proved developed reserves due to progress in development activities, production start-ups and project revisions. The main reclassifications to proved developed reserves related to the fields/projects in the following countries: Norway (through Vår Energi), the United Arab Emirates and Azule Energy in Angola. For further information, please see the additional information on Oil & Gas producing activities required by the SEC in the “Item 18 - Notes to the consolidated financial statements”. In 2025, capital expenditure amounted to approximately €10 billion to progress the development of PUDs. Reserves that remain proved undeveloped for five or more years are a result of several factors that affect the timing of the projects development and execution, such as the complexity of development project in adverse and remote locations, physical limitations of infrastructures or plant capacity and contractual limitations that establish production levels. The proved undeveloped reserves that have remained undeveloped for five years or more at the balance sheet date amounted to 0.75 BBOE, decreasing from 2024, and are mainly related to the following projects where executions and developments activities are in progress: (i) certain Libyan gas fields (0.45 BBOE) where production start-ups are planned according to the delivery obligations set forth in a long-term gas supply agreement currently in force; (ii) certain fields in the United Arab Emirates (0.15 BBOE); and (iii) other fields in Italy and Iraq (0.15 BBOE). See also our discussion under the “Risk factors” section about risks associated with oil and gas development projects. 37 Table of Contents Eni remains strongly committed to put these projects into production in the coming years. The length of the development period depends on a range of external factors, such as for example the type of development, the location and physical operating environment of the field or the absence of infrastructure, considering that the majority of our projects are infrastructure-driven, and not a function of internal factors, such as an insufficient devotion of resources by Eni or a diminished commitment on the part of Eni to complete the project. Delivery commitments Eni, through consolidated subsidiaries and equity-accounted entities, sells crude oil and natural gas from its producing operations under a variety of contractual obligations. Some of these contracts, mostly relating to natural gas, specify the delivery of fixed and determinable quantities. Eni is contractually committed under existing contracts or agreements to deliver in the next three years mainly natural gas to third parties for a total of approximately 624 mmBOE from producing assets located mainly in Algeria, Australia, Egypt, Ghana, Indonesia, Kazakhstan, Libya, Mozambique, Nigeria, Norway and Venezuela. The sales contracts contain a mix of fixed and variable pricing formulas that are generally indexed to the market price for crude oil, natural gas or other petroleum products. Management believes it can satisfy these contracts from quantities available mainly from production of the Company's proved developed reserves. Production is expected to fully account of delivery commitments. Eni has met all contractual delivery commitments as of December 31, 2025. Oil and gas production, production prices and production costs The matters regarding future production, additions to reserves and related production costs and estimated reserves discussed below and elsewhere herein are forward-looking statements that involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties relating to future production and additions to reserves include political developments affecting the award of exploration or production interests or world supply and prices for oil and natural gas, or changes in the underlying economics of certain of Eni’s important hydrocarbons projects. Such risks and uncertainties relating to future production costs include delays or unexpected costs incurred in Eni’s production operations. In 2025, oil and natural gas production available for sale averaged 1,594 KBOE/d (1,572 KBOE/d in 2024). Excellent project development performance was delivered in production start-ups and ramp-ups in Norway, Côte d'Ivoire, Mexico, Congo, Angola, Indonesia and Ghana. This was supplemented by excellent base business regularity. Offsetting these effects were mature fields declines and tail asset divestments closed in 2024 in Nigeria, Alaska, and Congo. Liquids production (839 KBBL/d) increased by 56 KBBL/d, or approximately 7% from the full year of 2024. The organic growth in Côte d'Ivoire due to the start of Baleine Phase 2, Mexico, Angola and Norway was partly offset by divestments and mature fields declines. Natural gas production (3,951 mmCF/d) decreased by 181 mmCF/d, or approximately 4% compared to the full year of 2024. The divestments and mature fields decline were partly offset by organic growth in Congo (Marine XII) and Indonesia (Merakes East) as well as at our satellites in Angola/Norway. Sales volumes of oil and gas production were 566 mmBOE. The 16 mmBOE difference over production on available-for-sale basis (582 mmBOE in 2025) reflected mainly changes in inventory and other factors. 38 Table of Contents The tables below provide Eni subsidiaries and its equity-accounted entities’ production (annual volumes and daily averages), by final product marketed of liquids and natural gas by country and geographical area of each of the last three fiscal years. Average daily production available for sale (a) 2025 (b) 2024 2023 (c) Liquids Natural gas Hydrocarbons Liquids Natural gas Hydrocarbons Liquids Natural gas Hydrocarbons (KBBL/d) (mmCF/d) (KBOE/d) (KBBL/d) (mmCF/d) (KBOE/d) (KBBL/d) (mmCF/d) (KBOE/d) Eni consolidated subsidiaries Italy 26 180 60 27 166 59 29 178 63 Rest of Europe 1 62 13 16 181 50 18 98 37 Netherlands 1 60 12 1 61 12 United Kingdom 2 1 15 120 38 18 98 37 North Africa 174 1,626 485 177 1,900 540 190 2,039 581 Algeria 57 232 101 56 253 104 62 249 110 Egypt 62 863 227 59 1,071 264 67 1,242 305 Libya 54 525 155 60 568 169 59 540 162 Tunisia 1 6 2 2 8 3 2 8 4 Sub-Saharan Africa 108 376 180 86 342 152 84 329 147 Congo 24 158 55 26 149 55 36 106 56 Côte d'Ivoire 39 38 47 17 12 20 4 1 4 Ghana 13 103 32 12 77 26 14 76 29 Nigeria 32 77 46 31 104 51 30 146 58 Kazakhstan 113 203 152 109 210 149 114 216 154 Rest of Asia 94 453 181 93 415 173 85 354 153 China 1 1 Indonesia 1 386 75 1 411 80 1 343 66 Iraq 31 31 28 28 23 23 Timor Leste 1 2 1 7 2 Turkmenistan 2 55 13 6 6 6 6 United Arab Emirates 60 11 62 58 2 58 54 4 55 Americas 62 33 68 59 30 64 68 45 76 Mexico 45 14 47 25 12 27 22 13 24 United States 17 19 21 34 18 37 46 32 52 Australia and Oceania 21 4 13 2 36 7 Australia 21 4 13 2 36 7 578 2,954 1,143 567 3,257 1,189 588 3,295 1,218 Eni share of equity-accounted entities Algeria 70 14 55 11 Angola 79 99 97 86 76 101 85 74 100 Mozambique 1 113 23 1 107 21 1 88 18 Norway 146 331 209 114 329 176 87 244 133 Tunisia 2 2 2 2 2 2 United Kingdom 25 95 43 6 24 11 Venezuela 8 289 63 7 284 61 5 279 58 261 997 451 216 875 383 180 685 311 Total 839 3,951 1,594 783 4,132 1,572 768 3,980 1,529 (a) It excludes production volumes of hydrocarbons consumed in operations. Said volumes were 134, 135 and 127 KBOE/d in 2025, 2024 and 2023, respectively. (b) Includes approximately 10 KBOE/d of production related to certain sanctioned joint‑venture partners. (c) Effective January 1, 2023, the conversion rate of natural gas from cubic feet to boe has been updated to 1 barrel of oil equivalent = 5,232 cubic feet of gas (it was 1 barrel of oil 5,263 cubic feet of gas). The effect of this update on production was 5 KBOE/d in the full year 2023. 39 Table of Contents Annual production available for sale (a) 2025 (b) 2024 2023 (c) Liquids Natural gas Hydrocarbons Liquids Natural gas Hydrocarbons Liquids Natural gas Hydrocarbons (mmBBL) (BCF) (mmBOE) (mmBBL) (BCF) (mmBOE) (mmBBL) (BCF) (mmBOE) Eni consolidated subsidiaries Italy 9 66 22 10 61 21 10 65 23 Rest of Europe 23 4 6 66 19 7 36 13 Netherlands 22 4 22 5 United Kingdom 1 6 44 14 7 36 13 North Africa 64 593 177 65 695 198 69 744 211 Algeria 21 85 37 20 92 38 23 91 40 Egypt 23 315 83 22 392 97 24 453 111 Libya 20 191 56 22 208 62 21 197 59 Tunisia 2 1 1 3 1 1 3 1 Sub-Saharan Africa 39 137 65 32 125 56 31 120 54 Congo 9 57 20 10 54 20 13 39 20 Côte d'Ivoire 14 14 17 6 5 7 2 2 Ghana 5 38 11 4 28 10 5 28 11 Nigeria 11 28 17 12 38 19 11 53 21 Kazakhstan 41 74 56 39 77 54 41 79 56 Rest of Asia 35 165 66 34 152 63 31 129 56 China Indonesia 1 141 27 1 150 29 125 24 Iraq 11 11 10 10 9 9 Timor Leste 1 1 3 1 Turkmenistan 1 20 5 2 2 2 2 United Arab Emirates 22 4 23 21 1 21 20 1 20 Americas 23 12 25 21 11 24 25 17 28 Mexico 16 5 17 9 4 10 8 5 9 United States 7 7 8 12 7 14 17 12 19 Australia and Oceania 8 2 5 1 13 3 Australia 8 2 5 1 13 3 211 1,078 417 207 1,192 436 214 1,203 444 Eni share of equity-accounted entities Algeria 25 5 20 4 Angola 29 36 36 31 28 37 31 27 36 Mozambique 41 8 39 8 32 7 Norway 53 121 76 42 120 64 32 89 49 Tunisia 1 1 1 1 1 1 United Kingdom 9 35 16 2 9 4 Venezuela 3 106 23 3 104 22 2 102 21 95 364 165 79 320 140 66 250 114 Total 306 1,442 582 286 1,512 576 280 1,453 558 (a) It excludes production volumes of hydrocarbons consumed in operations. Said volumes were 48.8, 49.3 and 46.2 mmBOE in 2025, 2024 and 2023, respectively. (b) Includes approximately 4 mmBOE of production related to certain sanctioned joint‑venture partners. (c) Effective January 1, 2023, the conversion rate of natural gas from cubic feet to boe has been updated to 1 barrel of oil = 5,232 cubic feet of gas (it was 1 barrel of oil = 5,263 cubic feet of gas). The effect of this update on production expressed in boe was approximately 2 mmboe for the full year of 2024. 40 Table of Contents Volumes of oil and natural gas purchased under long-term supply contracts with foreign governments or similar entities in properties where Eni acts as producer were marginal in 2025 (17 KBOE/d and 33 KBOE/d in 2024 and 2023, respectively). The tables below provide Eni subsidiaries and its equity-accounted entities’ average sales prices per unit of liquids and natural gas by geographical area for each of the last three fiscal years. In addition, Eni subsidiaries and its equity-accounted entities’ average production cost per unit of production are provided. ($) 2023 Consolidated subsidiaries Italy Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Total Oil and condensates, per BBL 67.76 72.77 72.10 81.79 72.71 80.19 75.30 54.02 74.87 Natural gas, per KCF 13.67 14.44 6.93 5.36 0.74 10.38 3.22 4.16 7.28 Total hydrocarbons, per BOE 69.80 74.31 48.60 60.51 54.01 69.03 68.89 22.11 56.23 Average production cost, per BOE 16.36 16.21 4.86 13.21 5.12 5.90 18.22 10.68 7.84 Equity-accounted entities Oil and condensates, per BBL 79.33 18.00 75.26 67.62 76.60 Natural gas, per KCF 20.53 9.69 11.94 5.22 12.18 Total hydrocarbons, per BOE 88.95 19.31 72.12 30.76 71.32 Average production cost, per BOE 12.46 10.09 13.48 1.00 10.70 2024 Consolidated subsidiaries Oil and condensates, per BBL 67.40 75.00 71.00 78.66 72.71 76.97 73.73 73.61 Natural gas, per KCF 11.73 10.20 6.78 5.75 0.89 11.09 3.20 4.38 7.24 Total hydrocarbons, per BOE 64.18 59.88 47.98 59.22 54.17 68.33 68.71 22.95 55.42 Average production cost, per BOE 17.67 19.22 5.31 12.02 5.58 6.73 18.49 29.33 8.37 Equity-accounted entities Oil and condensates, per BBL 76.72 20.98 74.77 68.12 75.30 Natural gas, per KCF 12.99 7.45 9.95 5.30 9.48 Total hydrocarbons, per BOE 73.54 37.09 68.67 32.30 64.15 Average production cost, per BOE 11.23 7.81 15.03 1.10 10.71 2025 Consolidated subsidiaries Oil and condensates, per BBL 57.73 70.41 60.94 68.24 62.14 66.41 62.90 54.01 63.51 Natural gas, per KCF 13.35 12.21 6.79 6.78 1.04 9.59 3.75 4.32 7.24 Total hydrocarbons, per BOE 64.73 64.58 45.12 56.04 47.27 59.61 58.90 23.22 51.36 Average production cost, per BOE 19.39 23.99 6.54 10.63 4.70 7.01 11.71 16.96 8.23 Equity-accounted entities Oil and condensates, per BBL 66.80 34.60 65.20 56.91 65.76 Natural gas, per KCF 13.00 6.70 9.98 5.42 9.67 Total hydrocarbons, per BOE 67.21 34.99 61.00 31.96 59.40 Average production cost, per BOE 10.71 7.18 17.42 1.20 11.03 Development well activity In 2025, a total of 303 development wells were drilled (79.1 of which represented Eni’s share) as compared to 217 development wells drilled in 2024 (57.3 of which represented Eni’s share) and 165 development wells drilled in 2023 (83.6 of which represented Eni’s share). The drilling of 184 development wells (36.5 of which represented Eni’s share) is currently underway. 41 Table of Contents The table below summarizes the number of the Company’s net interest in productive and dry development wells completed in each of the past three years and the status of the Company’s development wells in the process of being drilled as of December 31, 2025. A dry well is one found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. Net wells completed Wells in progress at 31 Dec. (units) 2025 2024 2023 2025 Productive Dry Productive Dry Productive Dry Gross Net Italy 1.2 1.0 1.0 0.5 Rest of Europe 19.3 3.8 4.8 15.0 2.4 North Africa 23.8 21.3 0.5 39.4 14.0 4.9 Sub-Saharan Africa 8.7 0.1 9.2 0.5 5.6 61.0 11.9 Kazakhstan 1.8 1.2 2.0 2.0 0.6 Rest of Asia 18.4 13.4 22.9 90.0 16.2 Americas 6.0 6.2 6.9 1.0 Australia and Oceania 1.0 1.0 Total including equity-accounted entities 79.0 0.1 56.3 1.0 83.6 184.0 36.5 Exploration well activity In 2025, a total of 42 new exploratory wells were drilled (16.8 of which represented Eni’s share), as compared to 37 exploratory wells drilled in 2024 (15.0 of which represented Eni’s share) and 39 exploratory wells drilled in 2023 (21.6 of which represented Eni’s share). The overall commercial success rate was 37.9% (42.2% net to Eni) as compared to 12.5% (12.8% net to Eni) and 34.5% (38% net to Eni) in 2024 and 2023, respectively. The following table summarizes the Company’s net interests in productive and dry exploratory wells completed in each of the last three fiscal years and the number of exploratory wells in the process of being drilled and evaluated as of December 31, 2025. A dry well is one found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. For further information on the ageing of suspended wells see “Item 18 - Note 12 to the Consolidated Financial Statements.” Net wells completed Wells in progress at Dec. 31 (units) 2025 2024 2023 2025 Productive Dry Productive Dry Productive Dry Gross Net Italy 1.0 0.6 Rest of Europe 0.9 2.3 1.9 0.1 0.4 70.0 18.6 North Africa 0.8 2.3 1.5 4.6 5.0 6.2 16.0 10.7 Sub-Saharan Africa 0.2 0.1 0.3 0.9 43.0 21.0 Kazakhstan 1.0 Rest of Asia 1.8 3.5 0.9 1.3 9.0 6.5 Americas 1.4 7.0 4.6 Australia and Oceania 1.0 0.3 Total including equity-accounted entities 3.5 4.8 1.6 11.0 6.3 10.2 147.0 62.3 Oil and gas properties, operations and acreage In 2025, Eni performed its operations in thirty-three countries located in five continents. As of December 31, 2025, Eni’s mineral right portfolio consisted of 868 exclusive or shared rights of exploration and development oil and gas activities. Total acreage amounts to 205,562 square kilometers net to Eni (total acreage was 211,347 square kilometers net to Eni as of December 31, 2024). Developed acreage was 25,712 square kilometers and undeveloped acreage was 179,850 square kilometers net to Eni. In 2025 new leases were purchased or awarded in Algeria, Egypt, Italy, Côte d'Ivoire, Norway and Tunisia for a total increase in acreage of approximately 21,200 square kilometers. Relinquishment for the year related mainly to China, Congo, Cyprus, Egypt, Mozambique, Norway, Timor Leste, the United Arab Emirates and Vietnam covering an acreage of approximately 21,250 square kilometers. Interest increases were reported mainly in Indonesia, Italy, Tunisia and the United Kingdom for a total acreage of approximately 350 square kilometers. Partial relinquishment was reported mainly in Côte d'Ivoire, Egypt, Indonesia, Italy, Timor Leste, the United Arab Emirates and the United Kingdom for approximately 6,085 square kilometers. 42 Table of Contents Eni’s investment in developed and undeveloped acreage is comprised of numerous concessions, blocks and leases. The terms and conditions under which the Company maintains exploration and/or production rights to the acreage are property-specific, contractually defined and vary significantly from property to property. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration. In some instances, Eni may elect to relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases where additional time may be required to fully evaluate acreage, Eni has generally been successful in obtaining extensions. The scheduled expiration of leases and concessions for undeveloped acreage over the next three years is not expected to have a material adverse impact on the Company. The gross undeveloped acreages that will expire in the next three years are related to exploration leases, blocks, concessions in: (i) Rest of Europe, in particular in Cyprus, Albania, Netherlands, Norway and the United Kingdom; (ii) Rest of Asia, in particular in Indonesia, Timor Leste, Vietnam, Lebanon, Oman and the United Arab Emirates; (iii) North Africa, in particular in Egypt and Libya; (iv) Sub-Saharan Africa, in particular in Angola, Namibia, Congo, Ghana and Côte d'Ivoire; (v) Americas, in particular in Mexico; and (vi) Australia and Oceania, in particular in Australia. In most cases extension or renewal options are contractually defined and may or may not be exercised depending on the results of the studies and the planned activities. Management believes that a significant amount of acreage will be maintained following extension or renewal. The table below provides certain information about the Company’s oil&gas properties. It provides the total gross and net developed and undeveloped oil and natural gas acreage in which the Group and its equity-accounted entities had interest as of December 31, 2025. A gross acreage is one in which Eni owns a working interest. 43 Table of Contents December 31, 2024 December 31, 2025 Total Number of Gross developed Gross undeveloped Total gross Net developed Net undeveloped Total net net acreage (a) interests acreage (a) (b) acreage (a) acreage (a) acreage (a) (b) acreage (a) acreage (a) EUROPE 38,752 480 18,026 59,109 77,135 8,557 23,062 31,619 Italy 7,797 108 7,134 3,404 10,538 5,938 2,900 8,838 Rest of Europe 30,955 372 10,892 55,705 66,597 2,619 20,162 22,781 Albania 587 1 477 477 477 477 Cyprus 13,988 4 14,020 14,020 7,466 7,466 Netherlands 1,599 35 1,960 2,177 4,137 833 681 1,514 Norway 10,174 188 5,907 32,289 38,196 959 8,187 9,146 United Kingdom 4,607 144 3,025 6,742 9,767 827 3,351 4,178 AFRICA 73,926 284 44,877 231,695 276,572 12,110 76,478 88,588 North Africa 45,131 157 20,214 161,671 181,885 8,143 52,365 60,508 Algeria 8,095 78 10,858 48,717 59,575 4,240 17,069 21,309 Egypt 10,205 54 4,433 32,053 36,486 1,594 10,855 12,449 Libya 24,644 14 1,963 78,085 80,048 958 23,686 24,644 Tunisia 2,187 11 2,960 2,816 5,776 1,351 755 2,106 Sub-Saharan Africa 28,795 127 24,663 70,024 94,687 3,967 24,113 28,080 Angola 9,456 69 10,688 40,202 50,890 906 8,515 9,421 Congo 1,099 11 518 1,320 1,838 265 713 978 Côte d'Ivoire 9,007 12 1,309 11,874 13,183 676 10,084 10,760 Ghana 502 4 226 946 1,172 100 402 502 Mozambique 3,260 6 719 3,193 3,912 180 736 916 Namibia 1,145 1 5,386 5,386 1,145 1,145 Nigeria 4,327 24 11,203 7,103 18,306 1,840 2,518 4,358 ASIA 80,904 36 14,595 129,039 143,634 3,832 63,772 67,604 Kazakhstan 1,273 6 2,391 2,505 4,896 442 831 1,273 Rest of Asia 79,631 30 12,204 126,534 138,738 3,390 62,941 66,331 China 7 Indonesia 12,051 10 2,288 14,850 17,138 1,926 9,945 11,871 Iraq 446 1 1,074 1,074 446 446 Lebanon 610 1 1,742 1,742 610 610 Oman 9,037 2 11,256 11,256 9,037 9,037 Qatar 38 1 1,206 1,206 38 38 Timor Leste 4,140 2 83 4,032 4,115 33 3,528 3,561 Turkmenistan 180 1 200 200 180 180 United Arab Emirates 16,658 7 8,559 12,032 20,591 805 8,335 9,140 Vietnam 15,245 2 12,886 12,886 10,229 10,229 Other Countries (c) 21,219 3 68,530 68,530 21,219 21,219 AMERICAS 8,336 60 1,923 11,549 13,472 885 7,437 8,322 Mexico 3,336 10 67 5,165 5,232 67 3,269 3,336 United States 362 39 595 154 749 321 27 348 Venezuela 1,066 6 1,261 1,544 2,805 497 569 1,066 Other Countries 3,572 5 4,686 4,686 3,572 3,572 AUSTRALIA AND OCEANIA 9,429 8 328 15,394 15,722 328 9,101 9,429 Australia 9,429 8 328 15,394 15,722 328 9,101 9,429 Total 211,347 868 79,749 446,786 526,535 25,712 179,850 205,562 (a) Square kilometers. (b) Developed acreage refers to those leases in which at least a portion of the area is in production or encompasses proved developed reserves. (c) Includes exploration acreage in Russia that are expected to be relinquished. The table below sets forth, as of December 31, 2025 and by main producing countries in each geographic area, Eni’s producing assets, the year in which Eni’s activities started (for acquired assets, the year corresponds to the acquisition date) and the Eni’s participating interest in each asset. The table does not include the assets held by the joint ventures and associates. In particular: (i) in Angola, the Azule Energy joint venture (Eni's interest 50%) holds interests in 17 blocks (of which 9 exploration blocks) and also in the Angola LNG JV and one exploration license in Namibia; (ii) in the United Kingdom, the Ithaca Energy joint venture (Eni’s interest 35.92%) holds interests in 39 production fields, of which 10 operated, located in the North Sea; (iii) in Norway, the Vår Energi associate (Eni's interest 63.1%) holds interests in 190 licences; (iv) in Mozambique, the Mozambique Rovuma Venture SpA joint venture (Eni's interest 35.71%) is the operator of the Area 4 production licence; (v) in Venezuela, where the Cardon IV (Eni's interest 50%), PetroSucre (Eni’s interest 26%) and PetroJunin (Eni’s interest 40%) joint ventures holds interests in the Perla, Corocoro and Junin 5 production fields, respectively; (vi) in Tunisia, where operate the Société Italo Tunisienne d’Exploitation Pétrolière (Eni’s interest 50%) joint venture; and (vii) in Algeria, where operate the E&E Touat BV joint venture (Eni’s interest 66%). 44 Table of Contents ITALY Adriatic and Ionian Sea: Cervia-Arianna (100%), Luna (100%), Barbara (100%), Emilio-Donata (100%), Clara NW (51%) and Hera Lacinia (100%) (1926) Basilicata Region: Val d'Agri (61%) Sicily: Argo-Cassiopea (60%), Gela (100%), Giaurone (100%), Prezioso (100%) and Armatella (100%) REST OF EUROPE Netherlands F3 (58.96%), G-blocks (from 33.7% to 60%), K2b-A (56.62%), K9ab-B (35.43%), L12-L15 (from 30% to 30.23%), L10/K12 (from 15.56% to 49.29%), L5 hub (from 59.50% to 60%), Q13a-A (50%) and K6-D (5.78%) (2024) NORTH AFRICA Algeria (a) Sif Fatima II (49%), Berkine South (75%), Block 404-208 (17,5%), Zemlet El Arbi (49%), Ourhoud II (49%), Blocks 403a/d (100%), Block ROM North (35%), Blocks 401a/402a (100%), Block 403 (50%), Block 405b (75%), In Amenas (45.89%) and In Salah (33.15%) (1981) Egypt (a)(b) Sinai (Abu Madi, Sinai 12 Leases - 100%), Ras el Barr (Ha'py and Seth - 50%), South Ghara (South Ghara, Hilal, Shoab Ali - 25%), Alam El Shawish (Assil, Karam, Barq-Bahga, Magd - 25%), Shorouk (Zohr - 50%), Nile Delta (Abu Madi West/Nidoco, El Qar'NE - 75%), Meleiha (76%), North Port Said (Port Fouad - 100%), Temsah (Tuna, Temsah e Denise - 50%), Southwest Meleiha (SWM, SWM-4 -75%), Baltim (Baltim North, Baltim East, Baltim South -50%), North El Hammad Offshore (Bashrush - 37,5%) ed East Obayed (Faramid - 75%) (1954) Libya (a) Offshore contract areas: Area C (Bouri - 50%) and Area D (Block NC 41 - 50%) (1959) Onshore contract areas: Area A (former concession 82 - 50%), Area B (former concession 100/ Bu-Attifel and Block NC 125 - 50%), Area E (El-Feel - 33.3%) and Area D (Block NC 169 - 50%) Tunisia Adam (30%), Oued Zar (50%) and Djebel Grouz (50%) (1961) SUB-SAHARAN AFRICA Congo Néné-Banga Marine and Litchendjili (Block Marine XII, 65%), Kitina (52%) and Yanga Sendji (29.75%) (1968) Côte d'Ivoire Baleine (47.25%) (2015) Ghana Offshore Cape Three Points (44.44%) (2009) Nigeria(c) OML 125 (100%) and OML 118 (15%) (1962) KAZAKHSTAN (a) Karachaganak (29.25%) and Kashagan (16.81%) (1992) REST OF ASIA Indonesia Jangkrik (88.33%), Jangkrik North East (88.33%) Merakes (85%) and Merakes East (85%) (2001) Iraq Zubair (41.56%)(d) (2009) United Arab Emirates Lower Zakum (5%), Umm Shaif and Nasr (10%) and Area B - Sharjah (50%) (2018) Turkmenistan(2008) Burun (90%) AMERICAS Mexico Area 1 (100%) (2019) United States Allegheny (100%), Appaloosa (100%), Pegasus (100%), Longhorn (75%), Devils Towers (100%), Triton (100%), Europa (32%), Medusa (25%), Lucius (14.45%), Frontrunner (37.5%) and Heidelberg (12.5%) (1968) (a) In certain extractive initiatives, Eni and the host Country agree to assign the operatorship of a given initiative to an incorporated joint venture, a so‐called operating company. The operating company in its capacity as the operator is responsible of managing extractive operations. Those operating companies are not controlled by Eni. (b) Eni’s working interests (and not participating interests) are reported. This includes Eni’s share of costs incurred on behalf of the first party accordingly to the terms of PSAs inforce in the Country. (c) As partners of Renaissance Africa Energy Company Limited JV (RAEC JV; ex SPDC JV), Eni holds a 5% interest in 18 blocks. (d) Eni is leading a consortium of partners including Kogas and the national oil companies Missan Oil and Basra Oil within a Technical Service Contract as contractor. 45 Table of Contents The table below provides the number of gross and net productive oil and natural gas wells in which the Group companies and its equity-accounted entities had an interest as of December 31, 2025. A gross well is a well in which Eni owns a working interest. The number of gross wells is the total number of wells in which Eni owns a whole or fractional working interest. The number of net wells is the sum of the whole or fractional working interests in a gross well. One or more completions in the same borehole are counted as one well. Productive wells are producing wells and wells capable of production. The total number of oil and natural gas productive wells is 6,756.0 (2,120.4 of which represent Eni’s share). Productive oil and gas wells at Dec. 31, 2025 (a) (units) Oil Wells Natural gas Wells Gross Net Gross Net Italy 107.0 94.8 224.0 193.7 Rest of Europe 730.0 113.5 228.0 54.8 North Africa 1,916.0 823.5 459.0 186.5 Sub-Saharan Africa 1,518.0 164.2 134.0 13.0 Kazakhstan 168.0 45.2 Rest of Asia 995.0 304.2 68.0 25.4 Americas 196.0 92.3 9.0 5.3 Australia and Oceania 4.0 4.0 Total including equity-accounted entities 5,630.0 1,637.7 1,126.0 482.7 (a) Multiple completion wells included above: approximately 913 (240 net to Eni). Eni’s exploration and production activities are subject to a broad range of laws and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and condition of the leases, licenses and contracts under which these oil&gas interests are held vary from country to country. These leases, licenses and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These contractual arrangements usually take the form of concession agreements or production sharing agreements: - Concession contracts are currently applied mainly in OECD countries and regulate relationships between States and oil companies with regards to hydrocarbon exploration and production activity. The company holding the mining concession has an exclusive right on exploration, development and production activities, sustaining all the operational risks and costs related to the exploration and development activities, and it is entitled to the productions obtained. As compensation for mineral concessions, it pays royalties on production (which may be in cash or in-kind) and taxes on profits from the exploitation of oil and gas concessions to each state in accordance with local tax legislation. Both exploration and production licenses are granted generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases): the term of Eni’s licenses and the extent to which these licenses may be renewed vary by area. Proved reserves to which Eni is entitled are determined by applying Eni’s share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right. In Particular, Eni’s exploration and production activities are regulated by concession contracts or a similar scheme mainly in Italy, Ghana, Tunisia, the United Arab Emirates, the United Kingdom, the United States, certain assets in Nigeria, Angola and Australia. In Norway, Eni’s activities are regulated by Production Licenses (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. - Eni operates under Production Sharing Agreement (PSA) in several foreign jurisdictions mainly in countries in Africa, Middle East and Far East. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract, the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment (technologies) and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: “Cost Oil” is used to recover costs borne by the contractor and “Profit Oil” is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country. Pursuant to these contracts, Eni is entitled to a portion of a field’s reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The Company’s share of production volumes and reserves representing the Profit Oil includes the share of hydrocarbons which corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. As a consequence, the Company has to recognize at the same time an increase in the taxable profit, through the increase of the revenues, and a tax expense. Proved reserves to which Eni is entitled under PSAs are calculated so that the sale of production entitlements should cover expenses incurred by the Group to develop a field (Cost Oil) and recognize the Profit Oil set contractually (Profit Oil). 46 Table of Contents A similar scheme applies to some Service contracts. Eni’s exploration and production activities are regulated by PSA or similar scheme in Algeria, Angola, China, Congo, Egypt, Indonesia, Libya, Mexico, Mozambique, Timor Leste in the JPDA area, Turkmenistan, certain assets in Nigeria, and Kazakhstan. Development and production activities in Iraq are regulated by a technical service contract. This contractual scheme establishes an oil entitlement mechanism and an associated risk profile similar to those applicable to PSA. Eni’s principal oil and gas properties are described below. For further information on main activities of the year see also “Significant business portfolio”. In the discussion that follows, references to hydrocarbon production are intended to represent hydrocarbon production available for sale. Italy Eni’s activities in Italy are mainly deployed in the Adriatic and Ionian Seas, the Central Southern Apennines and mainland and offshore Sicily. Eni operates 23 onshore and 43 offshore productive concessions. In 2025, Italy accounted for approximately 4% of Eni’s total worldwide production of oil and natural gas. 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. In the gas assets of the Adriatic and Ionian Seas, 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; and (iv) a plug-and-abandon campaign for no longer productive wells, including those for the Ravenna CCS project, is ongoing. 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 northerner part of the field; and (ii) production optimization actions to mitigate production decline. 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 have 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. 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 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. Rest of Europe Eni’s operations in the Rest of Europe are mainly conducted in the United Kingdom through Ithaca Energy, Norway through Vår Energi and the Netherlands. In 2025, the Rest of Europe accounted for 17% of Eni’s total worldwide production of oil and natural gas. Netherlands. 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. Norway. In 2025, an additional participation stake was acquired in the Ekofisk producing project in the PL018F development license and thus Vår Energi’s interest increased to approximately 52% in the Greater Ekofisk Area. The transaction is subject to the necessary approvals. During 2025, production start-up was achieved at: (i) the Johan Castberg oil field 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 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. 47 Table of Contents United Kingdom. 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 Eni’s operations in North Africa are mainly conducted in Algeria, Egypt, Libya and Tunisia. In 2025, North Africa accounted for 31% of Eni’s total worldwide production of oil and natural gas. Algeria. 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. During the year, an additional stake in the Touat license was acquired, increasing Eni's interest to 42.9%. 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. In 2025, Eni signed agreements with Cyprus and Egypt counterparties to develop gas reserves of 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. 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. The rights of Eni to produce at the Zohr Development Lease will expire in 2037. 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. 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. Libya. In 2025, Libya represented approximately 10% of the Group’s total production. In 2025, a relatively more stable sociopolitical environment than in previous years, allowed continuity to production operations and to develop projects sanctioned in 2023. Despite those developments, going forward, management continues to monitor Libya's geopolitical situation which is recognized as a source of risk and uncertainty to Eni's operations in the Country and related Group’s financial results. For further information on this matter, see “Item 3 – Risk factors – Political considerations”. The rights of Eni to produce at its assets in Libya will expire in 2038 for Contract Areas C, in 2042 for Contract Area E, in 2043 for Contract Areas A, B and D-producing fields, in 2062 for Area D-new developments (A&E Structures). 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 February 2026 Eni was awarded the O1 offshore exploration license through a consortium with another partner. Eni will be the operator. 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. Their proximity to the Bahr Essalam field will ensure a fast-track development through tie-back to existing production facilities. Tunisia. 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; and (iii) the start of development drilling activities in the Djebel Grouz concession. Sub-Saharan Africa Eni’s operations in Sub-Saharan Africa are conducted mainly in Congo, Côte d'Ivoire, Ghana, Mozambique, Nigeria and through Azule Energy in Angola and Namibia. In 2025, Sub-Saharan Africa accounted for 19% of Eni’s total worldwide production of oil and natural gas. Angola. 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. 48 Table of Contents In the year, production started at the 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 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; (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. 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. Congo. 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 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. 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. Côte d'Ivoire. 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. 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. 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 in the Block CI-501 (Eni operator with a 90% interest). Ghana. 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 operated by Eni and was submitted for approval by the country's authorities at the end of 2025. 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; and (iii) tenders were launched for awarding contracts of the linkage of the new GyeNyame non-associated gas well to existing FPSO. 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 of the offshore Area 4 Block where the discovery of Mamba and Coral are located. Following two separate transactions closed respectively in 2013 and in 2017, Eni retains a 25% indirect interest in the Area 4 concession. In 2017, the concessionaries of Area 4 achieved the Final Investment Decision (FID) to develop the reserves of the Coral discovery, sanctioning the Coral South project, currently in production. The Coral Sul Floating Liquefied Natural Gas (FLNG) vessel is designed to treat, liquefy the gas and to store and export the LNG, with a capacity of approximately 3.4 mmtonnes/y of LNG, produced through six subsea wells. 49 Table of Contents 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. Namibia. Exploration activity yielded positive results with the Sagittarius-1X gas and condensate well, the Capricornus-1X oil well as well as a further rich gas and condensate discovery at Volans-1X well. The appraisal campaigns planned in the Capricornus area and results of the production tests will be evaluated for possible integrated development projects. Nigeria. In November 2025, Eni acquired an additional 2.5% stake in the Production Sharing Contract (PSC) OML 118, exercising its pre-emption right. 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). 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. 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 (ex 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 and is sold FOB by means of the fleet owned by third parties. Kazakhstan Eni’s operations in Kazakhstan are performed at the Kashagan and the Karachaganak oilfields. In 2025, Kazakhstan accounted for 10% of Eni’s total worldwide production of oil and natural gas. Kashagan. Eni holds a 16.81% working interest in the North Caspian Sea Production Sharing Agreement (NCSPSA). The NCSPSA defines terms and conditions for the exploration and development of the Kashagan field, that was discovered in the Northern section of the contractual area in the year 2000 in an area extending for 4,600 square kilometers. Management believes this field to contain a large amount of hydrocarbon resources, which are expected to be developed in phases. The NCSPSA expires in 2041. In addition to Eni, the partners of the Consortium are the Kazakh national oil company, KazMunayGas, with a participating interest of 16.88%, the international oil companies TotalEnergies, Shell and ExxonMobil, each with a participating interest of 16.81%, CNPC with 8.33%, and Inpex with 7.56%. In 2025, production at the Kashagan field averaged 67 KBBL/d of liquids and 62 mmCF/d of natural gas net to Eni. 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%) is re-injected in the reservoir. Development plans envisage a phased increase in the production capacity. The first development phase provides for a progressive increase up to 450 kbbl/d. The activities, sanctioned in 2020, include the upgrading of management capacity of associated gas by means of: (i) increasing gas reinjection capacity by upgrading existing facilities, which was completed in 2022; and (ii) installation of a new onshore treatment unit operated by a third party, currently under construction, for the remaining part of associated gas volumes. Management believes that significant capital expenditure will be required in case the partners of the venture would sanction a second development phase and possibly other additional phases. Eni will fund those investments in proportion to its participating interest of 16.81%. However, taking into account that future development expenditures will be incurred over a long-term horizon, management does not expect any material impact on the Company’s liquidity or its ability to fund these capital expenditures. Karachaganak. Located onshore in West Kazakhstan, Karachaganak is a liquid and gas field. Operations are conducted by the Karachaganak Petroleum Operating consortium (KPO) and are regulated by a PSA that expires in 2037. Eni and Shell are cooperators of the venture. Eni’s interest in the Karachaganak project is 29.25%. In 2025, production of the Karachaganak field averaged 46 KBBL/d of liquids and 141 mmCF/d of natural gas net to Eni. This field is producing liquids from the deeper layers of the reservoir. The gas is delivered (about 45%) to the Russian gas plant of Orenburg; management believes this transaction does not violate the current sanction regime imposed to Russia following the military invasion of Ukraine. 50 Table of Contents The remaining gas volumes are utilized for re-injection in the higher layers of the reservoir and as fuel gas. Almost the entire liquid production is stabilized at the Karachaganak Processing Complex (KPC) and exported to Western markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara pipeline, this latter also a new route opened in 2023 leading to Germany. In 2025 activities progressed with the installation of a sixth compression unit, last development phase, sanctioned in 2022. Start-up is expected in 2026. Rest of Asia Eni’s operations in the Rest of Asia are mainly conducted in Indonesia, Iraq, Turkmenistan and the United Arab Emirates. In 2025, Eni’s operations in the Rest of Asia accounted for approximately 11% of its total worldwide production of oil and natural gas. Indonesia. In November 2025, Eni signed an investment agreement with Petronas, Malaysian state-owned company, to establish a jointly controlled venture to combine the two partners’ gas-rich production and development assets of Indonesia and Malaysia. The new company will be a financially self-sufficient entity, able to generate operational and financial synergies to deliver one of the main players on the LNG market and plans to grow to 500 KBOE/d of production in the medium term. The transaction completion is subject to governmental, regulatory, and partner approval. In May 2025, gas production start-up was achieved at the Merakes East field, in East Sepinggan block (Eni operator with an 85% interest) in the Kutei basin, offshore Indonesia, with initial rate of approximately 18 KBOE/d to Eni’s production. In the year development activities concerned: (i) the definition of integrated project of the Geng North and Gehem fields within the North Hub development, in the Kutei area. These fields will be put into production by means of subsea wells, flowlines and a new FPSO. Natural gas will be treated by the FPSO and will be carried to onshore facilities linked to the East Kalimantan pipeline network. The production will be delivered to the Bontang LNG plant and exported; a part of gas production will be destined to fulfil domestic needs. The condensates production will be stabilized and stored by the FPSO and then lifted; (ii) the definition of the Gendalo and Gandang gas project (South Hub). The development program of two fields provides for the drilling of new subsea wells and the tie-back connection to existing facilities of the Jangkrik production fields; and (iii) the execution of the Maha project where two new subsea wells will be put into production by means of tie-back connection to existing facility of Jangkrik field. In March 2026, Eni achieved the Final Investment Decisions (FIDs) for the Gendalo and Gandang gas project (South Hub) and for the Geng North and Gehem fields (North Hub), only 18 months after the approval of the Projects of Development (PODs) in 2024. Exploration activities yielded positive results with: (i) the Konta-1 well in the Muara Bakau block with a significant gas and condensates discovery where a production test has been successfully performed. This discovery is nearby existing facilities of the Jangkrik production field, providing significant synergies for the development; and (ii) the Kadal-1 gas well in the East Ganal block (Eni’s interest 100%), with an option for a development program in synergy with the Maha project. Iraq. Activities comprised the execution of an additional development phase of the ERP (Enhanced Redevelopment Plan) at the Zubair field. Main facilities have already been installed. Ongoing development activities include programs to expand water availability to maintain adequate reservoir pressurization in the long term and to increase water treatment and re-injection capacity. In particular, at the end of 2025 it has been initiated the phased start-up of the Zubair Mishrif Expansion project. This project includes four oil treatment units for a total capacity of 200 KBOE/d to ensure the replacement of existing production facilities and an additional water injection capacity of 750 KBOE/d. In addition, a program to achieve technical zero flaring by 2027 is being implemented. The field reserves will be progressively put into production by drilling additional productive wells over the next few years and by means of the collection facilities expansion and the completion of the water reinjection wells. Turkmenistan. Development activities mainly concerned: (i) the drilling of nine infilling and peripheral wells; and (ii) the conversion of five wells to water injectors to maximize hydrocarbon recovery. United Arab Emirates. In June 2025, the new Production Concession license of the offshore Block 2 to develop the Waset field (Eni's interest 28%) was approved by the country's Authority. Activities of the year mainly concerned: (i) the development program of the Ghasha offshore concession (Eni's interest 10%) to put into production the Dalma, Hail and Ghasha fields. In particular, the Dalma Gas project is being finalized while activities progressed at the Hail & Gasha project, sanctioned in 2023, according to the development plan; and (ii) ongoing development activities to support the increasing production at the Lower Zakum and Um Shaif/Nasr concessions. Americas Eni’s operations in Americas are conducted mainly in Mexico, United States and Venezuela. In 2025, Eni’s operations in the Americas area accounted for approximately 8% of its total worldwide production of oil and natural gas. Mexico. In 2025 Eni started the relinquishment of the Area 14 and Area 28 licenses in line with strategy of rationalizing the upstream exploration portfolio. Formalization process by the relevant Authorities is ongoing. Development activities of the Area 1 producing project concerned: (i) the drilling of five development wells; and (ii) ongoing infilling program to optimize hydrocarbons recovery 51 Table of Contents United States. Activities of the year concerned production optimization at the Devil’s Tower operated field and at the Lucius and Europa non-operated fields. Venezuela. In 2025, Eni’s production of oil and natural gas averaged 63 KBOE/d and accounted for approximately 4% of Eni’s total production. The political and economic crisis in Venezuela continued for years, influenced by the sanctions imposed by the US on exports crude oil targeting the Venezuelan government and the State oil Company PDVSA. Eni’s activities in the Country include the Perla offshore gas field, operated by the local joint venture Cardón IV SA, equally participated by Eni and other international oil company, where equity volumes of natural gas supplied to the national oil company of Venezuela. Other petroleum interests held by Eni in the Country comprise oil licenses in the Orinoco Belt, operated under the “Empresa Mixta” regime, where production is declining and their carrying amounts were fully impaired in prior years. Eni is exposed to credit exposure to recover its investment in Cardón IV due to the financial difficulties of PDVSA following the U.S. sanctions regime in force through 2025. However, in early 2026 certain developments were recorded in the relations between Venezuela and the United States, which are expected to improve the outlook for the country’s oil sector. These developments could, compared with the past, partially mitigate the uncertainty of the operating environment in relation to the recovery of Eni’s trade receivables from the state-owned oil company PDVSA and may give rise to potential business opportunities, subject to the evolution of the relevant regulatory and operating conditions. At the end of January 2026, the National Assembly approved a partial reform of the Organic Hydrocarbons Law which includes the renegotiation of existing oil contracts in relation to the Empresa Mixta regime, a new taxation system, and the proposal to strengthen legal safeguards for investment by introducing the possibility of resorting to independent mediation and arbitration mechanisms. In addition, the USA Authority issued “general licenses” enabling operations in the oil and gas sector in Venezuela by certain U.S. and European oil companies. Particularly significant is General License 50A, which broadly authorizes Eni to carry out transactions in the oil and gas sector in Venezuela that would otherwise be prohibited under the Venezuelan sanctions program (including those involving the Government of Venezuela, PDVSA, and its subsidiaries). These developments enhance the credit recovery outlook compared to the early scenario characterized by the US sanction regime on Venezuelan oil and gas sector. For further information see Item 3 – Risk Factors and Item 18 - Notes on Consolidated Financial Statements. Australia and Oceania Eni’s operations in Australia and Oceania are mainly conducted in Australia. Australia. Activities for the year concerned engineering studies for the development program of the Petrel field (Eni’s interest 100%, following acquisition of stake held by third parties closed in December 2025) located in the WA-6-R and NT/RL1 offshore blocks near to the Blacktip facilities where it will be linked. The project includes the drilling of two wells, the construction and installation of a platform and natural gas transport facility. Capital expenditures See “Item 5 – Liquidity and capital resources – Capital expenditures by segment”. Disclosure pursuant to Section 13(r) of the Exchange Act The Iran Threat Reduction and Syria Human Rights Act of 2012 (ITRA) created a new subsection (r) in Section 13 of the Exchange Act which requires a reporting issuer to provide disclosure if the issuer or any of its affiliates engaged in certain enumerated activities relating to Iran, including activities involving the Government of Iran. In accordance with our general business principles and Code of Ethics, Eni seeks to comply with all applicable international trade laws including applicable sanctions and embargoes. The activities referred to below have been conducted outside the U.S. by non-U.S. Eni subsidiaries. For purposes of the disclosure below, amounts have been converted into U.S. dollars at the average or spot exchange rate, as appropriate. In 2017, Eni recovered certain overdue trade receivables owed by Iranian state-owned companies relating to the cost recovery of past projects in accordance with agreements signed in 2016, while the amounts of cost recovery not covered by such agreements were written down in Eni accounts in the following years. Eni is seeking to recover approximately $30 million of such remaining receivables in compliance with the applicable regulation and once certain administrative compliance procedures in the country are completed, subsequently allowing the de-registration of the local branch. 52 Table of Contents Global Gas & LNG Portfolio and Power Competitive trends in the industries where the Company operates In the Global Gas & LNG Portfolio business, Eni is facing strong competition in the European wholesale markets to sell gas to industrial customers, the thermoelectric sector and retail companies from other gas wholesalers, upstream companies, traders and other players. The results of Eni’s wholesale gas business are affected by global and regional dynamics of gas demand and supplies, as well as by the constraints of its portfolio of long-term, take-or-pay supply, whereby the Company is obligated to offtake minimum annual volumes of gas or in case of failure to pay the corresponding purchase price (see below). Due to the competitive nature of the business, sales margins tend to be small. We believe wholesale margins of gas will be negatively affected by competitive pressures in connection with an oversupplied global natural gas market and rising LNG flows, a structural decline in European consumption due to plant closures or relocations, energy saving measures introduced by the EU during the gas crisis of 2022 and by the expected growth of renewable sources of energy that will replace natural gas in supplying electricity to European markets in the medium term. The results of the LNG business are mainly influenced by the global balance between demand and supplies, considering the higher level of flexibility of LNG with respect to gas delivered via pipeline. Eni also engages in the business of producing gas-fired electricity that is largely sold in the wholesale market and in providing the service of peak-load capacity to the Italian grid. The business is exposed to competition from large players and other electricity producers, like renewables. Global Gas & LNG Portfolio Global Gas & LNG Portfolio engages in the wholesale activity of supplying and selling natural gas via pipeline and LNG, and the international transport activity. It also comprises gas trading activities targeting both hedging and stabilizing the Group’s commercial margins and optimize the gas asset portfolio. In 2025, Eni’s worldwide sales of natural gas amounted to 43.72 BCM. Sales in Italy amounted to 21.00 BCM, while sales in European markets were 18.73 BCM that included 0.91 BCM of gas sold to certain importers to Italy. The business results of operations in 2025 and its strategy are described in “Item 5 – Group results of operations” and “Item 5 – Management’s expectations of operations.” Supply of natural gas The supply contracts which were intended to support Eni’s sales plan in Italy and in other European markets, provide take-or-pay clauses whereby the Company has an obligation to lift minimum, preset volumes of gas in each year of the contractual term or, in case of failure, to pay the whole price, or a fraction of that price, up to a minimum contractual quantity. Similar considerations apply to ship-or-pay contractual obligations which arise from contracts with transmission system operators or pipeline owners, which the Company has entered into to secure long-term transport capacity. In 2025, Eni subsidiaries’ total supply of natural gas was 43.92 BCM, decreased by 7.13 BCM, or 14% compared to 2024. Gas volumes supplied outside Italy (38.73 BCM from consolidated companies), imported in Italy or sold outside Italy, represented approximately 89% of total supplies, decreased by 4.66 BCM, or 10.7% compared to the previous year, due to lower volumes purchased in Russia (down by 6.19 BCM), in Qatar (down by 1.76 BCM), in Libya (down by 0.45 BCM) and in the Netherlands (down by 0.40 BCM), partially offset by higher purchases in the UK (up by 0.44 BCM), in Indonesia (up by 0.42 BCM), in Congo (up by 0.25 BCM) and in Norway (up by 0.22 BCM). Supplies in Italy (5.19 BCM) reported a decrease of 32.2% from the full year 2024. In 2025, gas supplies from Russia reduced to zero, decreasing by 6.19 BCM from the comparative period. In 2024 gas volumes were related to a long-term sale contract with Turkish company Botas, transported via the Eni-Gazprom jointly-operated Blue Stream pipeline through the Black Sea. This joint arrangement has expired at the end of 2025. Eni is evaluating the potential divestment of its interest in Blue Stream, which has minor contribution to the Group’s results and total assets. 53 Table of Contents The table below sets forth Eni’s purchases of natural gas by source for the periods indicated. Natural gas supply 2025 2024 2023 (BCM) Italy (including LNG) 5.19 7.66 5.71 Outside Italy 38.73 43.39 44.34 Algeria (including LNG) 10.72 10.70 12.06 Norway 7.10 6.88 6.49 Indonesia (LNG) 2.28 1.86 1.56 the United Kingdom 1.67 1.23 1.42 the Netherlands 1.46 1.86 1.62 Qatar (LNG) 1.15 2.91 2.91 Libya 0.96 1.41 2.52 Congo (LNG) 0.70 0.45 Russia 0.00 6.19 6.16 Other supplies of natural gas 4.66 6.80 5.89 Other supplies of LNG 8.03 3.10 3.71 Total supplies of subsidiaries 43.92 51.05 50.05 Withdrawals from (input to) storage (0.20) (0.09) 0.54 Network losses, measurement differences and other changes 0.00 (0.08) (0.08) Volumes available for sale of Eni’s subsidiaries 43.72 50.88 50.51 Total volumes available for sale 43.72 50.88 50.51 Sales of natural gas Eni is selling gas to wholesale markets in Italy and in a number of European countries. The wholesale market includes sales to large accounts (industrials and thermoelectric utilities) and on European spot markets. In 2025, natural gas sales amounted to 43.72 BCM (including Eni’s own consumption, Eni’s share of sales made by equity-accounted entities), representing a decrease of 7.16 BCM, or 14.1% from the previous year. Sales in Italy (21.00 BCM) decreased compared to 2024, mainly due to lower volumes marketed in the wholesale sector and lower sales to hub. Sales in the European markets amounted to 17.82 BCM, decreased by 19.5% or 4.32 BCM from 2024 in particular in Turkey, following the termination of the gas sale contract on BlueStream at the end of 2024. Sales to long-term buyers were 0.91 BCM, down by 27.8% compared to the previous year due to the lower availability of Libyan output. Sales in the Extra European markets (3.99 BCM) increased by 0.91 BCM or 29.5% due to higher LNG volumes sold in the Asian markets. The tables below set forth Eni’s sales of natural gas by principal market for the periods indicated. Natural gas sales by geographical area 2025 2024 2023 (BCM) Worldwide gas sales 43.72 50.88 50.51 Italy (including own consumption) 21.00 24.40 24.40 Rest of Europe 18.73 23.40 23.84 Outside Europe 3.99 3.08 2.27 Natural gas sales by market 2025 2024 2023 (BCM) ITALY 21.00 24.40 24.40 Wholesalers 8.78 11.01 10.71 Italian gas exchange and spot markets 4.12 5.94 6.28 Industries 1.98 1.56 1.50 Power generation 0.55 0.51 0.52 Own consumption 5.57 5.38 5.39 INTERNATIONAL SALES 22.72 26.48 26.11 Rest of Europe 18.73 23.40 23.84 Importers in Italy 0.91 1.26 2.29 European markets 17.82 22.14 21.55 Iberian Peninsula 3.58 3.18 2.75 Germany/Austria 3.47 4.35 3.35 Benelux 5.30 3.63 3.75 United Kingdom/Northern Europe 1.67 1.23 1.42 Turkey 0.20 6.10 6.90 France 3.60 3.58 3.31 Other 0.00 0.07 0.07 Extra European markets 3.99 3.08 2.27 WORLDWIDE GAS SALES 43.72 50.88 50.51 54 Table of Contents The LNG business Eni LNG business can count currently on a portfolio of contracted long-term supplies mainly from: Qatar, Nigeria and Indonesia. In the plan period, Eni intends to develop its LNG business leveraging on the integration with the E&P segment and the valorization of the equity gas. Final markets of that gas include Europe and Asia. The business’s profitability will be also driven by enhancing the commercial presence in premium markets and continuing integration with trading activities. LNG sales 2025 2024 2023 (BCM) Europe 8.1 6.7 7.3 Extra European markets 4.0 3.1 2.3 12.1 9.8 9.6 International transport Eni has transport rights on a large European network of integrated infrastructures for transporting natural gas, which links key consumption markets with the main producing areas (Algeria, the North Sea, including the Netherlands and Norway, and Libya). Eni has contracted the transport capacity under ship-or-pay contracts, which are similar to take-or-pay contracts. The main assets of Eni’s transport activities are provided in the table below. International Transport infrastructure Route Lines Total length Diameter Transport capacity Compression stations (units) (km) (inch) (BCM/y) (No.) TTPC (Oued Saf Saf-Cap Bon) 2 lines of km 370 740 48 34.3 5 TMPC (Cap Bon-Mazara del Vallo) 5 lines of 155 775 20/26 33.5 GreenStream (Mellitah-Gela) 1 line of km 516 516 32 11.5 1 Blue Stream (Beregovaya-Samsun) 2 lines of km 387 774 24 16.0 1 International transport activities The TTPC pipeline, 740 kilometer long, is made up of two lines that are each 370-kilometers long with a transport capacity of 34.3 BCM/y and five compression stations. This pipeline transports natural gas from Algeria across Tunisia from Oued Saf Saf at the Algerian border to Cap Bon on the Mediterranean coast where it links with the TMPC pipeline. The TMPC pipeline for the import of Algerian gas is 775 - kilometers long and consists of five lines that are each 155-kilometers long with a transport capacity of 33.5 BCM/y. It crosses the Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system. The GreenStream pipeline, jointly-owned with the Libyan National Oil Corporation, started operations in October 2004 for the import of Libyan gas produced at the Eni operated fields of Bahr Essalam and Wafa. It is 516-kilometers long with a transport capacity of 11.5 BCM/y crossing the Mediterranean Sea from Mellitah on the Libyan coast to Gela in Sicily, the point of entry into the Italian natural gas transport system. The Blue Stream underwater pipeline (water depth greater than 2,150 meters) links the Russian coast to the Turkish coast of the Black Sea. This pipeline is 774 - kilometers long on two lines and has transport capacity of 16 BCM/y. It is part of a joint venture to sell gas produced in Russia on the Turkish market. Following the expiration of the joint arrangement, Eni is evaluating the potential divestment of its interest in Blue Stream, which has minor contribution to the Group’s results and total assets. See "Risks in connection with escalating tensions in the Middle East and conflict between Russia and Ukraine" in the Risk factors section for further information. 55 Table of Contents Power As part of its marketing activities in Italy, Eni engages in selling electricity on the Italian market principally on the open market. Supplies of electricity include both own production volumes through gas-fired, combined-cycle facilities and purchases on the open market. Power sales in the open market In 2025, power sales in the open market were 27.57 TWh, representing an increase of 3.8% compared to 2024 due to higher volumes marketed to the free market (up by 0.74 TWh) and to the power exchange (up by 0.40 TWh). 2025 2024 2023 (TWh) Power generation sold 20.53 20.16 20.66 Trading of electricity (a) 7.04 6.39 6.64 Power availability 27.57 26.55 27.30 Power sales in the open market (b) 27.57 26.55 27.30 of which: sales to third parties 19.78 18.86 17.89 (a) Include positive and negative imbalances (differences between power introduced in the grid and the one planned). (b) Data include intercompany sales. Power generation Enipower’s power generation sites are located in Brindisi, Ferrera Erbognone, Ravenna, Mantova, Ferrara and Bolgiano. As of December 31, 2025, installed operational capacity of Enipower’s power plants was approximately 5 GW. In 2025, thermoelectric power generation was 20.53 TWh, up by 0.37 TWh compared to 2024. Electricity trading (7.04 TWh) reported an increase of 0.65 TWh from 2024. Site Total installed capacity in 2025 (a) Technology Fuel (MW) Brindisi 1,268 CCGT gas Ferrera Erbognone 1,052 CCGT gas/syngas Mantova 851 CCGT gas Ravenna 907 CCGT/Peaker gas Ferrara 785 CCGT gas Bolgiano 64 Power station gas Photovoltaic plants (b) 0.2 Photovoltaic Photovoltaic 4,926 (a) Data refer to 100% of the installed capacity. (b) Managed by EniPower Mantova Power generation 2025 2024 2023 Purchases Natural gas (mmCM) 4,204 4,078 4,144 Other fuels (ktoe) 40 139 156 - of which steam cracking 17 71 85 Production Electricity (TWh) 20.53 20.16 20.66 Steam (ktonnes) 5,867 6,761 6,981 Installed generation capacity (*) (GW) 4.9 4.9 4.9 (*) Data refer to 100% of the installed capacity. Capital expenditures See “Item 5 – Liquidity and capital resources – Capital expenditures by segment”. 56 Table of Contents Enilive and Plenitude Competitive trends in the industries where the Company operates Enilive is facing strong competition in the marketing of fuels to retail customers due to low product differentiation and customers’ sensitivity to prices at the pump. We are making investments to upgrade our service stations and to expand our offer to include biofuels and other energy vectors. Those investments are intended to retain our customers and to improve profitability by leveraging on cross-selling opportunities and the growing customers’ needs of having more products and services bundled with the refuelling. However, customers’ preferences may change very rapidly, and we are exposed to risks of losing customers and sales volumes in case our competitors adopt more aggressive pricing policies or more effective marketing strategies. Plenitude engages in the supply of gas and electricity to customers in the retail markets mainly in Italy, France, Spain, and other countries in Europe. Those markets have been almost fully liberalized. Customers include households, large residential accounts (hospitals, schools, public administration buildings, offices) and small and medium-sized businesses. The retail market is characterized by strong competition among selling companies which mainly compete in terms of pricing and the ability to bundle valuable services with the supply of energy commodity. Due to the commoditized nature of the business, the ability of residential customers to switch smoothly from one supplier to another and a low level of customer loyalty, management expects competition to significantly affect the business going forward. Enilive Enilive is engaged in the supply of biofeedstock, processing and production of biofuels in Italy (Venice and Gela biorefineries) and in the United States, with a 50% interest in the Chalmette biorefinery. In addition, Enilive is engaged in the offer of smart mobility solutions, including Enjoy car sharing, and the marketing and distribution of a wide range of products, including biogenic fuels such as HVO (Hydrotreated Vegetable Oil), bio-LPG and biomethane, hydrogen and electricity, as well as other oil products such as fuels, bitumen, and lubricants. The business also deals with wholesale operators, consisting mainly of resellers, industrial companies, service companies, public bodies and municipal companies, condominiums, operators in the agricultural and fishing sectors. The business results of operations in 2025 and its strategy are described in “Item 5 – Group results of operations” and “Item 5 – Management’s expectations of operations”. Ownership share Capacity (2025) Throughput (2025) (%) (mmtonnes/y) (mmtonnes/y) Wholly-owned biorefineries Venice 100 0.4 0.23 Gela 100 0.7 0.52 Partially owned biorefineries Chalmette 50 0.55 0.41 Total biorefineries 1.65 1.16 Enilive fully owns two biorefineries in Italy, specifically in Venice and Gela. In Venice biorefinery biofuels production started in June 2014 from the conversion of the existing oil-based refinery. The biorefinery has a processing capacity of 0.4 mmtonnes/y, leveraging the Ecofining™ proprietary technology to transform biofeedstock (both vegetable oil and waste and residues) in hydrotreated bio-fuels. Capacity is expected to be increased to 0.6 million tonnes/year with biojet production (SAF) by 2027. Gela biorefinery is based on the EcofiningTM conversion technology, developed by Eni, capable of converting vegetable oils and feedstock consisting of waste and residues, such as used cooking oils and animal fats, into HVO. The specifics of the plant, with a capacity of 0.7 million tons/year, together with a strong supply strategy, allow HVO to be produced in compliance with recent regulatory constraints in terms of reducing GHG emissions throughout the product life cycle. A Biomass Treatment Unit (BTU) allows to expand the range of raw materials to be treated by the plant and to process waste and residues such as animal fats and used cooking oil, replacing palm oil since the end of 2022. In January 2025, the biorefinery started the production of Sustainable Aviation Fuel (SAF) with a capacity of 400,000 tonnes/year. 57 Table of Contents Enilive and PBF Energy Inc. (PBF) own a 50% interest joint venture in St. Bernard Renewables LLC (SBR), an operational biorefinery co-located with PBF's Chalmette Refinery in Louisiana (USA). The biorefinery started with a processing capacity of approximately 1.1 million tonnes/year of feedstock (waste and residues and vegetable oils) with full pre-treatment capabilities. It mainly produces HVO Diesel using the Ecofining™ process developed by Eni in collaboration with Honeywell UOP. In August 2025, LG-Eni BioRefining, the LG Chem and Enilive joint venture, started construction works for the South Korea’s first hydrotreated vegetable oil (HVO) and Sustainable Aviation Fuel (SAF) production plant in Seoul. The plant is scheduled for completion in 2027 and will annually process approximately 400 ktonnes of renewable bio-feedstock. In September 2025, Eni started the authorization process to convert selected units at the Sannazzaro de’ Burgondi (Pavia) refinery into a biorefinery. The project is intended to convert the existing Hydrocracker (HDC2) unit, using Ecofining™ technology and constructing a pre-treatment unit for waste and residues, used by Enilive to produce HVO biofuels. The new biorefinery will have a processing capacity of 550 ktonnes/year, with flexibility to produce SAF-biojet and HVO diesel. In November 2025, Pengerang Biorefinery Sdn. Bhd., the joint venture between Petronas, Enilive and Euglena, started the development of a new biorefinery in Pengerang (Malaysia). The biorefinery with a yearly processing capacity of up to 650 ktonnes of renewable feedstock, is projected to produce Sustainable Aviation Fuel (SAF), Hydrogenated Vegetable Oil (HVO) and bio-naphtha. In 2025, biorefinery throughputs were 1.16 mmtonnes, increasing by 0.04 mmtonnes compared to 2024 (up by 4%), thanks to higher throughputs at Venice and Gela than in 2024, which was impacted by planned maintenance shutdowns. 2025 2024 2023 Bio throughputs (ktonnes) 1,157 1,115 866 Sold production of biofuels 925 982 635 Average biorefineries utilization rate (%) 78 74 72 Marketing Enilive markets a wide range of refined petroleum products, primarily in Italy, through a widespread operated network of service stations, franchises, and other distribution systems. The table below sets forth Eni’s sales of refined products by distribution channel for the periods indicated. Oil products sales in Italy and outside Italy 2025 2024 2023 (mmtonnes) Italy Retail 5.54 5.40 5.32 Wholesale 8.22 9.90 9.83 Other sales 2.61 2.27 2.71 Total sales in Italy 16.37 17.57 17.86 Outside Italy Retail 2.27 2.30 2.20 Wholesale 2.90 2.86 2.73 Total sales outside Italy 5.17 5.16 4.93 TOTAL SALES 21.54 22.73 22.79 In 2025, sales of refined products (21.54 mmtonnes) decreased by 1.19 mmtonnes or 5.2% vs. 2024 as result of lower volumes marketed in Italy. Retail sales in Italy In 2025, retail sales in Italy were 5.54 mmtonnes, up by 0.14 mmtonnes or 2.6% vs. 2024, benefiting from higher volumes of gasoline and diesel sold. Average gasoline and gasoil throughputs (1,451 kliters) were down by 6 kliters vs. 2024 (1,457 kliters). As of December 31, 2025, Eni’s retail network in Italy consisted of 3,982 service stations, higher by 57 units from December 31, 2024 (3,925 service stations), resulting from the positive balance between new openings and contract terminations (+62 units), partially offset by closures in the owned and leased network (-5 units). 58 Table of Contents Retail sales in the Rest of Europe Retail sales in the Rest of Europe were 2.27 mmtonnes, a slight decrease from 2024 (-1.3%) as a result of lower volumes sold mainly in Austria, Germany, France, and Switzerland, partially offset by the improved performance of the distribution network in Spain. At December 31, 2025, Eni’s retail network in the Rest of Europe consisted of 1,312 units, decreasing by 17 units from December 31, 2024, mainly due to reductions registered in Austria and Switzerland. Average throughput (2,140 kliters) decreased by 39 kliters compared to 2024 (2,179 kliters). Other businesses Wholesale and other sales Enilive is strongly present in the wholesale market in Italy, including sales of diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels as well as sales of fuel oil. Major customers are other oil companies, resellers, agricultural users, manufacturing industries, public utilities and transports, as well as final users (transporters, condominiums, farmers, fishers, etc.). Enilive provides its customers with its expertise in the area of fuels with a wide range of products that cover all market requirements. Customer care and product distribution are supported by a widespread commercial and logistical organization presence throughout Italy articulated in local marketing offices and a network of agents and concessionaires. In 2025, sales volumes on wholesale markets in Italy (8.22 mmtonnes) decreased by 17% from 2024, mainly due to lower product availability in specific geographical areas. Wholesale sales outside Italy were 2.90 mmtonnes, up by 1.4% from 2024 particularly in France and Austria, partly offset by the reduction in Germany and Switzerland. Other sales in Italy and outside Italy (2.61 mmtonnes) increased by 0.34 mmtonnes or up by 15%. LPG The LPG marketing activity in Italy is supported by production from Eni’s and Enilive’s refining system (bio-LPG), by product imports through the three coastal depots of Livorno, Naples, and Ravenna, and by Eni’s logistics network. Bottling is managed through five-year tolling contracts at third-party plants or at plants operated in Eni joint ventures. LPG is used as a fuel for heating systems as well as for automotive applications. Lubricants Enilive operates three plants for the production of finished lubricants in Spain, Germany, and the Far East, one of which is run in partnership. With a product range consisting of more than 650 different blends, Enilive boasts one of the highest levels of know-how internationally in the formulation of products for both automotive applications (engine oils, specialty fluids, and transmission oils) and industrial uses (lubricants for hydraulic systems, gears, industrial machinery, and metalworking). In Italy, Enilive SpA is also active in the marketing of additives produced at Eni Industrial Evolution SpA’s lubricant additive manufacturing plant in Robassomero (Turin). Enilive distributes its products in more than 80 countries through subsidiaries, licensing agreements, and distributors. 59 Table of Contents Plenitude Overall, Eni, through Plenitude, supplies around 10 million retail clients (gas and electricity) in Italy and Europe. In particular, clients located all over Italy are 7.9 million. Gas demand Eni operates in a liberalized market where energy customers are allowed to choose the gas supplier and, according to their specific needs, to evaluate the quality of services and offers. Gas and power sales to retail and business customers Gas sales by market 2025 2024 2023 (bcm) ITALY 3.64 3.83 4.11 Retail 2.62 2.71 2.91 Business 1.02 1.12 1.20 INTERNATIONAL SALES 1.65 1.68 1.95 European markets: France 1.22 1.29 1.54 Greece 0.30 0.26 0.26 Other 0.13 0.13 0.15 RETAIL AND BUSINESS GAS SALES 5.29 5.51 6.06 In 2025, retail and business gas sales, in Italy and European markets, amounted to 5.29 BCM, down by 0.22 BCM or 4% from 2024. Sales in Italy amounted to 3.64 BCM, a decrease of 5% (down by 0.19 BCM) compared to 2024, as a result of lower number of gas customers. Sales in the European markets were 1.65 BCM, decreasing by 1.8% (down by 0.03 BCM) compared to 2024. Lower volumes were marketed mainly in France. In Europe, Plenitude operates through the subsidiaries Eni Plenitude France S.A.S. (100% Plenitude interest) in France, Gas Supply Company of Thessaloniki (100% Plenitude interest) in Greece, Adriaplin doo (51% Plenitude interest) in Slovenia and Eni Plenitude Iberia SLU (100% Plenitude interest) in Spain and Portugal. In 2025, retail and business power sales to end customers, managed by Plenitude and its subsidiary companies in France, Greece and Iberian Peninsula, amounted to 18.63 TWh, an increase of 2% from the full year 2024, benefitting from increasing volumes sold in the domestic market. 60 Table of Contents Renewables Eni is engaged in the renewable energy business (solar and wind) aiming at developing, constructing and managing renewable energy producing plants. Eni’s targets in this business will be reached by leveraging on an organic development of a diversified and balanced portfolio of assets, integrated with selective asset acquisitions, as well as projects and national and international strategic partnerships. 2025 2024 2023 (TWh) Energy production sold from renewable sources 5.63 4.67 3.98 of which: photovoltaic 3.29 2.55 1.74 wind 2.34 2.12 2.24 of which: Italy 1.45 1.45 1.53 outside Italy 4.18 3.22 2.45 Energy production from renewable sources amounted to 5.63 TWh in 2025 (of which 3.29 TWh photovoltaic and 2.34 TWh wind) up by 0.96 TWh, or 21% compared to 2024. The increase in production compared to the previous year benefitted mainly from the start-up of organic projects and the contribution from acquired assets. 2025 2024 2023 (gigawatt) Total installed capacity from renewables at period end 5.8 4.1 3.0 of which: - photovoltaic (including installed storage capacity) 74% 71% 64% - wind 26% 29% 36% 2025 2024 2023 (gigawatt) Italy 1.1 1.0 1.0 Outside Italy 4.7 3.1 2.0 United States 1.7 1.7 1.3 Spain 1.6 0.8 0.4 Other (Australia, France, Germany, Greece, Kazakhstan, UK) 1.4 0.6 0.3 TOTAL INSTALLED CAPACITY (INCLUDING INSTALLED STORAGE CAPACITY) * 5.8 4.1 3.0 * Installed storage capacity amounted to 272 MW, 221 MW and 21 MW in the 2025, 2024 and 2023, respectively. At the end of 2025, the total installed capacity for the generation of energy from renewable sources amounted to 5.8 GW (100% Plenitude and including the storage capacity), up by 1.7 GW vs 2024 reflecting the organic development in Spain, the UK, Greece, Italy and Kazakhstan as well as the acquisitions in France and the USA. E-mobility On the back of a mobility market experiencing a constant increase in the number of electric vehicles in circulation in Italy and in Europe, Plenitude disposes one of the largest and most widespread networks of public charging infrastructure for electric vehicles. As of December 31, 2025, there are 22.8 thousand charging points distributed throughout Europe, in particular in Italy, France, Germany, Austria and Switzerland. 61 Table of Contents Refining and Chemicals Competitive trends in the industries where the Company operates Eni’s oil refining business is exposed to structural headwinds of the industry due to muted trends in the European demand for fossil fuels, with expectations of long-term decline due to market penetration of electric vehicles and growing supplies of biofuels, refining overcapacity with new additions expected to come online in the next years or to become operational shortly and continued competitive pressure from players in the Middle East, the United States and Far East Asia. Those competitors can leverage on larger plant scale and cost economies, availability of cheaper feedstock and lower energy expenses. Eni’s refining business is incurring expenses for the purchase of allowances in connection with the emission of CO2 in its operations to comply with the requirements of the European ETS, which reduce the competitiveness of Eni’s fuels with respect to other jurisdictions that do not yet impose those charges to refiners. The refining business is engaged in the processing of crude oil, production, storage and handling of petroleum products in Italy, Germany and the Middle East (through a 20% interest in ADNOC Refining). The business results depend heavily on trends in refining margins, i.e. the spread between the cost of the oil feedstock and the price of the refined products obtained from the crude processing. Eni’s chemical business is exposed to strong competition from well-established international players and state-owned petrochemical companies, considering the commoditized nature of most of the market segments where Eni’s chemicals business operates (such as the production of basic petrochemical products), whose demand is a function of macroeconomic growth. Many of these competitors based in the Far East and the Middle East have been able to benefit from cost economies due to larger plant scale, wide geographic moat, availability of cheap feedstock, lower energy prices and proximity to end markets. Petrochemical producers based in the United States have regained market share, as their cost structure has become competitive due to the availability of cheap feedstock deriving from the production of domestic shale gas from which ethane is derived, which is a cheaper raw material to produce ethylene than the oil-based feedstock utilized by Eni’s petrochemical subsidiaries. Finally, the running of petrochemicals operations in Europe is less competitive than other geographies due to relatively higher energy costs and environmental liabilities, as well as a growing consumers’ preference towards replacing single-use plastics with more sustainable packaging. The weak fundamentals of Eni’s mostly commoditized segments make them more sensitive to the cyclical nature of the industry and overcapacity. In order to reduce Versalis’ exposure to basic chemicals Eni is implementing a transformation and upgrading plan with the aim to recover profitability. An investment plan is currently being executed to develop new chemical platforms in high value downstream activities such as renewables, circular and specialized products, while restructuring efforts are addressing exposure to basic chemicals. As part of the plan, during 2025, the two loss-making cracking units at Priolo and Brindisi were shut down indefinitely. Refining In 2025, the Standard Eni Refining Margin reported an average of 7.3 $/barrel vs. 5.1 $/barrel reported in the comparative period. Refining margins increased driven mainly by more favorable middle distillate crack spreads leveraged by supply disruptions (outages and geopolitical risk) against a backdrop of refinery closures in the Atlantic Basin. Supply In 2025, a total of 16.64 mmtonnes of crude were purchased for the directly supplied refineries by Eni (compared with 16.22 mmtonnes in 2024), of which 2.80 mmtonnes were by equity crude oil. The breakdown by geographic area was the following: 28% of purchased crude came from Central Asia, 26% from North Africa, 9% from West Africa, 8% from the Middle East, 8% from Italy, 4% from the North Sea, and 17% from other areas. 62 Table of Contents Refining In 2025, Eni refinery capacity (balanced with conversion capacity), excluding Adnoc equity-accounted refinery, was approximately 22.2 mmtonnes (equal to 444 KBBL/d), with a conversion index of 53%. The conversion index is a measure of refinery complexity. The higher the index, the wider the range of crude qualities and feedstock that a refinery is able to process thus enabling refineries to benefit from the cost economies arising from the discount – versus the benchmark – at which certain qualities of crude (particularly the heavy ones) may be supplied. Eni’s 100% owned refineries have a balanced capacity of 14.2 mmtonnes (equal to 284 KBBL/d), with a 55% conversion index. In 2025, Eni’s refinery throughputs in Europe on own account were 16.56 mmtonnes. The average refinery utilization rate, ratio between throughputs and refinery capacity, is 80%. Refining system in 2025 Ownership share Capacity (2025) (%) (KBBL/d) Italy Sannazzaro subsidiary 100 180 Taranto subsidiary 100 104 Livorno* subsidiary 100 Milazzo joint-operation 50 100 Outside Italy Germany** Vohburg/Neustadt (Bayernoil) joint-operation 20 41 Schwedt equity-accounted 8.33 19 United Arab Emirates Adnoc Refinery equity-accounted 20 163 Total 607 * Traditional processing operations were shut down in order to convert the plant into a biorefinery. ** Results of the refining activities in Germany are reported within Enilive business. Italy Eni’s refining system in Italy is composed of the wholly-owned refineries of Sannazzaro, Livorno and Taranto, as well as its 50% stake in the Milazzo refinery in Sicily. Eni’s refineries operate to maximize asset value according to market conditions and the integration with marketing activities. The Sannazzaro refinery has a balanced capacity of 180 KBBL/d and a conversion index of 54%. Located in the Po Valley, in the center of Northern Italy, Sannazzaro is one of the most efficient refineries in Europe. The high flexibility and conversion capacity of this refinery allows it to process a wide range of feedstock. The main equipment in the refinery is: two primary distillation columns and two associated vacuum units, three desulphurization units, a fluid catalytic cracker (FCC), two hydrocrackers (HdC), two reforming units, a gasification producing a syngas used in a combined cycle power generation. In January 2026, Eni reached the FID to convert one of the existing Hydrocracker unit, using Ecofining™ technology and to build a pre-treatment unit for waste and residues, used by Enilive to produce HVO biofuels. The new biorefinery will have a processing capacity of 550 ktonnes/year, with flexibility to produce SAF-biojet and HVO diesel. The Taranto refinery has a balanced capacity of 104 KBBL/d and a conversion index of 56%. Taranto has a strong market position due to the fact that it is the only refinery in Southern Continental Italy and is upstream integrated with the Val d’Agri (Eni 61%) and Tempa Rossa fields in Basilicata through a pipeline. The main equipment is a topping-vacuum unit, a residue hydrocracking and a gasoil hydrocracking unit, a platforming unit and two desulphurization units. The Livorno refinery shut down its traditional processing operations in order to convert the plant into a biorefinery. In 2024, Eni obtained the final investment decision and in 2025 signed a finance contract to support the conversion. The project includes the construction of new plants to produce hydrogenated biofuels, including a biogenic pre-treatment unit and a 500 ktonnes/year Ecofining™ plant. The Milazzo refinery (Eni 50%) has a balanced capacity of 100 KBBL/d and a conversion index of 60%. Located in Sicily, Milazzo is mainly dedicated to export and to the supply of Italian coastal depots. The main equipment in the refinery is: two primary distillation columns and a vacuum unit, two desulphurization units, a fluid catalytic cracker (FCC), one hydrocracker (HdC), one reforming unit and one LC fining (ebullated bed residue conversion). 63 Table of Contents Rest of Europe In Germany, Eni owns an interest of 8.33% in the Schwedt refinery (PCK) and an interest of 20% in the Vohburg and Neustadt refineries (Bayernoil). Eni’s refining capacity in Germany is 60 KBBL/d to supply Eni’s distribution network in the country. The table below sets forth Eni’s sales of refined products by distribution channel for the periods indicated. Availability of refined products 2025 2024 2023 (mmtonnes) Italy 14.22 13.76 16.88 of which: At wholly-owned refineries 10.21 10.58 13.31 At account of third parties (1.18) (1.50) (1.32) At affiliated refineries 5.19 4.68 4.89 Outside Italy* 10.72 10.45 10.51 TOTAL THROUGHPUTS ON OWN ACCOUNT 24.94 24.21 27.39 *Results of the refining activities in Germany are reported within Enilive business. In 2025, Eni’s refining throughputs on own account were 24.94 mmtonnes, increasing by 3% from 2024 following the higher processing in particular, the higher volumes processed in Milazzo and Sannazzaro, due to lower shutdowns compared to the comparative period, more than offset the lower volumes at the Livorno refinery following a new production structure. The refinery utilization rate, ratio between throughputs and refinery capacity, is 80%. Approximately 17% of processed crude was supplied by Eni’s Exploration & Production segment, representing a decrease from 2024 (31%). Other businesses Logistics Eni is a leading operator in the Italian oil and refined products storage and transportation business. Oil and refined products are transported: (i) by sea through spot and long-term contracts of tanker ships; and (ii) inland through a proprietary pipeline and depots network directly operated. In particular, Eni owns and operates an integrated infrastructure consisting of 15 directly managed depots. Eni also owns a network of oil and refined products pipelines extending approximately 1,200 kilometers operating. Eni logistic model is organized in four operational management units (Northern depots, Central depots, Southern depots and LPG and Pipeline) operating in handling and storage of the product flows in order to guarantee high safety, asset integrity and technical standards (HSE and asset integrity), as well as cost optimization and constant products availability along the country. Eni is also part of 7 different logistic joint ventures (Sigemi, Seram, Disma, Seapad, Toscopetrol, Porto Petroli Genova and Costiero Gas Livorno), together with other Italian operators, that operate other localized depots and pipelines. Secondary distribution is outsourced to independent trucks, selected as market leaders. Oxygenates Eni, through its subsidiary Ecofuel (100% Eni’s share), sells approximately 1 mmtonne/y of oxygenates, mainly ethers (approximately 1.6% of world demand, used as a gasoline octane booster) and methanol (mainly for petrochemical use). About 77% of oxygenates are produced in Eni’s plants in Italy (Ravenna), Saudi Arabia (in joint venture with Sabic) and Venezuela (in joint venture with Pequiven) and the remaining 23% is purchased. 64 Table of Contents Chemicals In 2025, sales of chemical products amounted to 2,719 ktonnes, declining from 2024 (down by 450 ktonnes, or 14.2%), in particular, the main decreases were recorded in the chemicals area (olefines, aromatics and fenol derivatives) and in polymers (polyethylene, styrenics and elastomers). Average sale prices of the intermediates business decreased by 4% overall from 2024, in line with the weakening of the European scenario. Chemical production amounted to 4,105 ktonnes (down by 1,580 ktonnes vs. 2024) and was affected by lower production of intermediates (down by 1,347 ktonnes), particularly olefins, following the shutdown of the cracking plants in Brindisi and Priolo. The average plant utilization rate, calculated on nominal capacity, was 49%, down 1.3 percentage points compared to the previous year. The table below sets forth Eni’s main chemical products availability for the periods indicated. Year ended December 31, 2025 2024 2023 (ktonnes) Intermediates 2,504 3,851 3,877 Polymers 1,321 1,559 1,658 Biochem 207 206 57 Moulding & Compounding 73 69 71 Total production 4,105 5,685 5,663 Consumption losses (2,359) (3,106) (3,247) Purchases and change in inventories 973 590 701 Chemical products availability 2,719 3,169 3,117 The table below sets forth Eni’s main chemical products sales for the periods indicated. Year ended December 31, 2025 2024 2023 (ktonnes) Intermediates 1,432 1,720 1,651 Polymers 1,082 1,255 1,350 Oilfield chemicals 25 14 21 Biochem 110 116 28 Moulding & compounding 70 64 67 Total sales 2,719 3,169 3,117 65 Table of Contents Revenues from the Biochemistry business, amounting to €279 million, were mainly generated by Novamont (€271 million) and the Crescentino plant (€8 million). Compared to 2024, the Novamont Group reported a reduction in both sales volumes (-7.4%) and revenues. Revenues from the Moulding & Compounding business, amounted to €267 million and were broken down into moulding activities for €83 million, compounding for €72 million, and cable & wire activity for €112 million. Revenues from the oilfield chemicals business amounted to €90 million, an increase of 15.4% compared to 2024, mainly attributable to growth in sales volumes (+78.6%), partially offset by stable sales prices. Revenues from polymers (€1,633 million) decreased by 17.4% compared to 2024, impacted by lower sales volumes (-173 ktonnes) and lower average sales prices (-3%), partly offset by the increase in sales volumes recorded in the styrene business (+30%). In 2025, following the shutdown of the Brindisi and Priolo crackers, both production (-35%) and sales (-17%) reported a reduction compared to 2024. Capital expenditures See “Item 5 – Liquidity and capital resources – Capital expenditures by segment”. 66 Table of Contents Corporate and Other activities These activities include the following businesses: ● the “Other activities” segment comprises results of operations of Eni’s subsidiary Eni Rewind (former Syndial SpA) which runs reclamation and decommissioning activities pertaining to certain businesses which Eni exited, divested or shut down in past years; and ● the “Corporate and financial companies” segment comprises results of operations of Eni’s headquarters and certain Eni subsidiaries engaged in treasury, finance and other general and business support services. Eni’s headquarters is a department of the parent company Eni SpA and performs Group strategic planning, human resources management, finance, administration, information technology, legal affairs, international affairs and corporate research and development functions. It also includes the results of the CO2 Capture, Storage and Utilisation and Agri-business, which is under development. Through Eni’s subsidiaries Banque Eni SA, Eni International BV, Eni Finance USA Inc and Eni Insurance DAC, Eni carries out cash management activities, administrative services to its foreign subsidiaries, lending, factoring, leasing, financing Eni’s projects around the world and insurance activities, principally on an intercompany basis. Eni Servizi, Eni Corporate University, AGI and other minor subsidiaries are engaged in providing Group companies with diversified services (mainly services including training, business support, real estate and general purposes services to Group companies). Management does not consider Eni’s activities in these areas to be material to its overall operations. Seasonality Eni’s results of operations reflect the seasonality in demand for natural gas and certain refined products used in residential space heating, the demand for which is typically highest in the first quarter of the year, which includes the coldest months and lowest in the third quarter, which includes the warmest months. Moreover, year- to-year comparability of results of operations is affected by weather conditions affecting demand for gas and other refined products in residential space heating. In colder years, which are characterized by lower temperatures than historical average temperatures, demand for gas and products is typically higher than normal consumption patterns, and vice versa. 67 Table of Contents Research and development Eni’s research and technological innovation constitute a structural component of its business model and a key enabler of the energy transition. They support reliable and efficient access to new energy resources, enhance the performance of existing assets and contribute to the progressive reduction of environmental impact. In 2025, Eni invested €207 million in scientific research and technological innovation (€178 million in 2024), of which approximately €165 million, equal to around 80 percent (as in 2024), allocated to process decarbonization, circular economy initiatives, renewable energy and magnetic confinement fusion. Process decarbonization remains a primary focus, encompassing technologies for CO2 reduction, capture, utilization and storage, improvements in energy efficiency and the promotion of low carbon energy carriers. Circularity and bio-based solutions represent another core direction, with initiatives aimed at minimizing waste, increasing recycling and reuse, and converting residual streams into value-added products for biorefineries, sustainable mobility and bio-based chemicals. At the same time, Eni advances renewable energy systems, storage solutions and breakthrough technologies, while pursuing operational excellence through innovations that increase efficiency and safety, reduce environmental footprint and shorten development cycles. Open innovation, venture capital, venture building and technology insourcing have complemented internal research, reinforcing Eni’s ability to capture external innovation and accelerate its industrial deployment. This integrated and cross-functional approach enhances value creation by reducing time to market and by positioning innovation as a transversal lever across all business lines, from upstream to downstream, including biorefineries and new energy production models. In 2025, Eni filed 42 patent applications (39 in 2024). 68 Table of Contents Research and Development in Eni is characterized by three main factors: in-house expertise, Open Innovation model and development of the entire technology chain. About 1,000 researchers are engaged in research activities, with expertise ranging from upstream to downstream, from renewables to the environment. This knowledge base is complemented by a network of 70 national and international universities and research centers and becomes even more effective with an opening to the market and to startups, both in Italy and abroad, through Joule (startup accelerator) and Eni Next (Corporate Venture Capital). Eni’s approach in research and development is aimed at enhancing the entire technology value chain: thorough identification of a portfolio of technology solutions to be provided to the business, to meet the challenges of an evolving world with important decarbonization goals, and the definition of an approach to accelerating the industrial deployment of technologies, also through financial instruments or specific vehicles, such as the setup of Eniverse, Eni corporate venture building company. In this way, Eni Innovation follows all stages of the process: while we develop proprietary technologies already applicable to our businesses to increase efficiency, we continue to support the search for innovative solutions for business of tomorrow and to make access to energy resources more efficient and sustainable, contributing to the reduction of the carbon footprint. The company adopts a synergistic approach, involving all its expertise to address the challenges of an energy sector in constant evolution. One of the key areas of interest is CCUS (Carbon Capture, Utilization, and Storage), with the goal of covering the entire carbon chain: from capture to transport, storage, and utilization. In particular, the focus is on the capture phase, where we are evaluating different technological solutions to increase process efficiency. Another key aspect is the development of bio-based and low-carbon products. The goal is to replace, or at least integrate, fossil raw materials with renewable or biologically sourced resources, in order to produce fuels and other materials with lower emissions. At the same time, the company is committed to improving renewable energies and storage systems. Research focuses on optimizing solar and wind energy technologies, also evaluating new renewable sources and developing advanced systems to ensure stable and continuous supply. Regarding storage, studies aim to enhance the performance of batteries and thermal storage systems, to better integrate them into existing grids. Eni's innovation also extends to bio-based, circular, compounding, and polymer materials, with a significant commitment to creating more sustainable materials for sectors such as packaging, automotive, and construction. Finally, the focus is also on the research of advanced polymers, designed to address the challenges of electric mobility, renewable energy, and lightweight materials for innovative structures. Another pillar of the strategy is environmental and water resource management, as we invest in innovative solutions for soil remediation and the sustainable management of water, a key element of the energy transition. One of the main objectives is the reuse of wastewater, thus contributing to the circular management of water resources. In the field of fusion, research focuses on the development of innovative materials capable of withstanding extreme conditions and optimizing the systems necessary for the efficient and safe operation of future reactors. The goal is to improve the performance and reliability of these technologies, contributing to the progress of a possible sustainable energy source for the future. Finally, we work towards operational excellence, developing solutions to improve safety, reliability, and sustainability of industrial activities. The strategy includes the adoption of advanced technologies for plant monitoring, predictive maintenance, and energy consumption optimization. Furthermore, decarbonization is at the heart of corporate initiatives, with the integration of carbon capture and storage solutions and the increasing use of renewable sources throughout the entire energy value chain. 69 Table of Contents Insurance In order to control the insurance costs incurred by each of Eni’s business units, the Company constantly assesses its risk exposure in both Italian and foreign activities. The Company has established a captive subsidiary, Eni Insurance DAC, in order to efficiently manage transactions with mutual entities and third parties providing insurance policies. Internal insurance risk managers work in close contact with business units in order to assess potential underlying business and other types of risks and possible financial impacts on the Group’s results of operations and liquidity. This process allows Eni to accept risks in consideration of results of technical and risk mitigation standards and practices, to define the appropriate level of risk retention and, finally, the amount of risk to be transferred to the market. Eni enters into insurance arrangements through its shareholding in the Everen Ltd (a mutual insurance and re-insurance company that provides its members with a broad coverage of insurance services tailored to the specific requirements of oil and energy companies) and with other insurance partners in order to limit possible economic impacts associated with damages to own property and third parties, including pollution, occurring in case of both onshore and offshore accidents. The main part of this insurance portfolio is related to operating risks associated with oil&gas operations which are insured making use of insurance policies provided by the Everen Ltd. In addition, Eni uses reputable, high quality insurance companies which are well established in the market. Insured liabilities vary depending on the nature and type of circumstances; however, underlying amounts represent significant shares of the plafond granted by insuring companies. In particular, in the case of oil spills and other pollution damage, current insurance policies cover costs of cleaning-up and remediating polluted sites, damage to third parties and containment of physical damage up to $1.2 billion for offshore events and $1.4 billion for onshore plants (refineries). These are complemented by insurance policies that cover owners, operators and renters of vessels with the following maximum amounts: $1.3 million for tankers and charters and up to $1 billion for FPSOs used by the Exploration & Production segment for developing offshore fields. Management believes that the level of insurance maintained by Eni is generally appropriate for the risks of its businesses. However, considering the limited capacity of the insurance market, we believe that Eni could be exposed to material uninsured losses in case of catastrophic incidents, like the one that occurred in the Gulf of Mexico in 2010 which could have a material impact on our results, liquidity prospects, share price and reputation. See “Item 3 — Risk factors — Risk associated with the exploration and production of oil and natural gas”. Environmental matters Environmental regulation Eni is subject to numerous EU, international, national, regional and local environmental, health and safety laws and regulations concerning its oil&gas operations, products and other activities, including legislation that implements international conventions or protocols. In particular, exploration, drilling and production activities require acquisition of a special permit that restricts the types, quantities and concentration of various substances that can be released into the environment. The particular laws and regulations can also limit or prohibit drilling activities in certain protected areas or provide special measures to be adopted to protect health and safety at workplace and health of communities that could have been affected by the Company’s activities. These laws and regulations may also restrict emissions and discharges to surface and subsurface water resulting from the operation of natural gas processing plants, petrochemical plants, refineries, pipeline systems and other facilities that Eni owns. In addition, Eni’s operations are subject to laws and regulations relating to the production, handling, transportation, storage, disposal and treatment of waste materials. Environmental laws and regulations have a substantial impact on Eni’s operations. Some risk of environmental costs and liabilities is inherent in certain operations and products of Eni, and there can be no assurance that material costs and liabilities will not be incurred. See “Item 3 – Risk factors”. We believe that the Company will continue to incur significant amounts of expenses to comply with regulations and to protect the environment, the health and the safety; particularly in order to achieve any mandatory or voluntary reduction in the emission of GHG in the atmosphere, cope with climate change and pursuing minimal impacts on quality and availability. The Group balance sheet has accrued the expenses for environmental liabilities in place at the closing date, which will likely require a disbursement on part of the Company in future reporting periods and for which a reliable estimate can be made. 70 Table of Contents Management believes that it is possible that in the future Eni may incur significant or material environmental expenses and liabilities in addition to the amounts already accrued due to: (i) the likelihood of yet unknown contamination; (ii) the results of ongoing surveys or surveys to be carried out on the environmental status of certain Eni’s industrial sites as required by the applicable regulations on contaminated sites; (iii) unfavourable developments in ongoing litigation on the environmental status of certain of the Company’s sites where a number of public administrations, the Italian Ministry of the Environment or third parties are claiming compensation for environmental or other damages such as damages to people’s health and loss of property value; (iv) the possibility that new litigation might arise; (v) the probability that new and stricter environmental laws might be implemented; and (vi) the circumstance that the extent and cost of environmental restoration and remediation programs are often inherently difficult to estimate leading to underestimation of the future costs of remediation and restoration, as well as unforeseen adverse developments both in the final remediation costs and with respect to the final liability allocation among the various parties involved at the sites. International and European Union Environmental Laws Framework At global level, the most important policy framework to strengthen the global response to the threat of climate change is the Paris Agreement, an international treaty, entered into force on November 4, 2016. Although the Paris Agreement does not apply directly to Eni, it includes commitments from all countries to reduce their emissions and work together to adapt to the impacts of climate change, and calls on countries to strengthen their commitments over time. In this context, during the UN Climate Change Conference of Parties (COP 28), taken place in Dubai in 2023, the Parties agreed to “transitioning away from fossil fuels in energy systems, in a just, orderly and equitable manner, accelerating action in this critical decade, so as to achieve net zero by 2050 in keeping with the science”. In case this goal is effectively pursued by the Parties through policies and regulations, than hydrocarbons demand could decrease in the medium to long term, coupled with a potential increase of operational expenses for the O&G sector. On the other side, the final decision of COP28 highlights also some important levers for the decarbonization of the energy system that could represent business opportunities for Eni, such as renewables, Carbon Capture and Storage, low carbon hydrogen, transitional fuels, nuclear energy. Alongside the COP28, several initiatives have been launched or strengthened. Among them, Eni supported (i) the Global Flaring and Methane Reduction (GFMR) Partnership, a new multi-donor trust fund focused on helping developing countries cut carbon dioxide and methane emissions generated by the oil and gas industry and (ii) the Oil and Gas Decarbonization Charter (OGDC), where Signatories have committed to net-zero operations by 2050 at the latest, and ending routine flaring by 2030, and near-zero upstream methane emissions. Regarding the European Union (EU), during 2023, almost all new or emended directives and regulations, proposed in the "Fit for 55" package (July 2021) entered into force, among which the most impactful are: (i) 42.5% renewable share in the overall energy consumption by 2030; (ii) 40% GHG reduction for non-ETS sectors by 2030 vs 2005 and 62% GHG reduction for ETS sectors by 2030 vs 2005; (iii) 11.7% reduction in energy consumption by 2030, compared to the 2020 reference scenario at EU level. Within the revised Renewable Energy Directive (RED III), the EU institutions established also a new binding and challenge target for transport sector set at 29% renewable share in the final energy consumption of the transport sector by 2030 or alternatively a 14,5% reduction in GHG intensity compared to a fossil fuel baseline. The new Directive also requires Member States to increase the consumption of advanced biofuels and of Renewable Fuels of Non-Biological Origin (RFNBO) to 5.5% in 2030, of which at least 1% from RFNBO. In a separate regulation, the EU regulator also introduced a minimum blending mandate for Sustainable Aviation Fuels and a limit to the carbon intensity of the energy used on board ships, to support the uptake of sustainable maritime fuels. These mandates coupled with adequate incentives could increase the demand of sustainable biofuels that Eni is already committed to supply to the market. Regarding the ETS directive, main changes that, if implemented, could impact Eni are the (i) scope extension to the building, road transport and shipping sectors, (ii) downward revision of the cap (iii) potentially fewer free allowances allocation due to a revision of the emissions benchmark. EU also adopted the new Carbon Border Adjustment Measure (CBAM) aimed at ensuring a level playing field between EU and non-EU installations, thus securing the EU industrial competitiveness, in the following sectors cement, electricity, fertilisers, iron and steel, aluminum and hydrogen. However, for the time being, Eni operations are only marginally covered by the CBAM. 71 Table of Contents In the energy efficiency field, the directive of September 2023 introduces a series of measures and embraces the “energy efficiency first” principle. The main features and changes from the previous directive include: ● increasing annual energy savings from 0.8% (at 2023) to 1.3% (2024-2025), then 1.5% (2026-2027) and 1.9% from 2028; ● introducing an annual energy consumption reduction target of 1.9% for the public sector; ● extending the annual 3% buildings renovation obligation to all the levels of public administration; ● introducing a different approach, based on energy consumption, for business to have an energy management system or to carry out energy audits; ● bringing in a new obligation to monitor the energy performance of data centres, with an EU-level database collecting and publishing data. ● promoting local heating & cooling plans in larger municipalities. Progressively increasing the efficient energy consumption in heat or cold supply, also in district heating. From 2022, the efforts of the European Commission legislators focused on several proposals to support enhanced non-financial disclosure obligations for financial market participants, financial advisors and large corporations. On February 23, 2022, the European Commission published its proposal for a Directive on Corporate Sustainability Due Diligence that on July 25, 2024 came into force (Directive No. 2024/1760, later modified by Directive 2025/794). The new rules apply to large EU companies and large non-EU companies. The directive aims to promote sustainable and responsible business conduct in companies' operations and throughout their value chains. Companies must ensure the identification and assessing of actual or potential adverse impacts and, where necessary, prioritising actual and potential adverse impacts; preventing and mitigating potential adverse impacts, and bringing actual adverse impacts to an end and minimising their extent; providing remediation for actual adverse impacts. The core elements of this duty are identifying and addressing potential and actual adverse human rights and environmental impacts in the company’s own operations, their subsidiaries and, where related to their value chain(s), those of their business partners. Furthermore, the directive establishes the obligation to adopt and implement a transition plan for climate change mitigation, in line with the Paris Agreement’s goal of climate neutrality by 2050, as well as the intermediate targets set by EU climate legislation. The Corporate Sustainability Reporting Directive (CSRD) is another key initiative of the Green Deal for Europe and is part of a broader regulatory framework concerning non-financial disclosure requirements. On 5 January 2023, Directive 2022/2464/EU came into force, updating the EU rules on corporate sustainability disclosures by broadening the scope and introducing detailed reporting requirements, also with a view to combating greenwashing. Companies subject to the CSRD shall report according to European Sustainability Reporting Standards (ESRS), which are currently undergoing a revision and simplification process further to the “Omnibus I” Draft directive. The standards were published in the Official Journal on 22 December 2023 under the form of a delegated regulation. The CSRD amends Directive 2013/34/EU on non-financial business information by introducing ad hoc provisions on corporate sustainability reporting. In Italy, the CSRD was transposed on September 6, 2024, via Legislative Decree No. 125. Eni, among the first companies affected, has published the “Sustainability Report" in line with ESRS since 2025 (for the 2024 reporting year), replacing its Non-Financial Disclosure (DNF), with the relevant data disclosed within the Management Report (Eni’s Consolidated Financial Statements). Air quality remains at the center of the European environmental policies and strategies. In 2019 the European Commission has completed a fitness check of the two EU Ambient Air Quality (AAQ) Directives (Directives 2008/50/EC and 2004/107/EC). In October 2022, the Commission proposed stronger rules on ambient air quality, setting interim 2030 EU air quality standards more closely aligned with the 2021 World Health Organization guidelines, aiming for zero air pollution by 2050 in synergy with climate-neutrality efforts. A key change was the tightening of the annual limit value for fine particulate matter (PM2.5) to 10 µg/m³ by 2030, down from the previous 25 µg/m³ limit. In 2024, the EU legislature introduced further measures to progressively improve air quality to levels no longer harmful to human health, natural ecosystems, and biodiversity, while enhancing public access to information and strengthening the assessment of air quality by a representative high-quality monitoring network. On October 23, 2024, Directive 2024/2881 on ambient air quality was published, reinforcing implementation and tightening permissible pollutant levels to align more closely with WHO recommendations by 2030. Additionally, Regulation 2024/1244, in force since May 22, 2024, replaces Regulation (EC) No. 166/2006 and will apply from January 1, 2028. It establishes a European emissions portal to enhance industrial facility environmental data reporting. Lastly, Directive 2024/1785, effective August 4, 2024, amends Directive 2010/75/EU on industrial emissions (integrated pollution prevention and reduction) and the 1999/Ce Directive on the landfill of waste. Member States must transpose into national law by July 1, 2026. The main areas of improvement include: 72 Table of Contents • Innovation and transformation through the most effective viable emissions reduction techniques. • Tightened rules on reducing emissions with stricter emissions limit values and more stringent conditions on granting derogations. • Access to environmental data (new Industrial Emissions Portal Regulation). • Address Circular economy and resource efficiency, as well as reducing the use of hazardous chemicals. • Coverage of activities to reduce unregulated emissions. • Rights of the public by strengthening and broadening public information, participation and access to justice. The Industrial Emission Directive (IED) 2010/75/EU provides the framework for granting permits and lays down rules on the integrated prevention and control of air, water and soil pollution arising from industrial activities. As part of the IED framework, additional emission limit values are defined by the sector specific and cross sector Best Available Technology (BAT) Conclusions. On May 12, 2021, the European Commission adopted the EU Action Plan: "Towards a Zero Pollution for Air, Water and Soil" (and annexes) - a key deliverable of the European Green Deal whose objectives are “The zero pollution vision for 2050 is for air, water and soil pollution to be reduced to levels no longer considered harmful to health and natural ecosystems, that respect the boundaries with which our planet can cope, thereby creating a toxic-free environment”. In July 2021 the conclusion of the EU consultation on the revision of the Wastewater Directive was published. On October 25, 2022, the European Commission published the proposal for the new Urban Wastewater Treatment Directive (UWWTD). The revised Urban Wastewater Treatment Directive, which entered into force on 1 January 2025, protects human health and the environment from the effects of untreated urban wastewater. It requires EU countries to ensure that towns and cities properly collect and treat wastewater cost-effectively. It aims to: • Improve water quality through stricter water treatment and the inclusion of new pollutants; • Strengthen the EU’s polluter-pays principle by ensuring that those responsible for pollution bear the costs of remediating it; • Advance circularity through water reuse and the recovery of valuable resources from wastewater; • Address climate change through GHG emission reduction of treatment plants and urban adaptation to heavy rainfall; • Ensure access to sanitation for all, particularly the most vulnerable and marginalised. The Waste Framework Directive (2008/98/EU was revised by the Directive (EU) 2025/1892, which entered into force on 16th October 2025 and introduced new rules for textiles, including extended producer responsibility (EPR); moreover, it set binding food waste reduction targets for Member States. On April 11, 2024, the European Parliament and of the Council approved the Regulation (EU) 2024/1157 on shipments of waste, which entered into force on 20 May 2024; most provisions will apply from May 21, 2026 and most export rules will apply from May 21, 2027; until then, the provisions of Waste Shipment Regulation 1013/2006 continue to apply. The new Regulation sets stricter rules on waste export, also requiring independent audits in the facilities outside the EU, to strengthen the contrast to illegal shipments and to facilitate the waste shipments in the internal market of EU, also through the digitalization of procedures. Shipments of plastic waste are subject to a specific regime. Other waste suitable for recycling will be exported from the EU to non-OECD countries only when they ensure that they can deal with it in a sustainable manner, by the mean of independent audits. On February 11, 2025, the Packaging and Packaging Waste Regulation 2025/40 (PPWR) entered into force; its general date of application is 18 months after that. It regulates what kind of packaging can be placed on the EU market, as well as packaging waste management and prevention measures, aiming to minimize the quantities of packaging and waste generated while lowering the use of primary raw materials and fostering the transition to a circular, sustainable and competitive economy. The PPWR replaces the Packaging and Packaging Waste Directive 94/62/EC (PPWD) and harmonises national measures further - strengthening the internal market - notably for secondary raw materials, manufacturing, recycling and reuse. Those measures could lead to increased operating expenses for Eni, but they are not expected to have a significant impact on the Group’s results. 73 Table of Contents European Union Health and Safety Laws Framework With Law 215/2021 several updates were introduced into Legislative Decree 81/08 on coordination, supervision, training, and enforcement. Further amendments followed with Laws 51/2022, 85/2023, 170/2023, 191/2023, 214/2023, 56/2024, and 203/2024. In 2025, additional changes were introduced through Decree Law 159/2025, converted into Law 198/2025, strengthening: ● general rules for construction site access; ● health and safety obligations; ● near miss management; ● health surveillance; ● PPE and work at height rules; ● training and the electronic worker file, On June 1, 2007, the REACH Regulation of the European Union came into force (Regulation (EC) No. 1907/2006 concerning the Registration, Evaluation, Authorization and Restriction of Chemicals). The Commission is currently reviewing the REACH Regulation, through a public consultation aimed at SMEs, citizens and stakeholders to obtain opinions on the expected impacts of the envisaged changes. The Commission proposed major reforms, including 10-year registration validity, digital SDSs, and a Mixture Assessment Factor (MAF) for high-tonnage substances, aiming for simplification but sparking industry cost concerns. The overall objective of this revision is to ensure that the provisions of the REACH Regulation reflect the Commission's innovation ambitions for safe and sustainable chemicals and a high level of health and environmental protection, while preserving the internal market, as foreseen in the Chemical Strategy for Sustainability adopted on October 14, 2020. This strategy is part of the EU's zero pollution ambition, a key commitment of the European Green Deal, and aims to better protect citizens and the environment from harmful chemicals as well as stimulate innovation by promoting the use of safer and more sustainable chemicals. The European Chemicals Agency (ECHA) contributes to the implementation of the strategy with its scientific and regulatory expertise, databases, digital tools and networks, and practical experience in chemicals regulation, where necessary. The European Regulations are constantly evolving and this results in the publication of adjustments and delegated regulations on specific topics with large impact on Eni and the companies that produce and market products. Some examples of such updates are those reported below: 74 Table of Contents - Regulation (EU) 2024/2865, adopted on October 23, 2024, amends the CLP Regulation (EC) No 1272/2008. This amendment introduces significant changes, including new instructions for classifying complex substances - referred to as 'substances containing more than one constituent' (MOCS) - and updates to labelling formats by adding Chapter 3 to Title III of the CLP Regulation. The regulation entered into force on December 10, 2024, and will be implemented in phases, with the first provisions applying from July 1, 2026. The remaining requirements will come into full effect on January 1, 2027. - Commission Delegated Regulation (EU) 2025/1222 of April 2, 2025 amending Regulation (EC) No 1272/2008 of the European Parliament and of the Council as regards the harmonised classification and labelling of certain substances. This is the ATP 23 of CLP regulation, which will be applicable starting February 1st, 2027. Moreover, an ex-ante verification of SME status has been introduced: companies must submit a recognition request at least two months before applying for any procedure entitling them to a reduced fee. ECHA must issue a decision within two months of receiving complete documentation. The fee adjustment will enter into force on November 5, 2025, i.e. 20 days after publication, while the new provisions on SME verification and fee reductions will apply from February 5, 2027 - 15 months after entry into force. - On the 5th of November 2025, the ECHA (European Chemicals Agency) released the new Candidate List of SVHCs with the addition of a new substance. The current list of SVHCs now contains 251 substances. - Regulation (EU) 2025/2439, introducing urgent amendments to the 2024 revision of the Regulation on Classification, Labelling and Packaging of Substances and Mixtures (CLP Regulation), (EU) 2024/2865. In specific, the regulation regards the dates of application and transitional provisions (“Stop of the clock”). - Regulation (EU) 2025/2455 establishing a common data platform on chemicals, laying down rules to ensure that the data contained therein are findable, accessible, interoperable and reusable, and establishing a monitoring and outlook framework for chemicals. - Evolution on PFAS (Per- and polyfluoroalkyl substances) regulation and restrictions that involved about 10000 substances. ECHA’s scientific committees are currently evaluating the proposal for global restriction regarding all PFAS in terms of the risks to people and the environment, and the impacts on society. On October 2, 2025, the Directive No. 2025/1988/EU was issued. This regulation amends Annex XVII of REACH to address the environmental and health risks of "forever chemicals" (PFAS) used in firefighting applications. It introduces a new restriction under for all Per-and Polyfluoroalkyl Substances (PFAS) in firefighting foams. • A general concentration limit of 1 mg/L (1 ppm) for the sum of PFAS is established for placing on the market and use. • The general prohibition for most uses begins on October 23, 2030. • Portable fire extinguishers must comply by October 23, 2026, or April 23, 2027, for alcohol-resistant foams. • Use for training and testing is prohibited from April 23, 2027, unless all releases are fully contained and treated. • Municipal fire services are banned from using these foams starting April 23, 2027, except when responding to fires at industrial sites. • Critical sectors such as Seveso III industrial sites, offshore installations, and military vessels have an extended transition period until October 23, 2035. • Starting October 23, 2026, any permitted PFAS-containing foam must carry a specific warning label. • Professional users must implement a PFAS Management Plan to track stocks and outline the transition to fluorine-free alternatives. • All firefighting water and foam waste containing PFAS must be collected and disposed of using specialized treatment methods. • A temporary residual limit of 50 mg/L is permitted for equipment that has undergone decontamination procedures to switch to PFAS-free foam. Compliance with REACH requirements and the involvement of all stakeholders in the Company are coordinated and supervised by the HSEQ/Product Safety function. European institutions have also increased their activities in the area of environmental protection in the field of hydrocarbon extraction. On June 12, 2013, the Directive No. 2013/30/EU was issued with the aim of replacing the existing National Legislations and uniform the legislative approach at European level. The Directive, also named Offshore Directive, was transposed into Italian law by means of Legislative Decree 145 of August 18, 2015. 75 Table of Contents The main elements of the EU Directive are the following: ● The Directive introduces licensing rules for the effective prevention of and response to a major accident. The licensing authority in Member States will have to make sure that only operators with proven technical and financial capacities are allowed to explore and produce oil&gas in EU waters. Public participation is expected before exploratory drilling starts in previously un-drilled areas. ● Independent national competent authorities, responsible for the safety of installations, are in charge of verifying the provisions for safety, environmental protection, and emergency preparedness of rigs and platforms and the operations conducted on them. Enforcement actions and penalties apply in case of non-compliance with the minimum set standards. ● Obligatory emergency planning calls for companies to prepare reports on major hazards, containing an individual risk assessment and risk-control measures, and an emergency response plan before exploration or production begins. These plans have to be submitted to National Authorities. ● Technical solutions presented by the operator need to be verified independently prior to and periodically after the installation is taken into operation. ● Companies are required to publish on their websites information about standards of performance of the industry and the activities of the national competent authorities, as well as reports of offshore incidents. ● Companies are required to prepare emergency response plans based on their rig or platform risk assessments and keep resources at hand to be able to put them into operation when necessary. These plans are periodically tested by the industry and National Authorities. ● Oil and gas companies are fully liable for environmental damage caused to the protected marine species and natural habitats. For damage to waters, the geographical zone is extended to cover all EU waters including the exclusive economic zone (about 370 km from the coast) and the continental shelf, where the coastal Member States exercise jurisdiction. For water damage, the present EU legal framework for environmental liability is restricted to territorial waters (about 22 km offshore). ● Operators working in the EU are required to demonstrate they apply the same accident-prevention policies overseas as they apply in their EU operations. We believe that Eni operations are currently in compliance with all those regulations in each European country where they have been enacted. The Company has been adopting for years standard practices and operating procedures to reduce risks of incidents and adverse events in its oil&gas operations, particularly offshore, which we believe to be adequate to scale, reach, geographical location and complexity of our operations. Adoption of stricter regulation both at national and European or international level and the expected evolution in industrial practices would trigger cost increases to comply with new HSE standards. Eni exploration and development plans to produce hydrocarbon reserves and drilling programs could also be affected by changing HSE regulations and industrial practices. Moreover, in order to achieve the highest safety standards of our operations in the Gulf of Mexico, Eni entered into a consortium led by Helix that worked at the containment of the oil spill at the Macondo well. The Helix Well Containment Group (HWCG) performs certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline. 76 Table of Contents Worldwide Eni approach was to join international consortiums for main equipment and to develop in-house technologies to improve the intervention capability. Eni Emergency Response Kit consists of: ● Outsourced equipment contracted by Eni Head Quarter; ● Access Agreement to Subsea Capping Equipment consortium; ● Access Agreement to Global Dispersant Stockpile consortium; ● Eni Head Quarter proprietary equipment; ● Rapid Cube; ● Killing System relating to drilling operations. In addition to the above, Eni is a participant member of Oil Spill Response Limited, the largest international industry-funded cooperative which exists to respond to oil spills wherever in the world they may occur, by providing preparedness, response and intervention services. As regards major accidents, the Seveso III (Directive No. 2012/18/EU) was adopted on July 4, 2012 and entered into force on August 13, 2012. Italy has transposed it into national legislation through the Legislative Decree No. 105/2015 (June 26, 2015). The main changes in comparison to the previous Seveso Directive are: ● technical updates to take into account the changes in EU chemical classification, mainly regarding the 2008 European CLP Regulation of substances and mixtures; ● expanded public information about risks resulting from Company activities; ● modified rules in participation by the public in land-use planning projects related to Seveso plants; and ● stricter standards for inspections of Seveso establishments. ● Eni has carried out specific activities aimed at guaranteeing the compliance of its own industrial site. HSE activity for the year 2025 Eni is committed to continuously improving its model for managing health, safety and environmental issues across all its businesses in order to minimize risks associated with its own industrial activities, ensure reliability of its industrial operations and comply with all applicable rules and regulations. In 2025, Eni’s business units continued to obtain certifications of their management systems, industrial installations and operating units according to the most stringent international standards. The total number of certifications achieved was 347, of which: ● 101 certifications according to the ISO 14001 standard; ● 10 registrations according to the EMAS regulation; ● 37 certifications according to the ISO 50001 standard (certification for an energy management system); ● 107 according to the new ISO 45001 standard; ● 48 according to the ISO 9001 standard (certification of the quality management system). 77 Table of Contents In 2025 the percentage of Eni industrial installations and operating units with a significant HSE risk covered by certification is 94% for the ISO 45001 standard and 93% for the ISO 14001 standard. In 2025, total HSE expenses (including cross-cutting issues such as HSE management systems implementation and certification, etc.) amounted to €1,918 million (up by 23% vs 2024). Environment In 2025, Eni incurred total expenditures of €1,541 million for the protection of the environment (with an increase of 34% with respect to 2024). Environmental expenditures are mainly related to remediation and reclamation activities (€617 million), flaring down (€346 million), waste from productive activities management (€277 million), water management (€159 million), spill prevention (€41 million) and air protection (€38 million). Safety Eni is constantly engaged in the research and development of all the actions necessary to guarantee safety in the workplace, in particular in the development of models and tools of risks assessment and management and in the promotion of a safety culture, in order to pursue its commitment to zero accidents. In 2025, the new legislation did not have a significant impact on the procedures already in place for occupational and process safety. In 2025, the commitment to reduce accidents continues at Eni, through the: - application of the THEME methodology on analysing worker behaviour and human reliability in order to identify action strategies to strengthen human barriers and safe behaviour; - deployment of training course dedicated to: Operational Safety Management with the aim of familiarising with the basic principles and minimum safety requirements to be applied in risky activities; Process Safety Management, in order to provide basic information on Process Safety Management System; RC Eni investigation methodology, which enables the identification of root causes and effective action to prevent the recurrence of accidents; Industrial Hygiene Management with the aim of increase and share knowledge, principles and requirements to be applied in sampling and monitoring of risk agents. - extension to all operational sites of the digital Safety Presence tool, which, with the help of artificial intelligence and machine learning, enables predictive analysis by exploiting the data available in the safety reporting, sending an alert to the site when it detects a high frequency of recurring hazardous situations that retrace a past accident;' - diffusion of the Campaign on Process Safety Fundamentals. Process Safety Fundamentals are key operating principles that, if respected, may contribute to the reduction of approximately one third of Company Process Safety Event and the Safety Golden Rules with a focus on the Principles of Line of Fire and Stop Work Authority. In terms of industrial hygiene, great attention was paid to the identification and management of personal protective equipment (PPE). In 2025 continues at Eni the extension to all operational sites of the Integrated System Personal Protective Equipment web system aimed at the digital management of Personal Protective Equipment (PPE) and the promotion of specific training initiatives to raise awareness of the importance of correct identification and use of them. Eni has developed a radiation protection system capable of managing the risk deriving from the use of artificial radioactive sources (for example in systems for monitoring fluid levels and density) and from the presence of natural radioactive sources (Radon and TENORM). In particular, Eni has validated a methodology for the mapping of TENORM matrices in Eni sites all over the world and has implemented management systems for monitoring the disposal of matrices contaminated by natural radionuclides. 78 Table of Contents In 2025 the total recordable injury rate (TRIR) of the workforce improved compared to 2024 (0.55 vs 0.70 in 2024), with a decline in the number of injuries (78 vs 111) due to positive performances by both employees and contractors. No fatalities or disability-related injuries occurred during the period. In the area of emergencies, particular attention was paid to the prevention and management of emergencies induced by natural risks and in November 2021 Eni and the Department of Civil Protection signed a four-year Memorandum of Understanding which was extended to 2025. The agreement aims to strengthen cooperation and define emergency plans specific for each type of risk with an impact on the continuity of energy supply on the national territory. Emergency preparedness is regularly tested during exercises where the response capacity is tested in line with dedicated plans, including the timely alerting of the chain of command and of the resources necessary to face the event. The operational sites maintained a high level of preparedness for emergencies by carrying out over 5,800 exercises. Costs incurred in 2025 to support the safety levels of operations and to comply with applicable rules and regulations were €326 million. Health activity for 2025 Eni promotes a culture of health and well-being for its people, workers, families and communities, considering health’s physical, mental and social dimensions, through a management system based on the principles of precaution, prevention and promotion. The total amount spent in 2025 was €45.79 million divided into activities, covering the entire Eni population, and includes the activities of Occupational Medicine, Occupational Hygiene, Medical assistance and Emergency, Health Promotion & Welfare services and Global Health activities for the protection and improvement of communities’ health. The correct management of health-related risks is guaranteed with the constant updating of the health profile assessments of the countries of presence, which take into account the potential impacts on health deriving from company’s activities, with continuous monitoring of any presence of epidemic and pandemic outbreaks, and the expectations of stakeholders. In order to guarantee people's health at every stage of the business cycle, the management system is active in all operational areas, in collaboration with qualified healthcare providers and national and international university and government institutions and research centres. Eni acts following local regulations and highest international standards and guarantees continuous updating of staff training and skills. Health at the center of the company's strategy and operating models contributes to achieving a "just" energy transition for people in the geographical areas in which the company operates. 79 Table of Contents Main 2025 initiatives: - Occupational health and industrial hygiene: • Medical and occupational hygiene activities aimed at the evaluation, identification and control of risk factors that may have an impact on the well-being of workers. • Scientific research activities in relation to the energy transition, focusing on the analysis health risks factors of new businesses. • Testing of new Internet of Things technologies: 140 devices with sensors were tested at on-shore operating sites in Italy and abroad monitoring the healthiness of indoor working environments to protect the health of workers. • Definition of operating procedures for maintaining clean and comfortable indoor environments - Medical assistance and health emergency: • Services for the prevention, diagnosis, treatment and management of acute and chronic pathologies, for workers and, where applicable, family members. • Continuous updating of epidemic and pandemic response plans. • Online psychological support service available for employees in Italy and abroad, covering 80% of employees, expected to extend to 85% by 2028. • Critical Incident Stress Management service: direct on-site crisis management intervention by qualified emergency experts, available to all employees in Italy and abroad in the event of catastrophic and unexpected events. • Psychological First Aid Service (PFA) available to all employees in Italy and abroad in cases of catastrophic and unexpected events. • Train the brain: a new cognitive prevention programme has been launched for workers over 50, offering free, voluntary and completely confidential consultations with a neuropsychologist via remote communication. • Specific services regarding gender health and assistance have been activated, such as in Italy a helpline dedicated to victims of gender harassment and violence. - Health promotion and welfare services: • Initiatives aimed at fostering a culture of health among employees and their families, including awareness-raising activities on endemic diseases (such as tuberculosis and malaria), sexually transmitted diseases, and non-communicable diseases, including diabetes and hypertension. • The “Più Salute” programme, which provides Eni employees in Italy, and their families with free 24 hours a day healthcare services, ranging from telemedicine and home medical assistance, to support for healthcare facility bookings and anamnestic assessments. • Further rollout of the “Previeni con Eni” programme to additional Italian cities, offering free biennial preventive screenings for oncological and cardiovascular diseases. It currently covers approximately 97% of Eni’s workforce in Italy. • The seasonal influenza vaccination campaign for employees in Italy. - Global health: • 11 Health Impact Assessment (HIA) studies completed, of which 3 integrated ESHIA studies to evaluate the potential impacts of industrial projects on the health of the communities involved. • 38 health development initiatives have been implemented in 14 countries, reaching over 600,000 beneficiaries. • Collaboration with health institutions, non profit organizations and scientific/medical partners in the countries of presence was strengthened by signing of 7 new agreements besides of the 26 already active. In 2025 Eni’s collaboration with international organizations was strengthened. Eni is an active member of the Health Committees of IOGP – the International Association of Oil & Gas Producers and of IPIECA – the industry association on global sustainability issues. Moreover, within the global Eni-ILO – International Labour Organization Partnership, the company has continued working with small and big producers, farmers, aggregators, cooperatives across the agribusiness value chain in Kenya, Ivory Coast and Congo, implementing a programme aiming at assessing potential health impacts on workers of this value chain, at strengthening of Occupational Health and Safety and enhancing social protection measures. In Kenya these activities were integrated with community health initiatives. Regulation of Eni’s businesses The Group engages in the exploration and production of oil and natural gas, processing, transportation and refining of crude oil, transport of natural gas, storage and distribution of petroleum products and the production of base chemicals, plastics, and elastomers. By their nature, the Group’s operations expose Eni to a wide range of significant health, safety, security, and environmental risks. Technical faults, malfunctioning of plants, equipment and facilities, control systems failure, human errors, acts of sabotage, attacks, loss of containment and climate-related hazards can trigger adverse consequences such as explosions, blow-outs, fires, oil and gas spills from wells, pipeline and tankers, release of contaminants and pollutants in the air, ground and water, toxic emissions, and other negative events. The magnitude of these risks is influenced by the geographic range, operational diversity, and technical complexity of Eni’s activities. Eni’s future results of operations, cash flow and liquidity depend on its ability to identify and address the risks and hazards inherent to operating in those industries. 80 Table of Contents The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production leases, the imposition of specific drilling and other work obligations, higher-than-average rates of income taxes, additional royalties and taxes on production, environmental protection measures, control over the development and decommissioning of fields and installations, and restrictions on production. A description of the main regulations which impose restrictions and liabilities to the Company’s businesses is provided below. Overview The matters regarding the effects of recent or proposed changes in Italian legislation and regulations or EU directives discussed below and elsewhere herein are forward-looking statements and involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties include the precise manner of the interpretation or implementation of such legal and regulatory changes or proposals, which may be affected by political and other developments. Regulation of exploration and production activities Eni’s exploration and production activities are conducted in many countries and are therefore subject to a broad range of legislation and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and conditions of the leases, licenses and contracts under which these oil&gas interests are held vary from country to country. These leases, licenses and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These arrangements usually take the form of licenses or production sharing agreements. Licenses (or concessions) give the holder the right to explore for and exploit a commercial discovery. Under a license, the holder bears the risk of exploration, development and production activities and provides the financing for these operations. In principle, the license holder is entitled to all production minus any production taxes or royalties, which may be in cash or in-kind. Concession contracts currently applied mainly in Western countries regulating relationships between States and oil companies with regards to hydrocarbon exploration and production activity. Both exploration and production licenses are generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases). The term of Eni’s licenses and the extent to which these licenses may be renewed vary by area. Contractual clauses governing mineral concessions, licenses and exploration permits regulate the access of Eni to hydrocarbon reserves. The company holding the mining concession has an exclusive right on exploration, development and production activities, sustaining all the operational risks and costs related to the exploration and development activities, and it is entitled to the productions realized. As a compensation for mineral concessions, Eni pays royalties on production (which may be in cash or in-kind) and taxes on oil revenues to the state in accordance with local tax legislation. Proved reserves to which Eni is entitled are determined by applying Eni’s share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right. Eni operates under Production Sharing Agreement (PSA) in several foreign jurisdictions mainly in African, Middle Eastern and Far Eastern countries. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract, the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment (technologies) and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: “Cost Oil” is used to recover costs borne by the contractor and “Profit Oil” is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country. Pursuant to these contracts, Eni is entitled to a portion of a field’s reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The Company’s share of production volumes and reserves representing the Profit Oil includes the share of hydrocarbons which corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. Therefore, the Company recognizes at the same time an increase in the taxable profit, through the increase in revenues, and a tax expense. Proved reserves to which Eni is entitled under PSAs are calculated so that the sale of production entitlements should cover expenses incurred by the Group to develop a field (Cost Oil) and recognize the Profit Oil set contractually (Profit Oil). A similar scheme to PSA applies to Service contracts. In general, Eni is required to pay income tax on income generated from production activities (whether under a license or PSA). The taxes imposed upon oil&gas production profits and activities may be substantially higher than those imposed on other businesses. 81 Table of Contents Regulation of the Italian hydrocarbons industry The matters regarding the effects of recent or proposed changes in Italian legislation and regulations or EU directives discussed below and elsewhere herein are forward-looking statements and involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties include the precise manner of the interpretation or implementation of such legal and regulatory changes or proposals, which may be affected by political and other developments. Exploration & Production The Italian hydrocarbons industry is regulated by a combination of constitutional provisions, statutes, governmental decrees and other regulations that have been enacted and modified from time to time, including legislation enacted to implement EU requirements (collectively, the “Hydrocarbons Laws”). Exploration permits and production concessions. Pursuant to the Hydrocarbons Laws, all hydrocarbons existing in their natural condition in strata in Italy or beneath its territorial waters (including its continental shelf) are property of the State. Exploration activities require an exploration permit, while production activities require an exploiting concession granted by the Ministero dell’Ambiente e della Sicurezza Energetica - MASE or, in some specific cases (e.g. special-status region) by the Region. The initial duration of an exploration permit is six years, with the possibility of obtaining two three-year extensions and an additional one-year extension to complete activities underway. Upon each of the three-year extensions, 25% of the area under exploration must be relinquished to the State (only for initial acreages larger than 300 square kilometers). The initial duration of a production concession is 20 years, with the possibility of obtaining a ten-year extension and additional five-year extensions until the end of the field economic life. These provisions are to be coordinated with a new law effective as of February 12, 2019 (Law 12/2019 — ex “D.L. Semplificazioni”) and further amendments, which requires certain Italian administrative bodies to define and adopt within end September 2021 a plan (PiTESAI) aiming to identify areas suitable for exploration, development, and production of hydrocarbons in the national territory, including the territorial seawaters. The plan has been adopted on December 28, 2021. However, PiTESAI has been considered too restrictive by industry operators (including Eni) which lodged an appeal before Lazio Regional Administrative Court – Rome (TAR Lazio). On February 13, 2024, TAR Lazio ruling declared PiTESAI void. On October 18, 2024, a new law was issued (D.L. 153/2024 “Ambiente”) containing some provisions affecting the current hydrocarbon industry regulation. In particular: a) all the provisions related to PiTESAI are cancelled; b) new exploration and production onshore-offshore licenses - oil targeted – can no longer be granted. Only the existing licenses can continue/complete their authorized activities; c) the restriction on upstream activities related to the distance from shoreline or protected marine areas is reduced from 12 to 9 nautical miles; d) new opportunities to boost gas production are slightly redefined. Starting from June 1, 2019, the above-mentioned law increases 25 times the current annual fee for all licensees (exploration permits and production concessions). Moreover, the Fiscal decree no. 124/2019, converted into Law 157/2019 established (art. 38) the property tax on marine structures (IMPI) starting from year 2020. 82 Table of Contents As mentioned above (point d), D.L. n.153/2024 “Ambiente” slightly redefines the new opportunities to boost national gas production and removes all the PiTESAI restriction. However, discussions are ongoing between the Ministry and O&G Companies on possible amendments to be introduced. Royalties. The Hydrocarbons Laws require the payment of royalties for hydrocarbon production. As per Legislative Decree No. 625 of November 25, 1996, subsequent modifications and integrations (the last modification was introduced by Law 160/2019 – Budget Law 2020, art. 1 par. 736 & 737) and Law Decree No. 83 of June 22, 2012, royalties are equal to 10% for gas and oil productions onshore, to 10% for gas and 7% for oil offshore, with exemptions only for on shore gas concessions with production lower than 10 Msmc/year and off shore gas concessions with production lower than 30 Msmc. (Only in the Autonomous Region of Sicily, following the Regional Law No. 9 of May 15, 2013, royalties onshore for oil and gas are equal to 20.06%, with no exemptions). Gas & Power Eni’s wholesale gas and retail gas and power businesses are subject to regulatory risks mainly in Italy’s domestic market. The Italian Regulatory Authority for Energy, Networks and Environment (the “Authority”) is entrusted with certain powers in the matter of natural gas and power pricing. Specifically, the Authority exercises monitoring and supervisory powers over price trends in the energy markets and sets the economic conditions of supply for specific categories of end customers, such as vulnerable customers, for whom regulated tariffs remain in force under the applicable regulatory framework. Developments in the regulatory framework intended to increase the level of market liquidity or of deregulation or intended to reduce operators’ ability to transfer to customers the supply cost increases may negatively affect future sales margins of gas and electricity, operating results, and cash flow. Wholesale gas market in Italy Over the past years, a number of new rules were introduced in order to structurally improve liquidity and efficient functioning of the Italian wholesale gas market, fostering competition and at the same time improving the system security of supply. Among such new rules, it could be worth mentioning: – Market based mechanisms for the allocation of storage capacities and of regasification capacities: moving away from the past capacity allocation criteria based on regulated tariffs, new auction mechanisms were implemented that enabled market players to express the market-value of storage and of regasification capacities, while at the same time ensuring the allowed revenues of regulated storage operators and regulated LNG terminal operators by means of specific parallel measures. Thanks to these reforms, higher levels of capacity bookings have become possible for both types of infrastructures, and more LNG deliveries have been attracted in recent years to the country. – An organized market platform for gas trading and gas balancing (MGAS), managed by the independent operator Gestore dei Mercati Energetici (GME) which also acts as a central counterparty, where different market participants (including TSO) can carry out spot and forward transactions at the “Punto di Scambio Virtuale” (PSV – Virtual Trading Point). In addition, since February 2018 voluntary market making activity has been introduced in the spot section of the gas exchange MGAS: such activity is based on the service provided by some liquidity providers, in order to boost liquidity and trading activity on the same exchange, initially for the day-ahead market but with possible future extension to the within-day section and to the forward section of the MGAS. – A gas balancing regime, entered into force since October 2016 as an evolution of the one already in place and in compliance with the EU regulatory framework. This system is based on the principle that network users have to balance their daily position, also in accordance with the timely information provided by the TSO about the daily gas consumption. The new gas balancing regime provides the incentive for shippers to balance their position via penalizing imbalance prices and at the same time it provides the possibility for shippers to modify intra-day their gas flow nominations and to trade on the market with other shippers and/or with the TSO itself (that can access the market under some constraints, in order to address overall system balancing needs that may arise on top of shippers’ activities). 83 Table of Contents Activity in the Italian wholesale gas market is also exposed to risk factors, as well as business opportunities, resulting from certain developments – both temporary and structural – in the European regulatory framework that may impact the dynamics of the national markets. For example, in the context of the energy crisis following the Russian-Ukrainian war, and in the framework of the emergency and transitional regulations at EU level, the Italian competent authorities introduced in 2022 (and then adapted over the time) new regulatory measures aimed at ensuring the system security of supply in the short-term and improving it in the longer term, such as specific market based solutions in order to: i) incentivize storage booking and filling and ensure the compliance with the new filling targets set by the European regulation; ii) further facilitate market access to existing regasification capacities; iii) quickly develop new regasification capacities and making them accessible to the market. Such new measures may represent risk factors as well as business opportunities. Natural gas and electricity prices in the retail sector in Italy - Risks associated with the regulatory powers entrusted to the Italian Regulatory Authority for Energy, Networks and Environment in the matter of pricing to residential customers Following the liberalization of the natural gas sector introduced in the year 2000 by Decree No. 164, prices of natural gas for industrial and power generation customers are freely negotiated. However, ARERA retains a power of surveillance on this matter as per Law No. 481/1995 (establishing the ARERA) and Legislative Decree No. 164/2000. Furthermore, ARERA is still entrusted (as per the Presidential Decree dated October 31, 2002) with the power of regulating natural gas prices to residential customers, also with a view of containing inflationary pressure deriving from increasing energy costs. Consistently with those provisions, companies which sell natural gas to residential customers are currently required to offer to those customers the regulated tariffs set by ARERA beside their own price proposals. In 2013, a new tariff regime was fully enacted by ARERA targeting Italian residential clients who are entitled to be safeguarded in accordance with current regulations. Clients who are eligible for the tariff mechanism set by the ARERA are residential clients. With Resolution No. 196 effective from October 1, 2013, the ARERA reformulated the pricing mechanism of gas supplies to those customers by providing a full indexation of the raw material cost component of the tariff to spot prices at the TTF (Title Transfer Facility) hub in Northern Europe, replacing the then current regime that provided a mix between an oil-based indexation and spot prices. This tariff regime also reduced the tariff components intended to cover storage and transportation costs. Finally, it also increased the specific pricing component intended to remunerate certain marketing costs incurred by retail operators, including administrative and retention costs, losses incurred due to customer default and a return on capital employed. This new gas tariff indexation aiming at safeguarding the households was initially intended to remain effective till July 1, 2019 (as provided by Law 124/17). However, this deadline had been already prorogated by one year (as per Law Decree 91/2018), and finally has been prorogated to January 2024. From that point onwards, in Italy households other than vulnerable customers no longer have access to regulated tariffs for gas supplies. Consumers have to choose among the different pricing proposals made by gas selling companies, while only vulnerable customers are entitled to the regulated tariff after January 2024. The ARERA has established that gas selling companies comply with certain requirements about the offerings to customers which include at least two pricing indexations (fixed and variable), both complemented with contractual conditions regulated by the ARERA. Management believes that this development will increase competition in the Italian retail market for selling gas. Given the context of rising prices that occurred between 2021 and 2022 in gas market, ARERA carried out a series of investigations to evaluate interventions on commodity prices and then decided to switch the gas raw material reference from TTF to PSV, with monthly update of the component covering wholesale natural gas supply costs for regulated customers. In the electricity market the regulated prices phase out has been effective from July 1, 2021, for small enterprises (enterprise which employs fewer than 50 persons and whose annual turnover and/or annual balance sheet total does not exceed €10 million). For microenterprises (enterprise which employs fewer than 10 persons and whose annual turnover and/or annual balance sheet total does not exceed €2 million) the regulated prices phase out became effective from April 2023, while for non-vulnerable households the deadline was furtherly prorogated to July 2024. The publication of the results of the bidding process took place on February 6, 2024. It will be critical that the manner in which the winners handle clients be properly monitored to avoid unfair practices. The Annual Law for the Market and Competition 2023 provided that vulnerable domestic customers have the right to request, by June 30, 2025, access to the tiered protection service, provided by the awarded operator of the area in which the relevant delivery point is located. On January 22, 2025, ARERA published Resolution 10/2025/R/eel, setting out the implementation procedures, including those concerning the certification of the fulfillment of the vulnerability requirements, as evidenced on its official website. This provision applies to all customers meeting the vulnerability criteria, even if they are served in the liberalized market. Other regulatory developments in the gas and electric sector in Italy and Europe Within the scope of the costs and criteria for accessing the main logistic infrastructures of the gas system, the main risk factors for the business are linked to the processes for defining the economic conditions and the rules for accessing transportation, LNG regasification and storage services, which periodically involve all the European countries in which Eni operates. The regulation criteria for gas transportation tariffs have been redefined for the four-year period 2024-2027 in countries such as Italy, France and Belgium, but the re-definition of transportation tariffs criteria at pre-established multi-yearly deadlines, as well as the timely definition on an annual basis of the specific applicable tariff values, is an element that all European countries have in common and which also in the future could have an impact on logistic costs. Changes in access rules and tariff levels may also affect the regasification and storage sector representing risk factors as well as business opportunities, also in consideration of the market context following the energy crisis in 2022-2023 and of the need to pursue new solutions to ensure European security and diversification of supplies. 84 Table of Contents Activity in the wholesale gas market is also exposed to risks arising from both temporary and structural developments in the regulatory framework that may impact market dynamics and entail specific obligations. These include regulatory measures introduced at both the European and individual country levels since the 2022 energy crisis, aimed at containing prices or improving security of supply (for example, storage filling targets), as well as new and increasing regulatory obligations imposed on importers. In the medium term we could expect that gas demand at European level can still be supported by policies aimed at phasing out coal in power generation, in view of the decarbonisation targets. On the other side, with the progressive implementation of the EU Green Deal and of the related ambitious regulatory interventions aimed at decarbonisation, in the coming years the regulation of the gas sector will be affected by potentially significant changes, as a consequence of adjustments in the market design and/or new obligations or constraints on operators in the sector. The evolution of European regulations, in the context of energy transition and consistently with the decarbonisation objectives of the energy sector (including the related objectives for the development of renewable or decarbonised gases, for the promotion of technologies enabling greater integration between the electricity and gas sectors, for the reduction of methane emissions) will put pressure on the natural gas sector, but on the other side this will likely open up and support new business opportunities in the renewable and decarbonized gases sectors that Eni is ready to pursue. From a retail perspective, there were a number of various measures adopted at national level. For example, in 2021, the Spanish government in a measure to protect final consumers with low voltage supplies (>10kW power), reduced VAT from 21% to 10% and in 2022 proceeded to lower it further, to 5%. However, while retailers invoice final customers 5% VAT, distribution companies continue to invoice retailers at the normal 21% rate. The value-added tax rate for energy bills gradually returned to 21% in 2024. In France, during 2022, electricity and gas regulated tariffs were maintained below cost with a compensation distributed to all suppliers. For 2023, the government increased the frozen regulated electricity and gas tariffs by 15%. Although suppliers will continue to be compensated for 2023, this freeze will continue to have a negative impact on the competitiveness of alternative suppliers. Moreover, the amount of compensation is based on sales prices, which are set by the government below the suppliers' real costs. The ad hoc compensation mechanism introduced in 2022 for apartment blocks has also been extended until the end of 2023 and now covers both electricity and gas consumption. The government has also introduced a new support mechanism for SME electricity consumption throughout 2023. The compensation that suppliers gave to their customers (both condominiums and SMEs) was financed by the government. Therefore, their financial and commercial impact is limited. As far as gas is concerned, regulated tariffs were phased out in 2023. As far as electricity is concerned, in November 2024, the French Regulator (CRE) published an assessment supporting the reasons for the permanence and extension for a further 5 years (until 2030) of the electricity regulated tariff. Shortly after, the French Competition Authority has published an opinion strongly criticizing such decision and denouncing the non-transitory nature of the regulated tariff as well as its negative impact on the competitiveness of the energy market, thus suggesting its timely repeal. The Government has validated the decision for the extension of the regulated tariffs on electricity until 2030 and notified its decision to the European Commission. In Italy there have been some government interventions to contain retail prices such as: - cancellation of general system charges in the electricity sector, which in the gas sector even assume negative value; - strengthening of social bonuses in both sectors; - decrease of VAT in the gas sector (until December 31, 2023). With regard to wholesale power sector, Eni is participating to Italian Capacity Market auctions starting from 2019. During the delivery period the operators selected by the auctions will receive a fixed premium and, in return for this payment, they must i) offer power capacity on energy markets (day- ahead Market and intraday Market) and/or on the dispatching services market; ii) pay the difference between a market reference price and a pre- determined strike price whenever the reference price exceeds the strike price. Eni has been awarded all the capacity offered in the tenders so it will receive a net benefit for its existing Eni group’s power plants during the delivery period (2022, 2023 and 2024) and for a new power plant, that will be built in Ravenna, for a period of fifteen years (starting in 2023). 85 Table of Contents The auctions for the delivery years 2025, 2026 and 2027 have been held in November 2024, December 2024 and February 2025, respectively and Eni was awarded a premium for existing capacity of €45,000 MW/y, €46,000 MW/y and €47,000 MW/y respectively. The risk of annulment of the auctions has been removed, as all operators who appealed have withdrawn them due to a lack of interest. The auction for the allocation capacity with delivery 2028, which will likely take place in 2026, will be affected by increasing competition as a consequence of lower adequacy demand due to the new energy storage capacity, which Terna has procured by the centralized auction system, the so called “MACSE” (the first MACSE’s auction with delivery 2028 took place in September 2025, the second one will take place in 2026). Terna hasn’t planned the auctions for the years following 2028 yet. Besides, over the past years Italian power market design has significantly been affected by the implementation of European market model. The main innovations were the introduction of negative prices and the launch of new Intraday Market based on continuous trading and gate-closure close to delivery period (h -1 gate closure), both adopted in the second half of 2021. Moreover, the introduction of 15 minute Market Time Unit in the day ahead in 2025 and further reduction of intraday gate-closure time closer to delivery period (Q-30) starting from January 2026, are further contributing to the cross-border integration of European energy and balancing market (coupling of intraday market, coupling of balancing reserves markets). The implementation of new regulatory provisions concerning the rules which govern the Italian balancing market (the so called “Nuovo Testo Integrato del Dispacciamento” or “Nuovo TIDE”), has partially entered into force since January 1, 2025 and will be fully implemented from February 1, 2026. Management believes that all these measures will increase competition, in particular in the Italian balancing market, also taking into account that Terna is committed to minimize the balancing market cost. Despite the increasing frequency of RES overgeneration events in 2025, the current regulatory framework has avoided the occurrence of negative prices in day ahead market (so called “MGP”). Regarding this matter no regulation changes are foreseen. As regards MGP, starting from 1 January 2025, the phase-out of the PUN has had no effect on the wholesale electricity market due to the introduction of the “PUN Index” which includes a compensation component. Compensation component can be removed or partially modified just after a consultation that should be launched 24 months in advance. The revision of the European electricity market design carried by the Commission, amended four pieces of legislation throughout Regulation (EU) 2024/1747 and Directive (EU) 2024/1711: the Electricity Directive 2019/944 and Regulation 2019/943, RED II (2018/2001, regarding support schemes for renewables) and Regulation 2019/942 establishing ACER. The revision is more targeted and limited in the changes that were initially anticipated, most notably it conserves the merit-order pricing system, while reinforcing the role of long-term contracts for renewable energy sources, namely two ways CfDs and PPAs. With respect to Capacity Remuneration Mechanisms, the reform positively recognizes such mechanisms as structural elements of electricity markets, removing the reference to the temporary requirement. It maintains the validity of the Commission approval according to the State Aid Guidelines for ten years, but it charges the Commission with the proposal of a new simplified approval process for new CRMs, which ended with the publication of Clean Industrial State Aid Framework. The CISAF framework allows to streamline the approval of a CRM but provided that the mechanism is compliant with conditions defined in a target model. Furthermore, the reform introduced several obligations on suppliers. First, an obligation to offer fixed-price, fixed-term contracts, without first guaranteeing the possibility of charging termination fees. Second, it opens the possibility for Member States to require suppliers to cover part of their risk exposure using PPAs. Finally, it establishes the framework for declaring future price crisis, in which case Member States may impose below cost regulated prices, however, conditions are set whereby suppliers must be compensated for selling energy below cost, that there should be no discrimination between suppliers and that all suppliers are eligible to provide below cost offers on the same basis. At present, the emergency interventions adopted by the government to compensate for the phenomenon of high energy prices are finished. In fact, in addition to the suspension of tax credits for companies (starting from the third quarter 2023) and the reinstatement of system charges for the electricity sector (starting from the second quarter 2023), the 5% VAT reduction for gas, which was still in place until the fourth quarter 2023, is also terminated. Currently, only a few measures are provided for the most vulnerable households (for example the extraordinary contribution for electricity bonus holders confirmed for the first quarter 2024). Regarding the development of power generation from renewable sources, there are many issues under discussion that could represent risk factors for the sector. Noting the critical issues related to the complexity of the authorization processes, Law No. 201 of November 28, 2023 (Art. 3) extended from 16 to 24 months the provisions of Art. 26 of the Competition Law 2021 (118/2022) on the adoption of one or more legislative decrees on simplification, thus moving the deadline for the exercise of the delegation to August 25, 2024. In addition, the pending Decree on Eligible Areas and Regional Burden Sharing, the approval of which is desirable in a timely manner to ensure investment in the sector, and the Decree on Incentivizing Renewable Energy Plants Close to Competitiveness (FERX), which confirms the introduction of inflation adjustment mechanisms for tariffs, represent uncertainty elements for the achievement of the expected energy transition goals. With regard to the development of offshore power generation, particularly with floating technology, a certain framework of rules is strongly expected with reference to the finalization of maritime spatial planning tools and the publication (by the Ministry of Environment and Energy Security) of the guidelines/vademecum related to the necessary fulfillments for the purpose of initiating the single procedure for the authorization of such plants, as per the provisions of Legislative Decree No. 199 of November 8, 2021 (Art. 23). In addition, a strong impact for pipeline projects will be the definition of the Decree on incentives aimed at innovative plants or those still far from market competitiveness (RES2) and an adjustment of the regulatory framework related to port areas: a first positive step in this direction is represented by the provisions of DL 181/2023, which started the process for the identification of two port areas in the South of Italy for the development of investments of the shipbuilding sector for the production, assembly and launching of floating platforms and related electrical infrastructure. 86 Table of Contents Refining and marketing of petroleum products Refining. The current regulation on refining activity in Italy provides that Italian administrative bodies authorize plans filed by refining operators intended to set up new processing and storage plants and to upgrade capacity, while all other changes that do not affect capacity can be freely implemented. This regime was streamlined by Law Decree No. 5/2012 (as converted in Law 35/2012) that defined mineral oil processing and storage plants as “strategic installations” that need authorization from the State, in agreement with the local administrations. The Decree introduced a unitized process of authorization that must be finalized within 180 days, subject to compliance with applicable environmental regulations. The EU 2024 Delegation Law sets out the criteria for the transposition of the following: • Directive 2024/1785/EU, which amends Directive 2010/75/EU on industrial emissions. The foreseen revision of the integrated environmental authorization (AIA) will impact refineries, since strengthened requirements are expected (including: more stringent emission limit values and binding performance limit values, the obligation to adopt a certified environmental management system, increased transparency for public participation and the right to compensation for damage to health and to the environment caused by violations of applicable rules). • Directive 2024/2881 on ambient air quality, which sets more stringent emission standards by 2030 - aligned with the latest WHO (World Health Organization) recommendations - for PM2.5, PM10, nitrogen dioxide (NO₂), and sulfur dioxide (SO₂) and strengthens access to justice and citizens' right to compensation for health damage. Targets set for Member States will influence public programs for urban and metropolitan mobility and may affect permit requirements for industrial installations, particularly regarding air emissions in areas with the most critical air quality conditions. • Directive (EU) 2024/1203 on the protection of the environment through criminal law which strengthens the European framework by introducing new environmental offences and harshening penalties. To promote, by means of investment aid, the conversion of existing refineries for the production of pure biofuels, a dedicated fund has been established under the Ministry of Environment and Energy Security budget. The Ministerial Decree of June 17, 2024 sets out the criteria and conditions for the allocation of the resources, however, the allocation procedure has not yet been published. Legislative Decree No. 5/2026, which transposes Directive (EU) 2023/2413, extends the scope of the fund to include sustainable aviation biofuels (SAF), although without increasing its financial endowment or extending the reference period. A new Ministry of the Environment and Energy Security decree was published on November 3, 2025. The decree establishes the criteria and procedures for allocating capital grants to support the total or partial conversion of existing traditional refineries into biorefineries to produce sustainable liquid biofuels, to be used also in pure form, and SAF produced from the raw materials listed in Annex IX – RED. The costs are financed through ETS allowances auctions revenues. Following the entry in force of the EU methane emissions Regulation, the Italian Government is currently defining the applicable sanctions regime. Recently, new legislation has been adopted concerning work safety (Law decree 159/2025 Sicurezza sul Lavoro, Law n. 203/2024). Marketing. Following the enactment of the Law Decree No. 1/2012, an increased level of competition in the retail marketing of fuels has been introduced. The rules regulating relations between oil companies and managers of service stations have been changed by introducing the difference between principal and non-principal of a service station. Starting from June 30, 2012, principals have been allowed to freely supply up to 50% of their requirements. In such case, the distributing companies have the option to renegotiate terms and conditions of supplies and brand name use. As for non-principals, the law allows the parties to renegotiate terms and conditions at the expiration of existing contracts and new contractual forms can be introduced in addition to the only one allowed so far, i.e. exclusive supply. The law also provides for an expansion of non-oil sales. Furthermore, the Budget Law 2018 (Law 205/2017) provides some measures for preventing tax evasion in the sale of oil products. The law requires the advance payment of Value Added Tax (VAT) on oil products before the extraction from deposits or the sale to consumer. 87 Table of Contents In 2019, the Law no. 157/2019 introduced a set of measures to prevent illegal conduct/practices linked to fiscal fraud for the exchange of products in the retail fuel market. These regulatory initiatives will also address for more competition and efficiency of the sector. In 2020, the Budget Law 2021 (Law 178/2020) extends some measures to prevent fiscal frauds and introduces electronic communication for some information. Service stations. Legislative Decree No. 32 of February 11, 1998, as amended by Legislative Decree No. 346 of September 8, 1999 and Law Decree No. 383 of October 29, 1999, as converted in Law No. 496 of December 28, 1999, significantly changed Italian regulation of service stations. Legislative Decree No. 32 replaces the system of concessions granted by the Ministry of Industry, regional and local authorities with an authorization granted by city authorities while the Legislative Decree No. 112 of March 31, 1998 still confirms the system of such concessions for the construction and operation of service stations on highways and confers the power to grant to Regions. Decree No. 32 also provides for: (i) the testing of compatibility of existing service stations with local planning and environmental regulations and with those concerning traffic safety to be performed by city authorities; (ii) the option to extend by 50% the opening hours (currently 52 hours per week) and a generally increased flexibility in scheduling opening hours; (iii) simplification of regulations concerning the sale of non-oil products and the permission to perform simple maintenance and repair operations at service stations; and (iv) the opening up of the logistics segment by permitting third -party access to unused storage capacity for petroleum products. Subsequently, various regulations have been enacted in Italy with the aim of improving network efficiency, modernizing service stations and opening up the market. Currently, all service stations are provided with self-service equipment and the sale of non- oil products has been broadly introduced by local administrative bodies. Law Decree No. 1/2012 also allowed the installation of fully automated service stations with prepayment, but only outside urban areas. Law No. 133 of August 6, 2008, by intervening in competition provisions, removes some national and regional regulations, which might limit the liberty of establishment and introduces new provisions particularly concerning the elimination of restrictions concerning distances between service stations, the obligation to undertake non-oil activities and the liberalization of opening hours. In 2023, the Law Decree 5/2023 provided measures for the transparency and control of the prices of the road transport sector fuels. Ministry of Industry and Made in Italy calculates and publishes on its website: (i) the arithmetic average, on a regional basis, of the prices communicated by fuel sellers operating on the service stations located off highway and (ii) the arithmetic average, on a national basis, of fuel prices communicated by operators located in highway. Subsequently, pursuant to the abovementioned Law Decree 5/2023, the Ministerial Decree of March 31, 2023 provided the rules for the exposition of the relevant average reference prices for the fuel sellers. With ruling n. 1806 dated 23 February 2024, the Consiglio di Stato declared the illegitimacy of the provision contained in art. 7 of the Ministerial Decree of March 31, 2023, which established the obligation for fuel distributors to display on a daily basis the average price. Law no. 124/2017 aims to promote the structural reorganization of the fuel distribution network also in order to increase competition and efficiency. The law requires the closure of fuel stations that are incompatible with road safety regulations and environmental streamlining procedures for the decommissioning. The Law Decree 76/2020 extended the simplified procedures for the fuel station decommissioning by 2023. The regulatory framework provided by the legislative decree No 257/2016 – implementing EU Directive 2014/94/EU (AFID) on alternative fuel infrastructures – has introduced minimum requirements for the construction of infrastructure for the development of alternative fuels to mitigate the environmental impacts of the transport sector. Regulation (EU) 2023/1804 (AFIR) on the deployment of alternative fuels infrastructure repeals Directive 2014/94/EU and establishes, inter alia, mandatory national targets leading to the deployment of sufficient alternative fuels infrastructure in the Union for road vehicles, trains, vessels and stationary aircraft. It also lays down common technical specifications and requirements on user information, data provision and payment requirements for alternative fuels infrastructure. It applies from April 2024. The 2021 Budget law (Law 178/2020) introduced the obligations for concessionaires’ highway stations to provide electric charging points (up to 50 kW) within their own area of competence. Finally, the Law Decree 76/2020 introduced simplified procedures for the installation of electric charging points and stations and incentives to be recognized by local authorities (i.e. tax reduction or exemption for public land use). With the provisions of the Law Decree 77/2021 the installation of public access electric vehicle charging infrastructure is not subject to the issuance of a building permit and is considered free construction activity. Moreover, the annual Competition Law for 2022 (legislative decree No 118/2022) provides for competitive, transparent and non- discriminatory procedures for the selection of the operators responsible for the installation of electric recharging points on the highways network (fast and ultra-fast). 88 Table of Contents Among the measures introduced to spread sustainable mobility in Italy, starting from the 2019 Budget law and until 2024 the so-called ecobonus contributions were in place for the purchase of low-emission vehicles. With several other Acts (Law Decree 34/2020, 104/2020, Legislative Decree 187/2021), new measures and extension of existing provisions for sustainable mobility have been adopted in order to decarbonize the transport sector, through incentive mechanisms for low emission vehicles and for the installation of electric charging infrastructure. Also, Law Decree No 17/2022 provided a new incentive framework (from 2022 to 2030) for, inter alia, purchasing low-emission vehicles. The DPCM of 20 May 2024 remodulates incentives as well, to be allocated by 2024, by vehicle category. Following the latest revision (November 2025) of the National Recovery and Resilience Plan (NRRP) a new private and light commercial vehicle fleet renewal program with electric vehicles has been introduced, aimed at the purchase of at least 30,830 zero-emission vehicles by mid-2026. It consists of a car-scrapping scheme whereby a thermal vehicle is surrendered and replaced by a newly purchased zero-emission vehicle. Renewables uptake in the transport sector. In order to support the achievement of the renewables target in the transport sector established by the EU and national laws, the Ministerial Decree of March 2, 2018, provides the legislative framework to incentivize the production of both biomethane and other advanced biofuels to be used in the transport sector. The Decree provides incentives for plants starting operations between 2018 and 2022 and for plants that are converted to biomethane production. The incentive consists in an allocation of a Certificate (CIC) for every 10 Gcal of biomethane produced. The certificate has a market value since fossil fuel marketers have to sell a minimum percentage of biofuels annually, for which they receive the same Certificates. In order to access to incentives, producers must comply with legal and technical regulations governing the quality and certification of the produced biomethane, verified by the competent Authority (Gestore dei Servizi Energetici, GSE). These measures aim to favor advanced biofuels production through the valorization of waste, notably of agricultural and farm/zootechnical waste. Regarding biomethane, the incentive scheme has been replaced, following approval by the European Commission, by the Ministerial Decree of September 15, 2022. The mechanism consists of an operating aid – in the form of a CfD linked to the market value of natural gas and of the biomethane Guarantee of Origin, auctioned through a competitive procedure – and an investment aid – covering up to 40% of the eligible investment costs and funded by the NRRP. The mechanism differentiates between new plants and refurbishments and between agro or waste-based plants. Law 136/2023 introduced an inflation-linked indexation for the base tariffs set by MD September 15, 2022. In every auction, tariffs will be updated following the total inflation accrued between November 2021 and the auction’s opening month. At the end of 2020, the Ministerial Decree of October 2014 on conditions, criteria and implementation of biofuels (conventional and advanced) obligations for suppliers was modified. Among the novelties, the Decree introduced: the increase of the overall 2021 target from 9% to 10% and a new additional target of 0,5% of advanced liquid biofuels to be mandatory blended by each supplier (outside the incentive scheme provided by DM 2018). The Ministerial Decree was further amended (n. 107/2023) to specify the criteria and procedures for updating the obligations introduced by Legislative Decree 199/2021 which transposed Directive 2018/2001 (better known as REDII). In June 2024 Italy submitted its final updated NECP, a strategic plan where EU member States deliver on their commitments and reach the 2030 targets as set by the EU Fit for 55% legislation and REPowerEU, and in particular in line with the provisions of Directive 2413/2023 (REDIII). In January 2026, Legislative Decree No 5/2026 amended Legislative Decree No 199/2021 to transpose the REDIII. The Decree sets more ambitious targets for renewable energy penetration in the transport sector (setting a share of 29% in sectoral final consumption vs the previous 16%) and extends the obligation to suppliers of all transport energy carriers, including RFNBO (renewable fuels of nonbiological origin), RCF (recycled carbon fuels), LPG and electricity released in consumption for transport purposes. The maritime transport sector is included while jet fuel consumption is excluded from the obligation, as the ReFuelEU Aviation Regulation applies. The new decree confirms, by 2030, an advanced biofuels target of 8%, with a new sub-target requiring a minimum 1% share of RFNBO (of which at least 0.5% for direct use). RFNBO’s contribution to the transport target is considered even when such fuels are used as intermediate products for the production of conventional transport fuels or biofuels (if the GHG reduction achieved using RFNBO is not counted in the calculation of GHG reduction resulting from the use of biofuels), however with a lower energy valorization. The new decree sets two different regimes in case of non-compliance: existing obligation on biofuels entails a penalty of €4,000 for each missing CIC and the carryover of the obligation to the following year; whereas for the new RFNBO obligation, only a penalty of €4,000 per missing CIC is applied. Decree 5/2026 confirms the annual targets and the trajectory (with volumes increasing by 100 tons per year from 2023 and reaching 1 million tons per year from 2030 onwards) for liquid biofuels in pure form, additional to the RED obligation. The Decree introduces the possibility of using liquid and gaseous biofuels in pure form in the agricultural sector. As mentioned, the methods and criteria for implementing supply obligations for the period 2023-2030 are regulated by Ministerial Decree No 107/2023, which also defines the annual trajectories for achieving all biofuels targets and will be applied until its update. Legislative Decree 5/26 has also repealed the provisions relating to GHG saving requirements (6%) and raised the FAME quota in the diesel specification (from 7% to 10%) as provided for in Directive 98/70 (FQD). The new decree removes the restrictions on the use of PFAD and EFB, while confirming that palm-oil-based fuels cannot contribute to RES targets in the transport sector unless certified as low-ILUC risk. 89 Table of Contents Recent EU legislation promotes alternative fuels specifically in aviation and maritime transport. The ReFuelEU Aviation regulation (2405/2023) provides EU-wide blending targets for sustainable aviation fuel SAF (sustainable aviation fuel), from 2025 to 2050. Legislative decree 187/2025 defines penalties for violations of obligations related to Regulation (EU) 2023/2405. The FuelEU Maritime regulation (1805/2023) introduces progressive GHG intensity reduction requirements for the energy used on board by ships from 2025 to 2050. As mentioned above these provisions will be coordinated with the new legal framework set by the transposition of RED III in national law. As for feedstock, with Ministerial Decree of August 8, 2024 new categories of feedstock to produce double counting biofuels have been introduced in Annex VIII of Decree 199/2021, transposing the reviewed Annex IX of the REDIII. In particular, intermediate crops and crops grown on severely degraded lands are included in Part A (advanced) when used for SAF production or in Part B for the other cases. Moreover, with the Ministerial Decree of August 7, 2024, the National Certification System for the Sustainability of Biofuels has been updated to identify the criteria procedures for the certification of biofuels it also refers to a specific subsequent decree for the certification of renewable fuels of non-biological origin and recycled carbon fuels. Law Decree 63/2024 (DL Agricoltura) expanded the self-consumption regime for biomethane consumers. Self-consumption – subject to GSE’s operating rules as modified in May 2025 by Directorial Decree No 155/2025 - is no more strictly limited to on-site consumption of self-produced biomethane, but it can also include on-site consumption of biomethane produced on the same site by a third subject or produced in a different site by a third subject, under a specific contractual agreement covering the biomethane and – with an average price equal to 0 - the corresponding Guarantees of Origin. At the EU level, Regulation (EU) 2023/1115 on Deforestation (EUDR) came into force in 2023. This regulation imposes strict supply chain due diligence (DD) and reporting obligations on specific commodities and products, such as palm oil and its derivatives, imported into and exported out of the EU, that can be placed on the market or exported only if are deforestation free. The application of obligation to large companies has been postponed to 30 December 2026 by Regulation (EU) 2025/2650. On October 15, 2024, Legislative Decree 147/2024 came into force, amending Legislative Decree 47/2020 by updating the national regulations on greenhouse gas emission allowance trading to incorporate Directive (EU) 2023/959 revising the ETS Directive and Directive (EU) 2023/958 on the ETS system for aviation. Specifically, the introduced changes concern the gradual elimination of free allowances for the aviation sector, the inclusion of the maritime sector in the ETS mechanism, and the establishment of a new parallel ETS system (ETS II) involving commercial buildings, road transport, and small industries. Consequently, under the ETS II, from January 1, 2025, the companies that place into market the fuels used in road transport must have an authorization to emit GHG. National Recovery and Resilience Plan (NRRP – Piano Nazionale Ripresa e Resilienza). The NRRP, as approved by the Italian Parliament in April 2021, includes relevant proposal for the refining and marketing business area. The NRRP has been amended six times so far, the latest revision of the Plan (November 2025) introduces provisions to ensure the completion of the investment and reform initiatives by the final deadline set at EU level (August 2026). It now foresees the development of at least 21 hydrogen-based refueling stations for road transport (reducing the previous target of 40 stations). It also assigns resources for the installation of charging infrastructures for electric vehicles, envisaging the provision of certificates of installation, by June 2026, for a minimum of 10,368 fast public charging infrastructure points for electric vehicles either along freeways or urban areas (also this target has been significantly reduced). Petroleum product prices. Petroleum products’ prices were completely deregulated in May 1994 and are now freely established by operators. Oil and gas companies periodically report their recommended prices to the Ministry of Economic Development; such recommendations are considered by service station operators in establishing retail prices for petroleum products. Tax rate. The 2026 Budget Law (No. 199/2025) has introduced by 2026 the same excise tax level for diesel and gasoline for transport use, through a reduction of gasoline excise tax and an equivalent increase of diesel one. This provision leads to a complete realignment of the two excise duties at €672.90/1000 liters. The change does not affect the excise duty for pure biofuels (paraffinic diesel, HVO, and B100) produced from Annex IX-RED feedstock that until May 2030 is set at €617.4/1000 liters, nor tax reduced rates for some particular use (agricultural diesel, fixed engines, commercial diesel). Compulsory stocks. As a member of the European Union and the International Energy Agency (IEA), Italy has the obligation to maintain oil product stocks to ensure supplies in case of a national or international crisis, in accordance with Directive UE 2009/119/CE. The Legislative Decree No. 249/2012, entered into force on February 10, 2013 to implement the Directive No. 2009/119/EC. Legislative Decree no. 249 dated 31 December 2012 introduced the new procedures to maintain and manage the petroleum emergency stocks and provided for the creation of the Organismo Centrale di Stoccaggio Italiano (OCSIT), under the surveillance of the Ministry of Environment and Energy Security. 90 Table of Contents Italy’s compulsory stocks level must be at least 90 days of net import, including a 10% deduction for minimum operational requirements. Compulsory stocks are determined each year by a decree of the Minister of Environment and Energy Security defining also the compulsory stocks to be held by each economic operator according to previous year domestic consumption data. As of December 31, 2025, Eni owned 3.8 mmtonnes of oil products inventories, of which 2.6 mmtonnes as “compulsory stocks”, 1.1 mmtonnes related to operating inventories (including 0.2 mmtonnes of oil products contained in facilities and pipelines) and 0.1 mmtonnes related to specialty products. Eni’s compulsory stocks were held in term of crude oil (29%), light and medium distillates (44%), refinery feedstock (22%), fuel oil (4%), and other products (1%) were located throughout the Italian territory both in refineries (80%) and in storage sites (20%). Competition Like all Italian companies, Eni is subject to Italian and EU competition rules. EU competition rules are set forth in Articles 101 and 102 of the Lisbon Treaty on the Functioning of the European Union entered into force on December 1, 2009 (“Article 101” and “Article 102”, respectively being the result of the new denomination of former Articles 81 and 82 of the Treaty of Rome as amended by the Treaty of Amsterdam dated October 2, 1997 and entered into force on May 1, 1999) and EU Merger Control Regulation No. 139 of 2004 (EU Regulation 139). Article 101 prohibits collusion among competitors that may affect trade among Member States and that has the object or effect of restricting competition within the EU. Article 102 prohibits any abuse of a dominant position within a substantial part of the EU that may affect trade among Member States. EU Regulation 139 sets certain turnover limits for cross-border transactions, above which enforcement authority rests with the European Commission and below which enforcement is carried out by national competition authorities, such as the Antitrust Authority in the case of Italy. On May 1, 2004, a new regulation of the European Council came into force (No. 1/2003) which substitutes Regulation No. 17/1962 on the implementation of the rules on competition laid down in Articles 101 and 102 of the Treaty. In order to simplify the procedures required of undertakings in case of conducts that potentially fall within the scope of Article 101 and 102 of the Treaty, the new regulation substitutes the obligation to inform the Commission with a self-assessment by the undertakings that such conducts do not infringe the Treaty. In addition, the burden of proving an infringement of Article 101(1) or of Article 102 of the Treaty shall rest on the party or the authority alleging the infringement. The undertaking or association of undertakings claiming the benefit of Article 101(3) of the Treaty shall bear the burden of proving that the conditions of that paragraph are fulfilled. The regulation defines the functions of authorities guaranteeing competition in Member States and the powers of the Commission and of national courts. The Competition Authorities of the Member States shall have the power to apply Articles 101 and 102 of the Treaty in individual cases. For this purpose, acting on their own initiative or on a complaint, they may take the following decisions: ● requiring that an infringement be brought to an end; ● ordering interim measures; ● accepting commitments; and ● imposing fines, periodic penalty payments or any other penalty provided for in their national law. National courts shall have the power to apply Articles 101 and 102 of the Treaty. Where the Commission, acting on a complaint or on its own initiative, finds that there is an infringement of Article 101 or of Article 102 of the Treaty, it may: (i) require the undertakings and associations of undertakings concerned to bring such infringement to an end; (ii) order interim measures; (iii) make commitments offered by undertakings to meet the concerns expressed to them by the Commission binding on the undertakings; and (iv) find that Articles 101 and 102 of the Treaty are not applicable to an agreement for reasons of Community public interest. Eni is also subject to the competition rules established by the Agreement on the European Economic Area (the “EEA Agreement”), which are analogous to the competition rules of the Lisbon Treaty (ex Treaty of Rome) and apply to competition in the European Economic Area (which consists of the EU and Norway, Iceland and Liechtenstein). These competition rules are enforced by the European Commission and the European Free Trade Area Surveillance Authority. In addition, Eni’s activities are subject to Law No. 287 of October 10, 1990 (the “Italian Antitrust Law”). In accordance with the EU competition rules, the Italian Antitrust Law prohibits collusion among competitors that restricts competition within Italy and prohibits any abuse of a dominant position within the Italian market or a significant part thereof. However, the Italian Antitrust Authority may exempt for a limited period agreement among companies that otherwise would be prohibited by the Italian Antitrust Law if such agreements have the effect of improving market conditions and ultimately result in a benefit for consumers. In 2025, the Italian Antitrust Authority opened two proceeding against Eni for alleged violation of competition rules in the fields of bioplastics and biofuels and in both cases the Authority imposed a fine at Eni. The proceeding involving the biofuels segment is significant to the Company, who has filed an appeal to an administrative court requesting the repeal of the fine because the management believes that the charges from the authority are groundless. Those proceedings are fully disclosed in Note n. 18 to the Consolidated Financial Statements and a risk provision has been accrued in each case. Property, plant and equipment Eni has freehold and leasehold interests in real estate in numerous countries throughout the world. The Company enters into operating lease contracts with third parties to hire plant and equipment such as floating production and storage offloading vessels (FPSO), drilling rigs, time charter, service stations and other equipment. Management believes that certain individual petroleum properties are of major significance to Eni as a whole. Management regards an individual petroleum property as material to the Group in case it contains 10% or more of the Company’s worldwide proved oil&gas reserves and management is committed to invest material amounts of expenditures in developing it in the future. See “Exploration & Production” above for a description of Eni’s both material and other properties and reserves and sources of crude oil and natural gas. Organizational structure Eni SpA is the parent company of the Eni Group. As of December 31, 2025, there were 468 subsidiaries and 170 associates, joint ventures and joint operations that were accounted for under the equity or cost method or in accordance to Eni’s share of revenues, costs and assets of the joint operations calculated based on Eni’s working interest. Information on Eni’s investments as of December 31, 2025 is provided in the “Item 18 - Notes to the Consolidated Financial Statements”. 91 Table of Contents