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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 20-F

(Mark One)

☐ | REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

☑ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025

OR

☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

OR

☐ | SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report

Commission file number: 1-14090

Eni SpA

(Exact name of Registrant as specified in its charter)

Republic of Italy

(Jurisdiction of incorporation or organization)

1, piazzale Enrico Mattei - 00144 Roma - Italy

(Address of principal executive offices)

Francesco Esposito

Eni SpA

1, piazza Ezio Vanoni

20097 San Donato Milanese (Milano) - Italy

Tel +39 02 52061632 - Fax +39 06 59822575

(Name, Telephone, Email and/or Facsimile number and Address of Company Contact Person)

Securities registered or to be registered pursuant to Section 12(b) of the Act.

Title of each class |  | Trading Symbol(s) |  | Name of each exchange on which registered
Shares |  | E |  | New York Stock Exchange*
American Depositary Shares |  |  |  | New York Stock Exchange
(Which represent the right to receive two Shares) |  |  |  | * Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.

Securities registered or to be registered pursuant to Section 12(g) of the Act:

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

Ordinary shares | 3,146,765,114

Table of Contents

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes ☑ No ☐

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

Yes ☐ No ☑

Note - Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☑ Accelerated filer ☐ Non-accelerated filer ☐ Emerging growth company ☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

Indicate by check mark whether the registrant has fi led a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive- based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP ☐ International Financial Reporting Standards as issued by the International Accounting Standards Board ☑ Other ☐

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.

Item 17 ☐ Item 18 ☐

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐ No ☑

​​​Table of Contents

| #### T ABLE OF CONTENTS | ####
|  | #### Page
Certain defined terms | iii
Presentation of financial and other information | iii
Statements regarding competitive position | iii
Glossary | iv
Abbreviations and conversion table | ix
P A R T I |
Item 1. | IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS | 1
Item 2. | OFFER STATISTICS AND EXPECTED TIMETABLE | 1
Item 3. | KEY INFORMATION | 1
| Risk factors | 1
Item 4. | INFORMATION ON THE COMPANY | 18
| History and development of the Company | 18
| BUSINESS OVERVIEW | 31
| Exploration & Production | 31
| Global Gas & LNG Portfolio and Power | 53
| Enilive and Plenitude | 57
| Refining and Chemicals | 62
| Corporate and Other activities | 67
| Research and development | 68
| Insurance | 70
| Environmental matters | 70
| Regulation of Eni’s businesses | 80
| Property, plant and equipment | 91
| Organizational structure | 91
Item 4A. | UNRESOLVED STAFF COMMENTS | 92
Item 5. | OPERATING AND FINANCIAL REVIEW AND PROSPECTS | 92
| Operating results | 92
| Liquidity and capital resources | 113
| Recent developments and significant transactions | 118
| Management’s expectations of operations | 119
Item 6. | DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES | 129
| Directors and Senior Management | 129
| Compensation | 138
| Board practices | 139
| Employees | 155
| Share ownership | 156
Item 7. | MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS | 157

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| Major Shareholders | 157
| Related parties transactions | 157
Item 8. | FINANCIAL INFORMATION | 158
| Consolidated Statements and other financial information | 158
| Significant changes | 158
Item 9. | THE OFFER AND THE LISTING | 159
| Offer and listing details | 159
| Markets | 160
Item 10. | ADDITIONAL INFORMATION | 161
| Memorandum and Articles of Association | 161
| Material contracts | 168
| Exchange controls | 168
| Taxation | 168
| Documents on display | 173
Item 11. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 174
Item 12. | DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES | 176
Item 12A. | Debt securities | 176
Item 12B. | Warrants and rights | 176
Item 12C. | Other securities | 176
Item 12D. | American Depositary Shares | 176
PART II |
Item 13. | DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES | 178
Item 14. | MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS | 178
Item 15. | CONTROLS AND PROCEDURES | 178
Item 16. | [RESERVED] | 179
Item 16A. | Board of Statutory Auditors financial expert | 179
Item 16B. | Code of Ethics | 179
Item 16C. | Principal accountant fees and services | 179
Item 16D. | Exemptions from the Listing Standards for Audit Committees | 180
Item 16E. | Purchases of equity securities by the issuer and affiliated purchasers | 180
Item 16F. | Change in Registrant’s Certifying Accountant | 181
Item 16G. | Significant differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual | 181
Item 16H. | Mine safety disclosure | 184
Item 16I. | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | 184
Item 16J. | Insider trading policies | 184
Item 16K. | Cybersecurity | 184
PART III |
Item 17. | FINANCIAL STATEMENTS | 188
Item 18. | FINANCIAL STATEMENTS | 188
Item 19. | EXHIBITS | 189

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Ce r tain dis c losu r es contained he r ein in c ludin g, without limitation, ce r tain in f ormation appearing in “Item 4 – In f ormation on the Compa n y”, and in pa r ticular “Item 4 – Explo r ation & P r oductio n”, “Item 5 – Ope r ating and Financial R e view and P r ospects” and “Item 11 – Quantitat i v e and Qualitat i v e Dis c losu r es about Ma rk et Risk” contain f or w a r d-looking statements r e g a r ding futu r e e v ents and the futu r e r esults of Eni that a r e based on cur r ent e xpectation s, estimate s, f o r ecast s, and p r ojections about the industries in w hi c h Eni ope r ates and the beliefs and assumptions of the mana g ement of Eni. Eni may also ma k e f or w a r d-looking statements in other written material s, in c luding other documents f iled with or furnished to the U.S. Securities and E x c han g e Commission (the “SEC”). In addition, Eni’s senior mana g ement may ma k e f or w a r d-looking statements o r al l y to ana l yst s, i n v esto r s, r ep r esentat i v es of the media and othe rs. In pa r ticula r, among other statement s, ce r tain statements with r e g a r d to mana g ement object i v e s, t r ends in r esults of ope r ation s, ma r gin s, cost s, r eturn on capital, risk mana g ement and competition a r e f or w a r d looking in natu r e. W o r ds su c h as ‘e xpects’, ‘anticipates’, ‘ta rg ets’, ‘g oals’, ‘p r ojects’, ‘intends’, ‘plans’, ‘beli e v es’, ‘seeks’,‘estimates’, v ariations of su c h w o r d s, and similar e xp r essions a r e intended to identify su c h f or w a r d-looking statement s. These f or w a r d-looking statements a r e on l y p r edictions and a r e subject to risk s, unce r taintie s, and assumptions that a r e dif f icult to p r edict because th e y r elate to e v ents and depend on ci r cumstances that will occur in the futu r e. The r e f o r e, Eni’s actual r esults may dif f er material l y and ad v e r se l y f r om those e xp r essed or implied in a n y f or w a r d-looking statement s. F acto r s that mi g ht cause or contribute to su c h dif f e r ences in c lud e, but a r e not limited t o, those discussed in this Annual R epo r t on F orm 20-F under the section entitled “Risk f acto r s” and else w he r e. A n y f or w a r d-looking statements made b y or on behalf of Eni speak on l y as of the date th e y a r e mad e. Eni does not unde r ta k e to update f or w a r d-looking statements to r eflect a n y c han g es in Eni’s e xpectations with r e g a r d the r eto or a n y c han g es in e v ent s, conditions or ci r cumstances on w hi c h a n y su c h statement is based. The r eader should, h ow e v e r, consult a n y fu r ther dis c losu r es Eni may ma k e in documents it f iles with the SE C.

CE R T AIN DEFINED TERMS

In this F o r m 20-F, the te r ms “Eni”, the “G r oup”, or the “Compa n y” r efer to the pa r ent compa n y Eni SpA and its consolid a ted subsidiaries and, unless the cont e xt otherwise r equi r e s, their r espect iv e p r edecessor companie s. All r efe r ences to “It a l y” or the “St a te” a r e r efe r ences to the R epu b lic of It a l y, a ll r efe r ences to the “G o v ernment” a r e r efe r ences to the g o v ernment of the R epu b lic of It a l y. F or de f initions of certain oil and gas te r ms used he r ein and certain co n v ersion s, see “Glossary” and “Co n v ersion T a b le”.

PRESENTATION OF FINANCIAL AND OTHER INFORMATION

The Consolid a ted Financi a l St a tements of Eni, included in this An n u a l R eport, h a v e been p r epa r ed in acco r dance with Intern a tion a l Financi a l Standa r ds (IFRS) as issued b y the Intern a tion a l Accounting Standa r ds Boa r d (IASB).

Unless otherwise indic a ted, a n y r efe r ence he r ein to “Consolid a ted Financi a l St a tements” is to the Consolid a ted Financi a l St a tements of Eni (including the Notes the r eto) included he r ein.

Unless otherwise speci f ied or the cont e xt otherwise r equi r e s, r efe r ences he r ein to “dollars”, “$”, “U.S. dollars”, “US$” and “USD” a r e to the cur r ency of the United St a te s, and r efe r ences to “eu r o”, “EUR” and “€” a r e to the cur r ency of the Eu r opean Monetary Union.

Unless otherwise specified or the context otherwise requires, references herein to “Division” and “segment” are to any of the following Eni’s business activities: “Exploration & Production” (or “E&P”), “Global Gas & LNG Portfolio and Power”, “Enilive and Plenitude”, “Refining and Chemicals” and “Corporate and Other activities”.

References to Enilive are to Eni’s biofeedstock supply, storage, production, distribution and marketing of biofuels, oil products, biomethane, smart mobility solutions and mobility services, all managed through its fully-owned subsidiary Enilive and its controlled entities. References to Plenitude are to Eni’s retail gas and power activities and services, renewables and e-mobility businesses which are managed through its fully-owned subsidiary Eni Plenitude SpA Società Benefit and Plenitude’s controlled entities. The results of the operations of Enilive and Plenitude are included in the segment information “Enilive and Plenitude” for financial reporting purposes.

R efe r ences to V ers a lis or Chemic a l a r e to Eni’s chemic a l act i vities w hich a r e man a ged th r ough its ful l y-o wned subsidiary V ers a lis and V ers a lis’ cont r olled entitie s. The results of operations of the Chemical business are included in the segment information “Refining and Chemicals” for financial reporting purposes.

For further details on Eni’s business structure and financial reporting segments refer to “Item 4 – Information on the Company”.

Exhibit 99 which contains Eni’s disclosure pursuant to the EU Taxonomy regulation does not form part of this Form 20-F and is not incorporated herein.

S TA TEMENTS REGARDING COMPETITIVE POSITION

St a tements made in “Item 4 – In f o r m a tion on the Compa n y” r eferring to Eni’s competit iv e position a r e based on the Compa n y’s b e lie f, and in some cases re l y on a r ange of sou r ce s, including i n v estment an a l ysts’ r eport s, independent ma r k et studies and Eni’s intern a l assessment of ma r k et sha r e based on pu b lic l y a v ail a b le in f o r m a tion a bout the f inanci a l r esults and per f o r mance of ma r k et participant s. Ma r k et sha r e estim a tes contained in this document a r e based on man a gement estim a tes unless otherwise indic a ted.

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G L OSSA R Y

B e l o w is a s e lection of the most f r equent l y used te r ms th r oughout this An n u a l R eport on F o r m 20-F. A n y r efe r ence he r ein to a non-GAAP measu r e and to its most di r ect l y compa r a b le GAAP measu r e sh a ll be intended as a r efe r ence to a non-IFRS measu r e and the compa r a b le IFRS measu r e.

Financial terms

Identified net gains (losses) | Identified net gains (losses) include certain significant income or charges pertaining to either: (i) infrequent or unusual events and transactions, being identified as non-recurring items under such circumstances; (ii) certain events or transactions which are not considered to be representative of the ordinary course of business, as in the case of environmental provisions, restructuring charges, asset impairments or write ups and gains or losses on divestments even though they occurred in past periods or are likely to occur in future ones. Exchange rate differences and derivatives relating to industrial activities and commercial payables and receivables, particularly exchange rate derivatives to manage commodity pricing formulas which are quoted in a currency other than the functional currency are reclassified in operating profit with a corresponding adjustment to net finance charges, notwithstanding the handling of foreign currency exchange risks is made centrally by netting off naturally-occurring opposite positions and then dealing with any residual risk exposure in the derivative market. Finally, special items include the accounting effects of fair-valued commodity derivatives relating to commercial exposures: in addition to those which lack the criteria to be designed as hedges, also those which are not eligible for the own use exemption, including the ineffective portion of cash flow hedges, as well as the accounting effects of settled commodity and exchange rates derivatives whenever it is deemed that the underlying transaction is expected to occur in future reporting periods. Correspondently, special charges/gains also include the evaluation effects relating to assets/liabilities utilized in a natural hedge relation to offset a market risk, as in the case of accrued currency differences at finance debt denominated in a currency other than the reporting currency, where the cash outflows for the reimbursement are matched by highly probable cash inflows in the same currency. The deferral of both the unrealized portion of fair-valued commodity and other derivatives and evaluation effects are reversed to future reporting periods when the underlying transaction occurs.
Gearing | A non-GAAP measure of the Company’s financial condition, calculated as the ratio between net borrowings and shareholders’ equity plus net borrowings. This ratio is calculated also excluding the IFRS 16 lease liability.
Net bor ro wings | Eni evaluates its financial condition by reference to “net borrowings”, which is a non-GAAP measure. Eni calculates net borrowings as total finance debt less: cash, cash equivalents and certain very liquid investments not related to operations, including among others non-operating financing receivables and securities not related to operations. Non-operating financing receivables consist of amounts due to Eni’s financing subsidiaries from banks and other financing institutions and amounts due to other subsidiaries from banks for investing purposes and deposits in escrow. It includes certain long-term financing receivables due to the Company by affiliates, based on the Company’s sole exposure to counterparty credit risk and as a reimbursement plan has been scheduled. Securities not related to operations consist primarily of government and corporate securities. For a discussion of management’s view of the usefulness of this measure and its reconciliation with the most directly comparable GAAP measure, “Total debt” see “Item 5 – Financial condition”.
TSR (T otal Sha r eholder R eturn) | Management uses this measure to assess the total return on Eni’s shares. It is calculated on a yearly basis, keeping account of the change in market price of Eni’s shares (at the beginning and at end of year) and dividends distributed and reinvested at the ex-dividend date.

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Business terms

ARERA (Italian Regulatory Authority for Energy, Networks and Environment) formerly AEEGSI (Authority for Electricity Gas and Water) | The Italian Regulatory Authority for Energy, Networks and Environment is the Italian independent body which regulates, controls and monitors the electricity, gas and water sectors and markets in Italy. The Authority’s role and purpose is to protect the interests of users and consumers, promote competition and ensure efficient, cost-effective and profitable nationwide services with satisfactory quality levels. Furthermore, since December 2017 the Authority also has regulatory and control functions over the waste cycle, including sorted, urban and related waste.
Associated gas | Associated gas is a natural gas found in contact with or dissolved in crude oil in the reservoir. It can be further categorized as Gas-Cap Gas or Solution Gas.
Average reserve life index | Ratio between the amount of reserves at the end of the year and total production for the year.
Barrel/BBL | Volume unit corresponding to 159 liters. A barrel of oil corresponds to about 0.137 metric tons.
BOE | Barrel of Oil Equivalent. It is used as a standard unit measure for oil and natural gas. The latter is converted from standard cubic meters into barrels of oil equivalent using a certain coefficient (see “Conversion Table” on page ix).
Compounding | Activity specialized in production of semifinished products in granular form, resulting from the combination of two or more chemical products.
Concession contracts | Contracts currently applied mainly in Western countries regulating relationships between states and oil companies with regards to hydrocarbon exploration and production. The company holding the mining concession has an exclusive right on exploration, development and production activities and for this reason it acquires a right to hydrocarbons extracted against the payment of royalties on production and taxes on oil revenues to the state.
Condensates | Condensates are a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
Consob | The Italian National Commission for listed companies and the stock exchange (Commissione Nazionale per le Società e la Borsa).
Contingent resources | Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies.
Conversion capacity | Maximum amount of feedstock that can be processed in certain dedicated facilities of a refinery to obtain finished products. Conversion facilities include catalytic crackers, hydrocrackers, visbreaking units, and coking units.
Conversion index | Ratio of capacity of conversion facilities to primary distillation capacity. The higher the ratio, the higher is the capacity of a refinery to obtain high value products from the heavy residue of primary distillation.
Deep waters | Waters deeper than 200 meters.
Development | Drilling and other post-exploration activities aimed at the production of oil and gas.
Enhanced recovery | Techniques used to increase or stretch over time the production of wells.
Eni carbon efficiency index | Ratio between GHG emissions (Scope 1 and Scope 2 in tonnes CO 2 eq.) of the main industrial activities operated by Eni divided by the productions (converted by homogeneity into barrels of oil equivalent using Eni’s average conversion factors) of the single businesses of reference.

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EPC | Engineering, Procurement and Construction.
EPCI | Engineering, Procurement, Construction and Installation.
Exploration | Oil and natural gas exploration that includes land surveys, geological and geophysical studies, seismic data gathering and analysis and well drilling.

FPSO | Floating Production Storage and Offloading System.
FSO | Floating Storage and Offloading System.
Greenhouse Gases (GHG) | Gases in the atmosphere, transparent to solar radiation, that trap infrared radiation emitted by the earth’s surface. The greenhouse gases relevant within Eni’s activities are carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O). GHG emissions are commonly reported in CO2 equivalent (CO2eq) according to Global Warming Potential values in line with IPCC AR4, 4th Assessment Report.
Infilling wells | Infilling wells are wells drilled in a producing area in order to improve the recovery of hydrocarbons from the field and to maintain and/or increase production levels.
LNG | Liquefied Natural Gas obtained through the cooling of natural gas to minus 160 °C at normal pressure. The gas is liquefied to allow transportation from the place of extraction to the sites at which it is transformed back into its natural gaseous state and consumed. One tonne of LNG corresponds to 1,400 cubic meters of gas.
LPG | Liquefied Petroleum Gas, a mix of light petroleum fractions, gaseous at normal pressure and easily liquefied at room temperature through limited compression.
Margin | The difference between the average selling price and direct acquisition cost of a finished product or raw material excluding other production costs (e.g. refining margin, margin on distribution of natural gas and petroleum products or margin of petrochemical products). Margin trends reflect the trading environment and are, to a certain extent, a gauge of industry profitability.
Mineral Potential | (Potentially recoverable hydrocarbon volumes) Estimated recoverable volumes which cannot be defined as reserves due to a number of reasons, such as the temporary lack of viable markets, a possible commercial recovery dependent on the development of new technologies, or for their location in accumulations yet to be developed or where evaluation of known accumulations is still at an early stage.
Natural gas liquids (NGL) | Liquid or liquefied hydrocarbons recovered from natural gas through separation equipment or natural gas treatment plants. Propane, normal-butane and isobutane, isopentane and pentane plus, that were previously defined as natural gasoline, are natural gas liquids.
Net Scope 1+2 Upstream | Scope 1 and Scope 2 GHG emissions associated with Eni’s upstream operations or third parties’, accounted for on a financial perimeter basis, net of carbon credits mainly from Natural Climate Solutions and Technological solutions.
Net Scope 1+2 Eni | Scope 1 and Scope 2 GHG emissions associated with Eni’s operations or third parties’, accounted for on a financial perimeter basis, net of carbon credits mainly from Natural Climate Solutions and Technological solutions.

Net Intensity Scope 1+2+3 | Ratio between the GHG emissions Scope 1+2+3 (net of carbon credits mainly from Natural Climate Solutions and Technological solutions) and the energy content of products sold.
Network Code | A code containing norms and regulations for access to, management and operation of natural gas pipelines.
Oilfield chemicals | Innovative solutions for supply of chemicals and related ancillary services for Oil & Gas business.
Over/Under lifting | Agreements stipulated between partners which regulate the right of each to its share in the production for a set period of time. Amounts lifted by a partner different from the agreed amounts determine temporary Over/Under lifting situations.

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Possible reserves | Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
Probable reserves | Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
Primary balanced refining capacity | Maximum amount of feedstock that can be processed in a refinery to obtain finished products measured in BBL/d.
Production Sharing Agreement (PSA) | Contract regulates relationships between states and oil companies with regard to the exploration and production of hydrocarbons. 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 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.
Proved reserves | Proved oil and gas reserves are those quantities of oil and 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, and 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, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Reserves are classified as either developed and undeveloped. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
REDD+ | REDD+ stands for Reducing Emissions from Deforestation and Forest Degradationand the “+” symbolizes additional activities related to conservation, sustainable forest management, and enhancement of forest carbon stocks. This scheme was designed by the United Nations (United Nations Framework Convention on Climate Change - UNFCCC) and anchored in Article 5 of the Paris Agreement. It involves conserving forests to reduce emissions and improve the natural storage capacity of CO 2, as well as protecting biodiversity and promoting local communities socio-economic development.
Renewable Installed Capacity | Renewable Installed Capacity is measured as the maximun generating capacity of Eni’s share of power plants that use renewable energy sources (wind, solar and wave, and any other non-fossil fuel source of generation deriving from natural resources, excluding, from the avoidance of doubt, nuclear energy) to produce electricity. The capacity is considered “installed” once the power plants are in operation or the mechanical completion phase has been reached. The mechanical completion represents the final construction stage excluding the grid connection.
Reserves | Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

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Reserve life index | Ratio between the amount of proved reserves at the end of the year and total production for the year.
Reserve replacement ratio | Measure of the reserves produced replaced by proved reserves. Indicates the company’s ability to add new reserves through exploration and purchase of property. A rate higher than 100% indicates that more reserves were added than produced in the period. The ratio should be averaged on a three-year period in order to reduce the distortion deriving from the purchase of proved property, the revision of previous estimates, enhanced recovery, improvement in recovery rates and changes in the amount of reserves – in PSAs – due to changes in international oil prices.
Scope 1 GHG Emissions | Direct greenhouse gas emissions from company’s operations, produced from sources that are owned or controlled by the company.
Scope 2 GHG Emissions | Indirect greenhouse gas emissions resulting from the generation of electricity, steam and heat purchased from third parties and consumed by assets owned or controlled by the company.
Scope 3 GHG Emissions | Indirect GHG emissions associated with the value chain of Eni’s products.
SERM (Standard Eni Refining Margin) | It approximates the margin of Eni's refining system in consideration of the refinery
Ship-or-pay | Clause included in natural gas transportation contracts according to which the customer is requested to pay for the transportation of gas whether or not the gas is actually transported.
Take-or-pay | Clause included in natural gas supply contracts according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of gas set in the contract whether or not the gas is collected by the purchaser. The purchaser has the option of collecting the gas paid for and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years.
Title Transfer Facility | The Title Transfer Facility, more commonly known as TTF, is a virtual trading point for natural gas in the Netherlands. TTF Price is quoted in euro per megawatt hour and, for business day, is quoted day-ahead, i.e. delivered next working day after assessment.
UN SDGs | The Sustainable Development Goals (SDGs) are the blueprint to achieve a better and more sustainable future for all by 2030. Adopted by all United Nations Member States in 2015, they address the global challenges the world is facing, including those related to poverty, inequality, climate change, environmental degradation, peace and justice. For further detail see the website https://unsdg.un.org
Upstream/Downstream | The term upstream refers to all hydrocarbon exploration and production activities. The term downstream includes all activities inherent to the oil and gas sector that are downstream of exploration and production activities.
Upstream GHG Emission intensity | Ratio between 100% Scope 1 GHG emissions from Upstream operated assets and 100% gross operated production (expressed in barrel of oil equivalent).

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ABBREVI A TIONS

mmCF | = million cubic feet | mmtonnes | = million tonnes
BCF | = billion cubic feet | MW | = megawatt
mmCM | = million cubic meters | GWh | = gigawatthour
BCM | = billion cubic meters | TWh | = terawatthour
BOE | = barrel of oil equivalent | /d | = per day
|  | /y | = per year
KBOE | = thousand barrel of oil equivalent |  |
mmBOE | = million barrel of oil equivalent |  |
BBOE | = billion barrel of oil equivalent |  |
BBL | = barrels |  |
KBBL | = thousand barrels |  |
mmBBL | = million barrels |  |
BBBL | = billion barrels |  |
mmBTU | = million British thermal unit |  |
ktonnes | = thousand tonnes |  |
KW | = kilowatt |  |
GW | = gigawatt |  |
Gcal | = giga calorie |  |

CONVERSION T ABLE

1 acre | = 0.405 hectares |
1 barrel | = 42 U.S. gallons |
1 BOE | = 1 barrel of crude oil | = 5,232 cubic feet of n a tu r a l gas
1 barrel of crude oil per day | = approximately 50 tonnes of crude oil per year |
1 cubic meter of natural gas | = 35.3147 cubic feet of natural gas |
1 cubic meter of natural gas | = approximately 0.00675 barrels of oil equivalent |
1 kilometer | = approximately 0.62 miles |
1 short ton | = 0.907 tonnes | = 2,000 pounds
1 long ton | = 1.016 tonnes | = 2,240 pounds
1 tonne | = 1 metric ton | = 1,000 kilograms
|  | = approximately 2,205 pounds
1 tonne of crude oil | = 1 metric ton of crude oil | = approximately 7.3 barrels of crude oil (assuming an API gravity of 34 degrees)

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Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

NOT APPLICABLE

Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE

NOT APPLICABLE

Item 3. KEY INFORM A TION

RISK FACTORS

Eni is exposed to the effects of changing commodity prices and margins

Eni is primarily in a commodities business that has a history of price volatility. The most significant factor that affects the Company’s results of operations and cash flow is the price of crude oil, which can be influenced by several variables, including general economic conditions and level of economic growth or recessionary conditions; industry production and inventory levels; technology advancements, including those in pursuit of a lower carbon economy; greenhouse gas emissions and climate change; production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries (“OPEC”) or other producers; weather-related damage and disruptions due to other natural or human causes beyond Eni’s control; competing fuel prices; geopolitical risks; the pace of energy transition; customer and consumer preferences and the use of substitutes; and governmental regulations, policies and other actions regarding the development of oil and gas reserves. Eni evaluates the risk of changing commodity prices as a core part of its business planning process and resource allocation. An investment in the Company carries significant exposure to fluctuations in global crude oil prices and, to a lesser extent, in prices of other energy commodities.

In the short term, crude oil prices are mainly determined by the balance between global oil supply and demand, and the global levels of commercial inventories. A downturn in economic activity normally triggers lower global demand for crude oil, possibly resulting in oversupplies and inventories build-up, because in the short term, producers are unable to quickly adapt to swings in demand. Whenever global supplies of crude oil exceed demand, crude oil prices decrease. In the short term, global demand for crude oil is influenced by macroeconomic trends in large consuming countries (such as China, India and the United States) as well as any financial crisis, levels of inflation and interest rates, geo-political crisis, local conflicts, wars, strikes, attacks, sabotages (particularly in the crude oil-rich area of Middle East), social and political instability, pandemic diseases, flows of international commerce, trade disputes and governments’ fiscal policies, extreme weather events and natural disruptions, among others. Furthermore, trends in the market of crude oil derivatives contracts (futures and options), where material volumes of paper barrels are exchanged daily amongst financial operators (including commodity trading advisories, hedge funds and commodity specialists), can significantly affect short-term movements in crude oil prices driven by operators’ sentiment and expectations about the future direction of price which shape their positioning (long vs. short on the commodity). Considering that volumes exchanged daily in the paper market are several times greater than physical daily exchanges, the role of financial operators, who have been increasingly relying on algorithmic trading amplifying price movements in either direction, can overturn supply and demand fundamentals.

On the supply side, currently there is ample availability of crude oil. Notwithstanding the United States is the main oil producer in the world since the shale oil revolution of 2011, in the short term global balances are influenced to a considerable extent by the system of production quotas and level of spare capacity held by the Organization of the Petroleum Exporting Countries “OPEC” and its allied countries, among them Russia and Kazakhstan, known as the OPEC+ alliance, which have signed a declaration of cooperation (“DoC”) few years ago, designed to stabilize crude oil prices through production ceilings and voluntary production cuts. Therefore, decisions on part of the OPEC+ about production levels can have a significant influence on the price of crude oil in the short term. For example, in April 2025, the alliance resolved to start returning to the market a portion of the production cuts made in previous years, triggering a correction in the price of crude oil.

In the long term, demand for crude oil may be negatively affected by development of alternative energy sources (e.g., nuclear and renewables), technological breakthroughs, shifts in consumer preferences, and measures and other initiatives adopted by governments to tackle climate change and to curb carbon dioxide emissions (CO 2 emissions), including stricter regulations and control on production and consumption of crude oil. Eni’s management believes the push to reduce worldwide greenhouse gas emissions and the ongoing energy transition towards a low carbon economy could materially affect the worldwide energy mix and may lead to structural lower crude oil demands and prices. See the risk factor titled “Rising concerns about climate change and the effects of the energy transition could lead to a decline in demand for hydrocarbons and potentially lower prices” below.

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After a solid start to 2025 with prices in the 75-80 $/bbl range, the price of the commodity has been gradually declining since the second quarter of the year due to a combination of weakening fundamentals and bearish expectations about future price direction among financial operators. Global economic growth has slowed down pressured by the trade disputes commenced by the USA administration against its main partners affecting international commercial flows, in addition to an uncertain recovery path of the Chinese economy, and by high interest rates. Persistent geopolitical tensions in the Middle East, while the armed invasion of Ukraine by Russia has been dragging on without resolution, have also negatively affected investors and consumers’ confidence and hence economic activity. Finally, the decision of member countries of the OPEC+ alliance to unwind a significant portion of the voluntary production cuts made in April/November 2023, while US production remained resilient and other areas like Brazil and Guyana showed remarkable growth increased oil supplies at a time when demand growth was moderating. Furthermore, fundamental trends shaping current imbalances have been amplified by the bearish positioning of speculative traders, who for the first time on record have retained a net short position in the future contracts for the US crude benchmark (the West Texas Intermediate “WTI”) in August 2025, accelerating an ongoing price downturn. This was a landmark event, because never in the history of the futures market traders have been so negative about future crude oil prices, including the Great Financial Crisis of 2008, the 2015-2016 downturn and the COVID pandemic recession, and occurred notwithstanding the physical balances, albeit on a weakening trend, did not indicate a significantly oversupplied market. This flagged a possible heightened risk for the oil price in relation to the prevalence of speculative trading over physical flows in dictating the price direction in the short term. Due to those developments, crude oil prices for the Brent benchmark have declined to a range of 60-70 $/bbl for the rest of the year to close at a yearly average price of 69 $/bbl (down 14.5% y-o-y), plunging to the lowest level in more than five years at around 60 $/bbl in early January 2026. Since then, prices have been recovering steadily to over 100$/bbl at the start of March 2026, due to escalating tensions in the Middle East that have culminated in acts of war involving the USA, Israel and Iran, as financial operators began discounting risks of possible disruptions to crude oil flows from the Gulf. Considering the uncertainties related to possible evolution of the tensions in Middle East as well as in the military aggression of Ukraine by Russia, based on a review of market fundamentals and assuming moderate growth in the global economy, the management estimates the price of the Brent crude oil at 70 $/bbl (nominal terms) in 2026.

The drivers of prices and demand for natural gas are like those of crude oil. The development of massive liquefaction capacity that has occurred in recent years in countries like the United States, Qatar and Australia has helped to develop a global liquid market of gas, with traders being able to redirect LNG volumes from one geography to another based on price arbitrages. Differently from crude oil, the absolute levels of natural gas prices change from region to region due to specific supply dynamics (e.g. in 2025 the price of natural gas in the United States was one fifth that of Europe, because Europe is a net importer, whilst the United States is currently an oversupplied market due to growing domestic production), while consumption of natural gas is significantly exposed to seasonal patterns and competition from renewables. All those trends may result in a high degree of volatility in natural gas prices. In 2025, natural gas prices in Europe were on average in line compared to 2024 reflecting more pronounced seasonal consumption rather than improving fundamentals as new, significant liquefaction capacity entered into operations in the United States, Canada, where the first LNG exporting project started operations, and production rose in China, which is a net importer of LNG. Against the backdrop of increased supplies, industrial activity, the main driver of gas demand, remained weak in Europe and China, and electricity generation from renewables continued to grow. The outlook for natural gas prices in the short to medium term is compounded by expectations of material additions of LNG production capacity in the United States and Qatar, the emergence of Canada as a new potential large supplier, and rising competition from renewables. In the long-term, demand for natural gas is exposed to the risks of the transition to a low-carbon economy.

The volatility of hydrocarbon prices significantly affects the Group’s financial performance. Lower hydrocarbon prices negatively affect the Group’s consolidated results of operations and cash flow; while the opposite effect is caused by a rise in prices. This is because lower prices translate into lower revenues recognized in the Company’s Exploration & Production segment at the time of the price change, whereas expenses in this segment are either fixed or less sensitive to changes in crude oil prices than revenues. The Group is mainly exposed to the price of crude oil as featured by the fact that the same relative change in the crude oil price yields a considerably larger impact at the Group’s results of operations and cash flow than the gas price. This is because a significant portion of natural gas production volumes are marketed at fixed prices or are indexed to the price of crude oil.

In 2025, the average Brent crude oil price declined by 14.5% compared to 2024 and that reduced Exploration & Production operating profit by an estimated amount of €1.8 billion and the cash flow by an estimated €1.6 billion.

Considering the massive price volatility of the commodity and the fact that Eni does not hedge its future expected cash flows from the sale of its proved reserves, except for specific market situations or transactions, management is fully committed to retaining efficient operations to preserve the profitability of its oil&gas business and a healthy balance sheet across the cycle. In case we fail to achieve low breakeven prices at our portfolio of projects, our results of operations and cash flow could be overexposed to the commodity risk.

Finally, movements in hydrocarbon prices significantly affect the reportable amount of production and proved reserves under our production sharing agreements (“PSAs”), which represented 60% of our proved reserves as of end of 2025. The entitlement mechanism of PSAs foresees the Company 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 higher the reference prices for Brent crude oil used to estimate Eni’s proved reserves, the lower the number of barrels necessary to recover the same amount of expenditure, and vice versa. In 2025, our reported production and reserves were increased by an estimated amount of respectively around 4 KBOE/d and by 12 mmBOE due to a decreased Brent reference price. Considering the current portfolio of oil&gas assets, the Company estimates its production to vary by up to 1 KBOE/d for each one-dollar change in the price of the Brent crude oil.

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Eni’s Refining and Chemical businesses are in cyclical economic sectors. Their results are impacted by trends in the supply and demand of oil products and commodity plastics, which are influenced by macro-economic variables and by competitive dynamics which ultimately determine the level of product prices. Margins for refined and chemical products depend upon the speed at which products’ prices adjust to reflect movements in oil prices.

All these risks may adversely and materially impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholders returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s share.

There are increasing systemic risks to the macroeconomic outlook, which could trigger a global slowdown negatively affecting demand for hydrocarbons, and hence our results of operations.

There are several risk factors to the macroeconomic outlook in the short term.

Escalating tensions in the Middle East have culminated in acts of war involving the U.S., Israel and Iran at the end of February/early March 2026 with risks of possible enlargement of the conflict and of ensuing possible disruptions in the flow of crude oil and LNG from the Gulf which could increase volatility in the price of these commodities and trigger a slowdown in the global economy or in the worst of cases a recession with huge implications for global demand of crude oil and other energy commodities.

Russia’s military aggression of Ukraine has been dragging on since February 2022, amidst several failed attempts to reach a peaceful solution and recent military threats against neighboring European countries by Russia. This conflict has negatively impacted the global economy and triggered an energy crisis in Europe as well as a downturn in industrial activity, given the disruption in political and trading relationships between Western Countries and Russia, reverberating through supply chains, the need on part of EU countries to replace cheap gas supplies from Russia, as well as increased cybersecurity threats. In response to Russia’s aggression, the EU nations, the UK, and the United States have adopted severe economic and financial sanctions to curb Russia’s ability to fund the war, which are negatively affecting the overall economic activity.

Trade disputes between the USA and its main commercial partners, like China, the EU, India and Japan, and the imposition of import duties could disrupt global supply chains and reduce international commercial flows, which could significantly and negatively affect economic growth and hydrocarbons demand.

High interest rates, particularly over the long-term yield curve, rooted in the need to finance massive state deficit in the USA and in other leading countries could destabilize financial markets and suppress economic activity.

Continuing and escalating tensions in the Middle East including risks of possible large-scale conflict, the protracting of the military aggression of Ukraine by Russia, a deterioration of commercial relationships between the USA and other countries, destabilization of financial markets and high interest rates pose risks to the macroeconomic recovery because they can eventually undermine consumers’ confidence and deter investment decisions, thus increasing the risks of a worldwide slowdown or, under a worst-case scenario, a global recession. Such developments could negatively and significantly affect hydrocarbons demand, leading to lower commodity prices and adversely impacting our results of operations and cash flow, as well as business prospects, with a possible lower remuneration of our shareholders.

Risks in connection with our presence in Russia and our commercial relationships with Russia’s State-owned companies

The most important exposure of Eni to Russia is relating to the existence of long-term gas supply contracts with take-or-pay clauses with Russian state-owned company Gazprom and its affiliates.

In the most recent three-year timeframe, we made no liftings at our current, long-term contracts with Gazprom to serve our customers in European markets or to support our trading activities at European hubs. The year 2022 was the last one when volumes supplied from Russia represented a material amount in our portfolio of gas supplies (see table “Natural gas supply” in Item 4 – Global Gas & LNG Portfolio, providing information about the last three-year period). This situation was due to the unilateral decision from our Russian supplier to suspend deliveries to Eni in 2023, against the backdrop of a commercial dispute between the two parties. We have substantially replaced Russian-origin gas in our portfolio with volumes coming from other suppliers and geographies, and our objective is to terminate the current supply contracts with our Russian counterparties in the shortest possible timeframe. This may entail operational and financial risks which may be significant.

There is strong competition worldwide, both within the oil industry and with other industries, to supply energy and petroleum products to the industrial, commercial, and residential energy markets

Eni operates in commodity sectors, which feature prices and margins volatility due to their cyclical nature, limited product differentiation, comparatively higher production expenses in Europe vs other geographies and, in the case of the E&P business, complex relationships with state-owned companies and national agencies of the countries where hydrocarbon reserves are located to obtain mineral rights. Furthermore, competition within commodity industries is significantly influenced by the economic cycle.

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Normally an economic downturn negatively affects demand for commodities leading to a more intense price competition. As commodity prices are not within Eni’s control, Eni’s ability to remain competitive and profitable in this environment requires continuous focus on technological innovation, efficiencies in operating costs, effective management of capital resources and the supply of valuable services to energy buyers. It also depends on Eni’s ability to gain access to new investment opportunities. Competitive trends represent a risk to the profitability of all Eni’s business segments:

• E&P may be negatively affected by its relatively smaller scale compared to other players in the industry;

• The business of marketing gas in the European wholesale market managed by the GGP segment is exposed to pricing competition and competition from renewables considering anticipated weak demand trends in Europe;

• The businesses of oil refining and production of basic chemical products located mainly in Europe are exposed to ongoing weak demand trends, global overcapacity, lack of technological entry barriers, competition from players with large economies of scale and cost advantages, which are operating in geographies characterized by lower energy expenses and environmental liabilities compared to Europe, and finally growing market penetration by more sustainable products. In 2025, Eni’s refining business incurred an operating loss of €1.1 billion affected by inventory valuation, reflecting lower prices and, in part, lower volumes for the main commodities, in a market environment that remains challenging due to weak demand, overcapacity and competitive pressure from other geographical areas. Eni’s Chemical business incurred an operating loss for the fourth year in a row (€1.4 billion in 2025) due to the above-mentioned weak business fundamentals which have been exacerbated by the comparatively higher energy inputs of manufacturing activities in Europe with respect to other geographies following the European energy crisis of 2022, which has further reduced the competitiveness of the Eni’s chemical activity against the backdrop of macroeconomic headwinds.

• The business of marketing gas and electricity to the retail market managed by our subsidiary Plenitude, is exposed to the competitive trends of the retail market, which is characterized by an almost complete deregulation, an ever-increasing number of suppliers, low entry barriers, and customers’ ability to switch readily from one supplier to another. The same applies to retail marketing of fuels which is managed by our subsidiary Enilive, operating in a market characterized by intense price competition and low brand loyalty. Enilive also engages in the manufacturing of biofuels and returns of this activity are exposed to the competition risks in connection with oversupplies and dumping by unregulated operators and an uncertain regulatory framework. In the first part of 2025, the margins on the sale of biofuels were significantly affected by those trends. However, as the year progressed, we observed a gradual rebalancing driven by a surge in demand. Several factors have contributed to this situation, including the concentrated demand due to annual compliance requirements being in the third and fourth quarters of the year. Additionally, scheduled maintenance activities, such as those conducted by Neste, and export restrictions on SAF from China.

More information about Eni’s segments competitive trends is disclosed in Item 4.

The Group has launched a plan intended to recover profitability at its loss-making chemicals business, which comprises significant expenditures for plant upgrading and is subject to an execution risk.

In consideration of the structural weaknesses of the European petrochemicals industry, plagued by global overcapacity, competitive pressures, reduced demand and comparatively higher production costs than in other geographies (like energy inputs and environmental obligations), the Company has launched a plan intended to improve the profitability at its petrochemicals arm, which has been incurring operating losses for years (with the sole exception of the year of the COVID pandemic). In 2025, the Chemical business reported an adjusted operating loss of €819 million. This plan comprises the shutdown of loss-making plants and a significant capital expenditure program to upgrade and reconvert the business to manufacture products for the energy transition (like biofuels, batteries to accumulate electricity, among others). This plan is subject to an execution risk in connection with the need to obtain all licenses and permits by relevant administrative authorities to close plants and build new facilities, as well as to the possible incurrence of unforeseen costs and liabilities. In case we fail to execute the plan as designed by the management or in case of cost overruns or other liabilities, our future results of operations and cash flow may be significantly and negatively affected.

Rising concerns about climate change and the effects of the energy transition could lead to a decline in demand for hydrocarbons and potentially lower prices. This risk may also lead to additional legal and/or regulatory measures, resulting in project delays or cancellations, potential additional litigation, operational restrictions, and additional compliance obligations and expenses. Climate change could also have a physical impact on our assets and supply chains.

Societal demand for urgent action on climate change has increased, especially since the Intergovernmental Panel on Climate Change (IPCC) Special Report of 2018 on 1.5°C effectively made the more ambitious goal of the Paris Agreement to limit the rise in global average temperature this century to 1.5 degrees Celsius the default target. This increasing focus on climate change and drive for an energy transition have created a risk environment that is changing rapidly, resulting in a wide range of governmental actions at global, local and company levels, increasing pressure from civil society and the investing and lending community to speed up our decarbonization plans.

The energy transition, as well as increasingly stricter regulations in the field of CO 2 emissions, could entail risks to the Group’s financial performance and business prospects, because the Company still relies substantially on the legacy business of Exploration & Production.

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Firstly, international initiatives and national, regional, and state legislation and regulations targeting GHG emissions are in various stages of design, adoption, and implementation. These policies and initiatives - some of which support the global net zero emissions ambitions of the Paris Agreement - can change the amount of energy consumed, the rate of energy-demand growth, the energy mix, and the relative economics of one fuel versus another. Laws and regulations whether already in force or under consideration are seeking to limit greenhouse gas (GHG) emissions by taxing them or by imposing operational restrictions and other compliance costs on oil&gas companies. Regulators may seek to limit certain oil and gas projects or make it more difficult to obtain required permits. Additionally, climate activists are challenging the grant of new and existing regulatory permits. We expect that these challenges and protests are likely to continue and could delay or prohibit operations in certain cases. We also expect that actions by customers to reduce their emissions and changing consumers’ preferences will continue to lower demand and potentially affect prices for fossil fuels, as will tax incentives in support of electric vehicles and renewables and other low-carbon solutions.

The pace and extent of the energy transition could pose a risk to Eni if we decarbonize our operations and the energy we sell at a different speed relative to society. If we are slower than society, customers may prefer a different supplier, which would reduce demand for our products and adversely affect our reputation besides materially affecting our results of operations and cash flow. If we move much faster than society, we risk investing in technologies, markets or low-carbon products that are unsuccessful because there is limited demand for them, negatively affecting investment returns.

The physical effects of climate change such as, but not limited to, increases in temperature and sea levels and fluctuations in water levels could also adversely affect our operations and supply chains.

Certain investors have decided to divest from fossil fuel companies, which could undergo growing scrutiny from financial market participants to obtain funds and borrowing facilities. If this were to continue, it could have a material adverse effect on the price of our securities, our ability to access capital markets and hence the cost of capital to the Group. Stakeholder groups are also putting pressure on commercial and investment banks to stop financing fossil fuel companies. Some financial institutions have started to limit or cease altogether their exposure to fossil fuel projects. Accordingly, our ability to use financing for these types of future projects may be adversely affected.

In some countries, governments, regulators, organizations, and individuals have filed lawsuits seeking to hold oil companies liable for costs associated with climate change or seeking to have oil companies condemned to speed up decarbonization plans based on alleged crimes against the environment or human rights violations. While we believe these lawsuits to be without merit, losing could have a material adverse effect on our business.

In summary, rising climate change concerns, the pace at which we decarbonize our operations relative to society and effects of the energy transition have led and could lead to a decrease in demand and potentially affect prices for fossil fuels. If we are unable to find economically viable, publicly acceptable solutions that reduce our GHG emissions and/or GHG intensity for new and existing projects and for the products we sell, we could experience financial penalties or extra costs, delayed or cancelled projects, potential impairments of our assets, additional provisions and/or reduced production and product sales, negatively affecting future results of operations, cash flow, liquidity, business prospects, financial condition, shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares may be adversely and significantly affected.

The Company will continue to develop oil and gas resources to meet customers’ and consumers’ demand for energy, targeting to increase the proportion of natural gas in the production mix. At the same time, Eni has been implementing a strategy designed to gradually reduce the weight of hydrocarbons in the Company’s portfolio by growing the businesses of renewable energy and manufacturing of biofuels and, as well as developing new technologies in the fields of nuclear energy, plastic recycling, and other energy vectors and solutions, like the geological permanent sequestration of CO 2, to decarbonize hard-to-abate products or processes with the long-term goal of achieving net zero emissions of CO 2 at the whole of its products and processes by 2050. Eni integrates climate change-related issues and the regulatory and other responses to these issues into its strategy and planning, capital investment reviews, and risk management tools and processes, where it believes they are applicable. They are also factored into the Company’s long-range supply, demand, and energy price forecasts. These forecasts reflect estimates of long-range effects from climate change-related policy actions, such as electric vehicle and renewable fuel penetration, energy efficiency standards, and demand response to oil and natural gas prices. In case demand for hydrocarbons declines more rapidly than management’s planning assumptions and capital programs, our results of operations and business prospects may be significantly and negatively affected.

The above-mentioned risks may emerge in the short, medium and long term.

a) Regulatory risk: increasing worldwide efforts to tackle climate change may lead to the adoption of stricter regulations to curb carbon emissions and this could lead to increasing expenditures in the short term and may end up suppressing demands for our products in medium-to-long term.

It is possible that a growing share of our GHG emissions may be subject to regulation going forward, resulting in increased compliance costs and operational constraints. Regulatory actions intended to reduce greenhouse gas emissions include adoption of cap and trade regimes, carbon taxes, carbon-based import duties or other trade tariffs, minimum renewable usage requirements, restrictive permitting, increased mileage and other efficiency standards, mandates for sales of electric vehicles, mandates for use of specific fuels or technologies, and other incentives or mandates designed to support transitioning to lower-emission energy sources. Depending on how policies and regulations are formulated and applied, such policies and regulations could negatively affect our investment returns, make our hydrocarbon-based products more expensive or less competitive, lengthen project implementation times, and reduce demand for hydrocarbons, as well as shift hydrocarbon demand toward relatively lower-carbon alternatives. Current and pending greenhouse gas regulations or policies may also increase our compliance costs, such as for monitoring, tracking or sequestering emissions.

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Some governments have already introduced carbon pricing schemes. Eni’s operating and compliance expenses could increase in the short-to-medium term in case of widespread adoption of carbon tax mechanisms. Currently, about half of the direct GHG emissions coming from Eni’s operated assets are included in national or supranational Carbon Pricing Mechanisms, such as the European Emissions Trading Scheme (ETS), which provides an obligation to purchase, on the open market, emission allowances in case GHG emissions exceed a pre-set amount of emission allowances allotted for free. In 2025 to comply with this carbon emissions scheme, Eni accrued an expense of around €800 million for allowances corresponding to 11.3 million tons of CO 2 emissions (11.7 million tons in 2024 for a total expense of €850 million). Due to the likelihood of new regulations in this area and expectations of a reduction in free allowances under the European ETS and the likely adoption of similar schemes in other jurisdictions, Eni could incur increased investments and higher operating expenses in case the Company is unable to reduce the carbon footprint of its operations.

It is also possible that new restrictions on oil&gas activities may be introduced in response to the climate emergency. Governments in jurisdictions where we operate may deny permissions to start new oil and gas projects or may impose restrictions on drilling and other field activities. These possible developments could significantly and negatively affect our business’s prospects and results of operations.

b) Market/Technological risk: in the long-term demands for hydrocarbons may be materially reduced by the projected mass adoption of electric vehicles, the development of green hydrogen, the deployment of massive investments to grow renewable energies also supported by governments fiscal policies and the development of other technologies to produce clean feedstock, fuels, and energy.

In the long term, the weight of hydrocarbons in the global energy mix may decline due to an expected growth in the volumes of energy generated by renewable sources, the possible emergence of new products and technologies, as well as changing consumers’ preferences. Sales of electric vehicles (EVs) are expected to overcome internal-combustion-engine sales in the future, as is occurring in China, also helped by state tax-incentives and governmental or intergovernmental targets on the production of EVs and in certain instances also proposed restrictions or ban on sales of internal-combustion-engine cars. In the long term this trend could disrupt the consumption of gasoline which is one of the main drivers of global crude oil demand. For example, the rapid adoption of EVs in China is deemed to have displaced an amount of gasoline corresponding to circa one million barrels of crude oil as per certain market sources. Other potentially disruptive technologies designated to produce clean energy and fuels are emerging, driven by the development of hydrogen-based solutions as an energy vector or the utilization of renewables feedstock to manufacture fuels and other goods replacing oil-based products. Electricity generation from wind power and solar panels has grown materially worldwide, with massive additions in China, and is projected to continue growing at rapid pace in line with the stated targets by several governments and institutions like the EU and the UK to decarbonize the electricity sector, and this could reduce demand for gas-fired electricity generation. Finally, some market forecasters are projecting a resurgence of investments in nuclear capacity due to a changing perception from public opinions and institutions about the role of this form of energy in the global mix and its being carbon neutral. As a matter of fact, the EU has recently upgraded nuclear energy as a net zero emission technology.

These trends could reduce demand for hydrocarbons in the long-term.

A large portion of Eni’s business depends on the global demand for oil and natural gas. If existing or future laws, regulations, treaties, or international agreements related to GHG and climate change, including state incentives to conserve energy or use alternative energy sources, technological breakthroughs in the field of renewable energies, hydrogen, production of nuclear energy or mass adoption of electric vehicles trigger a structural decline in worldwide demand for oil and natural gas, Eni’s results of operations and business prospects may be materially and adversely affected in case the Company fails to adapt its business model at the same pace of the energy transition as the economy.

c) Legal risk: several lawsuits are pending in various jurisdictions against oil&gas companies based on alleged violations of human rights, damage to the environment and other claims and such legal actions may be brought against us.

In recent years, there has been a marked increase in climate-based litigation. Courts could be more likely to hold companies that have allegedly made the most significant contributions to climate change to account. Cases brought to courts against oil&gas companies in several jurisdictions indicate that there are risks that oil and gas companies may have an individual legal responsibility to reduce emissions to address climate change based on an alleged relationship between climate change and human rights violations. Courts may condemn oil and gas companies to compensate individuals, communities, and states for the economic losses due to global warming because of their alleged responsibility in supporting hydrocarbons and their alleged awareness of knowingly hurting the environment. In some cases, companies’ boards have been summoned for having allegedly failed to take effective actions to contrast climate change.

Private individuals, associations and NGOs may also bring legal actions against states or companies to get them condemned to adopt stricter targets of reducing GHG emissions and that could entail more restrictive measures on businesses. For example, in 2023, certain NGOs and several private citizens filed a complaint before an Italian court claiming that Eni is liable for the alleged impact on climate change in connection with its industrial activities and for alleged human rights violations. The plaintiffs requested compensation for economic losses and other damages and requested that Eni revises its decarbonization strategy and immediately stops any harmful conduct.

As such, climate litigation represents a significant risk. In case the Company is condemned to reduce its GHG emissions at a much faster rate than planned by management or to compensate for damage related to climate change due to ongoing or potential lawsuits, we could incur a material adverse effect on our results of operations and business’s prospects.

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d) Reputational risk: the consideration of oil&gas companies as poorly performing investments from an environmental standpoint by financial market participants, could reduce the attractiveness of their securities or limit their ability to access the capital markets. Activist investors have been seeking to interfere in companies’ plans and strategies through matter of shareholders’ resolutions and other means.

The reputational risk of oil&gas companies owes to the growing perception by certain governments, financial institutions, and the society that those companies may be allegedly liable for global warming due to GHG emissions across the hydrocarbon value chain, particularly related to the use of energy products, and may be poorly performing players in the ESG dimensions. This could possibly impair their reputation and make their securities and debt instruments less attractive than other industrial sectors to investors and lenders.

Asset managers, mutual funds, global allocation funds, generalist investors and pension funds have been reducing their exposure to the fossil fuel industry due to the adoption of stricter ESG criteria in selecting investing opportunities. In some cases, these investors have adopted climate change targets in determining their policies of asset allocations. Many of them have announced plans to completely divest from the fossil fuel industry. This trend could reduce the market for our share and negatively affect shareholders’ returns. Likewise, banks, financing institutions, lenders and insurance companies are cutting exposure to the fossil fuel industry due to the need to comply with ESG mandate or to reach emission reduction targets in their portfolios and this could limit our ability to access new financing, could drive a rise in borrowing costs to us or increase the costs of insuring our assets. Several large, well established financing institutions have announced their intention to stop financing directly the development of new oil and gas fields, a move that could herald an emerging trend among banks and lenders towards a phase-out of financing the hydrocarbons sector.

As a result of those developments, we could expect the cost of capital to the Company to rise in the future and reduced ability on part of Eni to obtain financing for future projects in the oil&gas business or to obtain it at competitive rates, which may curb our investment opportunities or drive an increase in financing expenses, negatively affecting our results of operations, returns on investments and business prospects.

Shareholders and activist funds may have resolutions passed at annual general meetings of listed oil&gas companies, which could interfere with management’s long-term goals, strategies and capital allocation processes leading to unplanned cost increases and sub-optimal investment decisions. Activist investors may also bring lawsuits against oil&gas companies and their boards, claiming their responsibilities for not implementing adequate strategies to manage the transition risk; and we believe that such kind of claims can be brought against us.

e) Climate change adaptation: extreme weather phenomena, which are allegedly caused by climate change, may disrupt our operations

The scientific community has concluded that increasing global average temperature produces significant physical effects, such as the increased frequency and severity of hurricanes, storms, droughts, floods, or other extreme climatic events that could interfere with Eni’s operations and damage Eni’s facilities. Extreme and unpredictable weather phenomena can result in material disruption to Eni’s operations, and consequent loss of or damage to properties and facilities, as well as a loss of output, loss of revenues, increasing maintenance and repair expenses and cash flow shortfall.

As a result of these trends, climate-related risks could have a material and adverse effect on the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholders returns, including dividends and the price of Eni’s shares.

Investments in our low or zero carbon products and services may not achieve expected returns

We are building our portfolio of low or zero carbon products and services such as electricity generated from solar and wind power, manufacturing of biofuels, projects for permanent geological sequestration of CO 2, and a network of chargers for electric vehicles through organic and inorganic growth.

In expanding our offering of these products and services, we expect to undertake acquisitions and form partnerships also in the form of third-party investments in our subsidiaries developing those nascent businesses. The success of these transactions will depend on our ability to realize the synergies from combining our respective resources and capabilities, including the development of new processes, systems and distribution channels. For example, it may take time to develop these areas through retraining our workforce and recruitment for the necessary new skills. It may take longer to realize the expected returns from these transactions.

The operating margins for our lower carbon products and services may not be as high as the margins we have experienced historically in our oil and gas operations. Furthermore, lower carbon products are experiencing increasing competition risks. Biofuels prices can be negatively affected by oversupplies and an uncertain regulatory environment which may negatively affect final users’ purchase decisions. Renewable electricity sold at spot markets is exposed to risks of uneconomic pricing or curtailed volumes, due to objective limits of current transmission networks to handle peak production volumes which are a feature of the renewable sector.

Finally, the capital contributions made by third-party investors in our subsidiaries, also in the form of purchase of non-controlling stakes, will entail a growing stream of dividends to non-controlling shareholders, which are expected to affect our cash flow, also considering our projections of improving results of our low or zero carbon businesses.

Therefore, developing our low or zero carbon products and services is subject to challenges which could have a material adverse effect on future results of operations, cash flow, liquidity, business prospects, financial condition, shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares may be adversely and significantly affected.

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Risk deriving from Eni’s exposure to weather conditions

Significant changes in weather conditions in Italy and in the rest of Europe from year to year may affect demand for natural gas and some refined products. In colder years, demand for such products is higher. Accordingly, the results of operations of Eni’s businesses engaged in the marketing of natural gas and, to a lesser extent, the Refining business, as well as the comparability of results over different periods may be affected by such changes in weather conditions. Over recent years, this pattern could have been possibly affected by the rising frequency of weather trends like milder winter or extreme weather events like heatwaves or unusually cold snaps.

The Group is exposed to significant operational and economic risks associated with the exploration and production of crude oil and natural gas

The exploration and production of oil and natural gas is a capital-intensive business, which requires high levels of expenditure and is subject to specific operational and economic risks as well as to natural hazards and other uncertainties. The natural hazards and the economic risks described below could have an adverse and significant impact on Eni’s future growth prospects, results of operations, cash flows, liquidity, and shareholders’ return.

a) Operational risks in connection to drilling and extraction operations

The physical and geological characteristics of oil and gas fields entail natural hazards and other operational risks including risks of eruptions of hydrocarbons, discovery of hydrocarbon pockets with abnormal pressure, crumbling of well openings, oil spills, gas leaks, risks of blowout, fire or explosion and risks of earthquake in connection with drilling and extraction activities. Eni has material offshore operations which are inherently riskier than onshore activities. In 2025, approximately 73% of Eni’s total oil and gas production for the year derived from offshore fields, mainly in Norway, Egypt, Libya, Kazakhstan, Indonesia, Angola, Congo and the United Arab Emirates. Offshore accidents and oil spills could cause damage of catastrophic proportions to the ecosystem and to communities’ health and security due to the apparent difficulties in handling hydrocarbons containment in the sea, pollution, poisoning of water and organisms, length and complexity of cleaning operations and other factors. Furthermore, offshore operations are subject to marine risks, including storms and other adverse weather conditions and perils of vessel collisions, which may cause material adverse effects on the Group’s operations and the ecosystem.

b) Exploratory drilling efforts may be unsuccessful

Exploration activities are mainly subject to the mining risk, i.e. the risk of dry holes or failure to find commercial quantities of hydrocarbons. The costs of drilling and completing wells have margins of uncertainty, and drilling operations may be unsuccessful because of a large variety of factors, including geological failure, unexpected drilling conditions, pressure or heterogeneity in formations, equipment failures, well control (blowouts) and other forms of accidents. A large part of the Company’s exploratory drilling operations is located offshore, including in deep and ultra-deep waters, in remote areas and in environmentally sensitive locations (such as the Barents Sea, the Gulf of Mexico, deep water leases off West Africa, Indonesia, the Mediterranean Sea and the Caspian Sea). In these locations, the Company generally experiences higher operational risks and more challenging conditions and incurs higher exploration costs than onshore. Furthermore, deep and ultra-deep water operations require significant time before commercial production of discovered reserves can commence, increasing both the operational and the financial risks associated with these activities.

Because Eni plans to make significant investments in executing exploration projects, it is likely that the Company will incur significant amounts of dry hole expenses in future years. Unsuccessful exploration activities and failure to discover additional commercial reserves could reduce future production of oil and natural gas, which is highly dependent on the rate of success of exploration projects and could have an adverse impact on Eni’s future performance, growth prospects and returns.

c) Development projects bear significant operational risks which may adversely affect actual returns

Projects to develop and market reserves of crude oil and natural gas normally entail long lead times because of the complexity of the activities required to achieve the production start-up, which comprise:

• appraising a discovery to evaluate the economic and operating viability of a development project;

• finalizing negotiations with joint venture partners, governments and state-owned companies, suppliers and potential customers to define project terms and conditions, including, for example, the fiscal take, the production sharing terms with the first party, or negotiating favorable long-term contracts to market gas reserves;

• obtaining timely issuance of permits and licenses by government agencies, including obtaining all necessary administrative authorizations to drill locations, install producing infrastructures, build pipelines and related equipment to transport and market hydrocarbons;

• effectively carrying out the front-end engineering design in order to prevent the occurrence of technical inconvenience during the execution phase;

• timely manufacturing and delivery of critical plants and equipment by contractors, like platforms and floating production storage and offloading (FPSO) vessels, or market availability for renting such kind of vessels, as well as building transport infrastructures to export production to final markets. For example, in case of a shortage of FPSOs to rent, we may have no other option than to build the facility thus incurring upfront the whole costs of the investment, which could negatively affect a project’s return;

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• preventing risks associated with the use of new technologies and the inability to develop advanced technologies to maximize the recoverability rate of hydrocarbons or gain access to previously inaccessible reservoirs;

• carefully planning the commissioning and hook-up phase where misstep might lead to delays in achieving first oil and rising expenses;

• changes in operating conditions and cost overruns. Since the post-COVID recovery, the industry has been experiencing higher inflationary pressures than in the past or compared to other sectors of the economy. This has been driven by the fact that suppliers of complex plants and equipment (like floating production vessels) are very concentrated, and providers of oilfield services and drilling rigs have undergone a restructuring process during the oil downturn resulting in reduced investment in new drilling facilities and fewer players; for example oilfield service providers Saipem and Subsea7 are in the process of executing a merger agreement. Therefore, we expect construction costs as well as costs of renting rigs and other drilling vessels and facilities to remain elevated as oil companies compete for a stable amount of supply of this kind of equipment;

• operating risks, including third-party claims, environmental protests and claims, changes to the work scope requested by governmental authorities, contractors’ underperformance.

Moreover, projects executed with partners and joint venture partners limit the ability of the Company to manage risks and costs, and Eni may have limited influence over and control of the operations and performance of its partners.

The occurrence of any of these risks may negatively affect the time-to-market of the reserves and may cause cost overruns and start-up delays, lengthening the project payback period. Those risks would adversely affect the economic returns of Eni’s development projects and the achievement of production growth targets, also considering that those projects are exposed to the volatility of oil and gas prices which may be substantially different from those estimated when the investment decision was made, thereby leading to lower return rates.

Finally, if the Company is unable to develop and operate major projects as planned, or in case actual reservoir performance and natural field decline do not meet management’s expectations, it could incur significant impairment losses of capitalized costs associated with reduced future cash flows of those projects.

d) Inability to replace produced oil and natural gas reserves could adversely impact results of operations and financial condition, including cash flows

Future oil and gas production depends on the Company’s ability to access new reserves through new discoveries, application of improved techniques, success in development activity, negotiations with national oil companies and other owners of known reserves and acquisitions.

An inability to replace produced reserves by discovering, acquiring, and developing additional reserves could adversely impact future production levels and growth prospects. If Eni is unsuccessful in meeting its long-term targets of reserve replacement, Eni’s future total proved reserves and production will decline.

e) Uncertainties in estimates of oil and natural gas reserves

The accuracy of proved reserve estimates and of projections of future rates of production and timing of development costs depends on several factors, assumptions and variables, including:

• the quality of available geological, technical and economic data and their interpretation and judgment;

• management’s assumptions regarding future rates of production and costs and timing of operating and development costs. The projections of higher operating and development costs may impair the ability of the Company to economically produce reserves leading to downward reserve revisions;

• changes in the prevailing tax rules, other government regulations and contractual terms and conditions;

• results of drilling, testing and the actual production performance of Eni’s reservoirs after the date of the estimates which may drive substantial upward or downward revisions; and

• changes in oil and natural gas prices which could affect the quantities of Eni’s proved reserves since the estimates of reserves are based on prices and costs existing as of the date when these estimates are made. Lower oil prices may impair the ability of the Company to economically produce reserves leading to downward reserve revisions.

Many of the factors, assumptions and variables underlying the estimation of proved reserves involve management’s judgement or are outside management’s control (prices, governmental regulations) and may change over time, therefore affecting the estimates of oil and natural gas reserves from year-to-year.

The prices used in calculating Eni’s estimated proved reserves are, in accordance with the U.S. Securities and Exchange Commission (the “U.S. SEC”) requirements, calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12 months. For the 12-month ending at December 31, 2025, average prices were based on 70 $/barrel for the Brent crude oil, 11 $/barrel lower than the 2024 reference price 81 $/barrel, resulting in us having to remove 12 million BOE of reserves that have become uneconomical at a lower price.

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Accordingly, the estimated reserves reported as of the end of 2025 could be significantly different from the quantities of oil and natural gas that will be ultimately recovered. Any downward revision in Eni’s estimated quantities of proved reserves would indicate lower future production volumes, which could adversely impact Eni’s business prospects, results of operations, cash flows and liquidity.

f) The development of the Group’s proved undeveloped reserves “PUD” may take longer and may require higher levels of capital expenditures than it currently anticipates, or the Group’s proved undeveloped reserves may not ultimately be developed or produced

As of December 31, 2025, approximately 44% of the Group’s total estimated proved reserves (by volume) were undeveloped and may not be ultimately developed or produced. Recovery of PUD requires significant capital expenditures and successful drilling operations. The Group’s reserve estimates assume the Group can and will commit these expenditures and conduct these operations successfully. These assumptions may prove to be inaccurate, are subject to the risk of a structural decline in the prices of hydrocarbons, which could reduce available funds to develop PUD, or management can change capital allocation plans or withdraw its commitment to develop certain projects. The Group’s reserve report as of December 31, 2025, includes estimates of total future development and decommissioning costs associated with the Group’s proved total reserves of approximately €45.3 billion (undiscounted, including consolidated subsidiaries and equity-accounted entities; €41.7 billion in 2024). It is uncertain that estimated costs of the development of these reserves will prove correct, development will occur as scheduled, or the results of such development will be as estimated. In case of change in the Company’s plans to develop those reserves, or if it is not otherwise able to successfully develop these reserves as a result of the Group’s inability to fund necessary capital expenditures due to a prolonged decline in the price of hydrocarbons or otherwise, it will be required to remove the associated volumes from the Group’s reported proved reserves.

g) The oil&gas industry is a capital-intensive business and needs a large amount of funds to find and develop reserves. In case the Group does not have access to sufficient funds its oil&gas business may decline

The oil and gas industry is a capital-intensive business. Eni makes and expects to continue making substantial capital expenditures in its business for the exploration, development and production of oil and natural gas reserves. Historically, Eni’s capital expenditures have been financed with cash generated from operations, proceeds from asset disposals, borrowings under its credit facilities and proceeds from the issuance of debt and bonds. The actual amount and timing of future capital expenditures may differ materially from Eni’s estimates because of, among other things, changes in commodity prices, changes in cost of oil services and other inputs, available cash flows, lack of access to capital, actual drilling results, the availability of drilling rigs and other services and equipment, the availability of transportation capacity, and regulatory, technological and competitive developments. Eni’s cash flows from operations and access to capital markets are subject to several variables, including but not limited to:

• the amount of Eni’s proved reserves;

• the volume of crude oil and natural gas Eni is able to produce and sell from existing wells;

• the prices at which crude oil and natural gas are marketed

• Eni’s ability to acquire, find and produce new reserves; and

• the ability and willingness of Eni’s lenders to extend credit or of participants in the capital markets to invest in Eni’s bonds considering that adoption of ESG targets by lenders may restrict our access to third-party financing.

If cash generated by operations, cash from asset disposals, or cash available under Eni’s liquidity reserves and credit facilities or from issuance of new bonds is not sufficient to meet capital requirements, or in case of otherwise failure to obtain additional financing, due to among other things a decline in oil and gas prices or more stringent ESG criteria adopted by banks and other lenders, we may be forced to curtail our operations relating to the development of Eni’s reserves and revise our capital plans, which in turn could adversely affect the Company’s results of operations and cash flows and its ability to achieve its growth objectives. We plan to invest a major part of the Group €29 billion gross expenditure budgeted for the next five-year plan 2026-2030 to explore for and develop hydrocarbons reserves. In case of a cash flow shortfall, we may be forced to take on new finance debt from banks and financing institutions to pursue our development plans and that could increase our financial risk profile. Finally, funding Eni’s capital expenditures with additional debt will increase its leverage and the issuance of additional debt will require an increasing portion of Eni’s cash flows from operations to be used for the payment of interest.

h) Oil and gas activity may be subject to increasingly high levels of income taxes and royalties

Oil and gas operations are subject to the payment of royalties and income taxes, which tend to be higher than those payable in other commercial activities. Management believes that the marginal tax rate in the oil and gas industry tends to increase in correlation with higher oil prices, which could make it more difficult for Eni to translate higher oil prices into increased net profit. However, the Company does not expect that the marginal tax rate will decrease in response to falling oil prices. Adverse changes in the tax rate applicable to the Group’s profit before income taxes in its oil and gas operations would have a negative impact on Eni’s future results of operations and cash flows.

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After the energy crisis of 2022 following Russia’s military aggression of Ukraine, the recent events in the Middle East have put again surging hydrocarbon prices on the political agenda as they hit the psychological level of over 100 $/bbl triggering criticism on part of governments, businesses, and consumers in the Eurozone because high oil prices are perceived to hamper competitiveness of the manufacturing sector and to reduce the purchase power of households. Given rising pressures on public finances due to an ongoing economic slowdown in the EU and the general consideration that oil&gas companies may continue benefiting from the ongoing geopolitical tensions in Ukraine and the Middle East, management cannot rule out the possibility of the introduction of new windfall taxes and other extraordinary levies targeting the hydrocarbons sector, signaling an increased fiscal risk for oil&gas companies and energy manufacturers and traders, which could negatively affect the Group’s results of operations and cash flows in case of a recovery in commodity prices.

i) The present value of future net revenues from Eni’s proved reserves will not necessarily be the same as the current market value of Eni’s estimated crude oil and natural gas reserves

The present value of future net revenues from Eni’s proved reserves may differ from the current market value of Eni’s estimated crude oil and natural gas reserves. In accordance with the U.S. SEC rules, Eni bases the estimated discounted future net revenues from proved reserves on the 12-month unweighted arithmetic average of the first day of the month commodity prices for the preceding twelve months. Actual future prices may be materially higher or lower than the SEC pricing method in the calculations. Actual future net revenues from crude oil and natural gas properties will be affected by factors such as:

• the actual prices Eni receives for sales of crude oil and natural gas;

• the actual cost and timing of development and production expenditures;

• the timing and amount of actual production; and

• changes in governmental regulations or taxation.

The timing of both Eni’s production and its incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. Additionally, the 10% discount factor Eni uses when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with Eni’s reserves or the crude oil and natural gas industry in general.

At December 31, 2025, the net present value of Eni’s proved reserves totaled approximately €42.9 billion, representing a decrease of €12.6 billion from the estimated amount at December 31, 2024. The average prices used to estimate Eni’s proved reserves and the net present value at December 31, 2025, as calculated in accordance with the SEC rules, were at around 70 $/barrel for the Brent crude oil. Actual future prices may materially differ from those used in our year-end estimates..

Risks related to political considerations

As at December 31, 2025, about 84% of Eni’s proved hydrocarbon reserves were located in non-OECD (Organization for Economic Co-operation and Development) countries, mainly in Africa, Central Asia and Middle East where the socio-political framework, the financial system and the macroeconomic outlook are less stable than in the OECD countries. In those non-OECD countries, Eni is exposed to a wide range of political risks and uncertainties, which may impair Eni’s ability to continue operating economically on a temporary or permanent basis, and Eni’s ability to access oil and gas reserves. Particularly, Eni faces risks in connection with the following potential issues and risks:

• socio-political instability leading to internal conflicts, revolutions, establishment of non-democratic regimes, protests, attacks, and other forms of civil disorder and unrest, such as strikes, riots, sabotage, blockades, vandalism, and theft of crude oil at pipelines, acts of violence and similar events. These risks could result in disruptions to economic activity, loss of output, plant closures and shutdowns, project delays, loss of assets and threats to the security of personnel. They may disrupt financial and commercial markets, including the supply of and pricing for oil and natural gas, and generate greater political and economic instability in some of the geographical areas in which Eni operates. Additionally, any possible reprisals because of military or other action, such as acts of terrorism in Europe, the USA or elsewhere, could have a material adverse effect on the world economy and hence on the global demand for hydrocarbons;

• lack of well-established and reliable legal systems and uncertainties surrounding the enforcement of contractual rights;

• unfavorable enforcement of laws, regulations and contractual arrangements leading, for example, to expropriation, nationalization or forced divestiture of assets and unilateral cancellation or modification of contractual terms, tax or royalty increases (including retroactive claims) and restrictions on exploration, production, imports and exports;

• sovereign default or financial instability since those countries rely heavily on petroleum revenues to sustain public finance. Financial difficulties at country level often translate into failure by state-owned companies and agencies to fulfil their financial obligations towards Eni relating to funding capital commitments in projects operated by Eni or to timely paying for supplies of equity oil and gas volumes;

• difficulties in finding qualified international or local suppliers in critical operating environments;

• risks of international sanctions which could impair our ability to conduct profitable operations or to recover our investments like the U.S. sanctions designated to impact on the oil sector of Venezuela; and

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• complex processes of granting authorizations or licenses affecting time-to-market of development projects.

Areas where Eni operates and where the Company is particularly exposed to political risk include, but are not limited to Libya, Venezuela, and Egypt.

Eni’s operations in Libya are exposed to geopolitical risks. The social and political instability of the country dates to the revolution of 2011 that brought a change of regime and a civil war with a material impact on our operations in that year. A divided political landscape emerged from those events, which caused a prolonged period of internal instability which has triggered several acts of internal conflict, armed clashes, civil turmoil, and unrest involving the opposing factions amidst failed attempts to hold general elections and appoint a national government, resulting in several disruptions to Eni’s activities in the country. In the last few years, the situation has improved somewhat, and no significant disruptions have occurred. However, the political landscape of the Country has remained split between the Government of National Unity installed in Tripoli and recognized by the UN and the self-appointed National Stability Government installed in the east of the country and has resulted in several disputes and reciprocal claims. This constitutes a continuing source of instability. In 2025, Eni production in Libya was 155 kboe/d, equal to about 10% of the Group’s total production and was in line with management’s plans. 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.

Venezuela has experienced a prolonged period of financial and economic crisis due to the US sanction regime intended to block the Country’s oil exports and revenues, which in turn have impaired our ability to conduct profitable operations in the country. At the beginning of 2026, a new government took office, and a legislative process started to amend the Country’s Hydrocarbon law with a view to stimulating investments. Those developments could revive the Country’s ailing oil sector, also with involvement of certain international oil companies who have been granted general licenses by the US administration. Currently, after having impaired other projects in past reporting periods, the Company retains one main asset in Venezuela: the 50%-participated Cardón IV joint venture, which is operating an offshore natural gas field and is supplying its production to the national oil company, Petroleos de Venezuela SA (“PDVSA”), under a long-term supply agreement. PDVSA has defaulted on the payments of the receivables for the gas volumes supplied by Cardón IV venture and consequently the Company has recorded a significant amount of overdue trading receivables owed by PDVSA. In 2025, due to the US administration’s tightening of the sanction regime against the Venezuela oil sector, we were unable to execute any swap transaction with PDVSA to obtain reimbursement in-kind of our outstanding receivables. As of December 31, 2025, Eni's credit exposure to PDVSA amounted to approximately nominal $2.3 billion, excluding accrued interest, stated at an estimated value of around $1.0 billion, net of a loss provision. The Country’s recent developments could make less uncertain the recoverability of our receivables than the previous status of the Country as our Company has been involved in discussions with US relevant authorities about possible involvement of Eni in the relaunch of the Venezuela oil sector.

Egypt has been experiencing financial restraints due to an economic slowdown and a contraction in reserves of foreign currencies as fallout of the conflict situation in Middle East. Eni is currently supplying its equity share of natural gas production to state-owned oil companies that in the past have failed to pay receivables owed to us in a timely manner; in 2025 the situation has improved reducing almost completely the overdue balance.

Sanction targets

The sanction programs relevant to Eni are those issued by the European Union and the United States and, as of today, the restrictive measures adopted by such authorities in respect of Russia.

As a consequence of Russia’s military aggression of Ukraine, the European Union, the United Kingdom, the United States and the G-7 countries adopted a comprehensive system of sanctions against Russia to weaken its economy and its ability to finance the war. The sanction system is constantly evolving.

The main targets of the sanctions are the Russian Central Bank and the major financial institutions of the country, as well as Russia’s exports of crude oil and refined products to international markets, as well as EU proposed restrictive measures against imports of Russian LNG. Considering the complexity of the sanctions and the fact that Eni engages in trading crude oil, gas, LNG and refined products in international markets and also owing to the Company’s current gas supply contracts with Russian counterparts (as described above), the Company is exposed to the risk of possible violations of the sanctions regime.

Eni has adopted the necessary measures to ensure that its activities are carried out in accordance with the applicable rules, ensuring continuous monitoring of the evolution in the sanction framework, to adapt on an ongoing basis its activities to the applicable restrictions.

Furthermore, an escalation of the international crisis, resulting in a tightening of sanctions, could entail a significant disruption of energy supply and trade flows globally, which could have a material adverse effect on the Group’s business, financial conditions, results of operations and prospects.

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Specific risks of the Company’s gas and electricity businesses

a) Any negative trends in the competitive environment of the European wholesale gas sector may impair the Company’s ability to fulfil its minimum off-take obligations in connection with its take-or-pay, long-term gas supply contracts

Eni is currently party to a number of long-term gas supply contracts with state-owned companies of key producing countries, from where most of the gas supplies directed to Europe are sourced via pipeline (Algeria and Norway). These 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. Long-term gas supply contracts with take-or-pay clauses expose the Company to a volume risk, as the Company is obligated to purchase an annual minimum volume of gas, or in case of failure, to pay the underlying price. The structure of the Company’s portfolio of gas supply contracts is a risk to the profitability outlook of Eni’s wholesale gas business should these take-or-pay clauses be activated, which the Company does not expect to happen in the coming years. Furthermore, the Company’s wholesale business is exposed to volatile spreads between the procurement costs of gas, which are linked to spot prices at European hubs or to the price of crude oil, and the selling prices of gas which are mainly indexed to spot prices at the Italian hub.

Eni’s management is planning to continue its strategy of renegotiating the Company’s long-term gas supply contracts in order to constantly align pricing terms to current market conditions as they evolve and to obtain greater operational flexibility to better manage the take-or-pay obligations (volumes and delivery points among others), considering the risk factors described above. The revision clauses included in these contracts state the right of each counterparty to renegotiate the economic terms and other contractual conditions periodically, in relation to ongoing changes in the gas scenario. Management believes that the outcome of those renegotiations is uncertain in respect of both the amount of the economic benefits that will be ultimately obtained and the timing of recognition of profit. Furthermore, in case Eni and the gas suppliers fail to agree on revised contractual terms, both parties can start an arbitration procedure to obtain revised contractual conditions. All these possible developments within the renegotiation process could increase the level of risks and uncertainties relating the outcome of those renegotiations.

b) 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 and other regulatory risks

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 tariff remain in force under the applicable regulatory framework. Developments in the regulatory framework aimed at increasing the level of market liquidity, promoting deregulation or limiting operators’ ability to pass supply cost increases onto customers may negatively affect future sales margins of gas and electricity, operating results, and cash flow at our Plenitude subsidiary, which engages in those markets. For example, based on our experience, in case of an upward trend in commodity prices the Authority may enact measures intended to cap the cost of the raw materials in pricing formulae applied by retail companies that market natural gas and electricity to residential customers, thus reducing sales margins.

Our GGP business that engages in the wholesale marketing of gas and the power generation business that sell produced electricity on the spot market could be exposed to a regulatory risk, although on a smaller scale than the retail business due to well-established and liquid spot markets for gas and electricity.

Law Decree No. 162 (the so called “Law Decree Bollette”), adopted by the Council of Ministers and published in the Gazzetta Ufficiale on February 21, 2026, introduces a set of regulatory measures within the Italian energy framework aimed at reducing the cost of electricity and gas supplies for businesses and households end users. This Decree primarily targets to: (i) reduce or eliminate the spread between wholesale gas prices at European markets and Italian prices (the so called PSV–TTF spread); (ii) disincentivize strategic or opportunistic withholding of spare thermoelectric generation capacity; and (iii) to introduce, for the 2026–2027 regulatory period, a voluntary discount on electricity supplies for certain segments of residential customers. In addition, for the same two-year period, the decree introduces a two-percentage point increase in an Italian regional income tax rate for companies operating in the energy sector. These measures have introduced a risk factor for the Group’s economic performance, primarily due to the potential reduction of the PSV–TTF spread, which could negatively affect margins on equity gas and marketed gas, and to a lesser extent due to the voluntary discount on residential electricity supplies. Those effects could, however, be offset by lower energy input costs to Eni’s refining, biorefining, and petrochemical plants. Assuming a price scenario reflecting the wholesale gas price trend implied by evolution of the forward curves in the days immediately following the issuance of the decree, the overall estimated impact on the Group’s consolidated operating results would not be significant. Regarding the increase in the Italian Regional Income tax rate, the effect is negligible, also considering the expected evolution of the taxable base.

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ENVIRONMENTAL, HEALTH AND SAFETY RISKS.

a) The Group is exposed to material HSE risks due to the nature of its operations

The Group engages in the exploration and production of crude oil and gas, processing, transportation and refining of crude oil, transport of natural gas by pipeline, transport of LNG by carriers, storage and distribution of petroleum products and the production of base chemicals, plastics, and elastomers. The Group’s operations expose Eni to a wide range of significant health, safety, security, and environmental risks. Flammability and toxicity of hydrocarbons, 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 scale, geographical reach, 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.

b) Eni expects to incur material operating expenses and expenditures in future years in relation to compliance with applicable environmental, health and safety regulations, including compliance with any national or international regulation on greenhouse gas (GHG) emissions, as well as to retain high standards of reliability in its industrial operations

Eni’s activities are highly regulated. Laws and regulations intended to preserve the environment and to safeguard health and safety of workers and communities impose several obligations, requirements, and prohibitions to the Company’s businesses due to their inherent risky nature because of flammability, dangerousness, and toxicity of hydrocarbons and of objective complexities of industrial processes to explore, develop, extract, refine, handle and transport oil, natural gas, liquefied natural gas and products. These laws and regulations require acquisition of a permit before drilling for hydrocarbons may commence, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with exploration, drilling and production activities, including refinery and petrochemical plant operations, limit or prohibit drilling activities in certain protected areas, require to remove and dismantle drilling platforms and other equipment and well plugging once oil and gas operations have terminated, provide for measures to be taken to protect the safety of the workplace, the health of employees, contractors and other Company collaborators and of communities involved by the Company’s activities, and impose criminal and civil liabilities for polluting the environment or harming employees’ or communities’ health and safety as result from the Group’s operations. These laws and regulations control the emission of scrap substances and pollutants, discipline the handling of hazardous materials and waste and set limits to or prohibit the discharge of soil, water or groundwater contaminants, emissions of toxic gases and other air pollutants or can impose taxes on carbon dioxide emissions, as in the case of the European Trading Scheme that requires the purchase of an emission allowance for each ton of carbon dioxide emitted in the environment above a pre-set threshold, resulting from the operation of oil and natural gas extraction and processing plants, petrochemical plants, refineries, service stations, vessels, oil carriers, pipeline systems and other facilities owned or operated by Eni.

Breaches of environmental, health and safety laws and regulations as in the case of negligent or willful release of pollutants and contaminants into the atmosphere, the soil, water or groundwater or exceeding the concentration thresholds of contaminants set by the law expose the Company to the incurrence of liabilities associated with compensation for environmental, health or safety damage and expenses for environmental remediation and clean-up, as well as damage to reputation. Furthermore, in the case of violation of certain rules regarding the safeguard of the environment and the health and safety of employees, contractors, and other collaborators of the Company, and of communities, the Company may incur liabilities in connection with the negligent or willful violations of laws by its employees as per Italian Law Decree No. 231/2001.

Management expects that the Group will continue to incur significant amounts of operating expenses and expenditures in the foreseeable future to comply with laws and regulations, to upgrade plants and equipment to improve security standards and to safeguard the environment and the health and safety of employees, contractors and communities involved by the Company activities by retaining reliable industrial operations and by adhering to industry best practices, including:

• costs to prevent, control, eliminate or reduce release of pollutants and other hazardous materials in the soil, groundwater and the marine environment, and of GHG and other toxic gases in the atmosphere, as well as to maintain high standards of efficiency and reliability at its plants and equipment, including offshore platforms, FPSO vessels, oil&gas treatment plants, refineries, petrochemical complexes and pipelines;

• remedial and clean-up measures related to environmental contamination or accidents at various sites, including those owned by third parties, as well as decommissioning costs of productive infrastructures and well plugging of industrial hubs and oil and gas fields once production and manufacturing activities are discontinued; and

• damage compensation claimed by individuals and entities, including local, regional, or state administrations in case Eni is found liable of a HSE incident, contamination, pollution of marine or water resources, soil or the atmosphere, or violations of HSE laws.

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As a further consequence of any new laws and regulations or other factors, like the actual or alleged occurrence of environmental damage at Eni’s plants and facilities, the Company may be forced to curtail, modify, or cease certain operations or implement temporary shutdowns of facilities. Furthermore, in certain situations where Eni is not the operator, the Company may have limited influence and control over third parties, which may limit its ability to manage and control such risks.

c) The Group is exposed to operational risks in connection with the transportation of hydrocarbons

All of Eni’s segments of operations involve, to varying degrees, the transportation of hydrocarbons. Risks in transportation activities depend on several factors and variables, including the hazardous nature of the products transported due to their flammability and toxicity, the transportation methods utilized (pipelines, shipping, river freight, rail, road and gas distribution networks), the volumes involved and the sensitivity of the regions through which the transport passes (quality of infrastructure, population density, environmental considerations). All modes of transportation of hydrocarbons are particularly exposed to risks of blowout, fire, release of toxic agents in the atmosphere, spillover of oil and other pollutants and loss of containment and, given that normally high volumes are involved, could present significant risks to people, environment and property.

d) The Group is not insured against all potential HSE risks

Eni retains worldwide third-party liability insurance coverage, which is designed to hedge part of the liabilities associated with possible incidents occurring at the Group plants and installations resulting in damage to third parties, loss of value to the Group’s assets related to adverse events and in connection with environmental clean-up and remediation. Management believes that its insurance coverage is in line with industry practice and is enough to cover normal risks in its operations. However, the Company is not insured against all potential risks. In the event of a major environmental disaster, such as the incident which occurred at the Macondo well in the Gulf of Mexico several years ago, Eni’s third-party liability insurance would not provide any material coverage and thus the Company’s liability would far exceed the maximum coverage provided by its insurance. The loss Eni could suffer in case of a disaster of material proportions would depend on all the facts and circumstances of the event and would be subject to a whole range of uncertainties, including legal uncertainty as to the scope of liability for consequential damages, which may include economic damage not directly connected to the disaster. The Company cannot guarantee that it will not suffer any uninsured loss and there can be no guarantee, particularly in the case of a major environmental disaster or industrial accident, that such a loss would not have a material adverse effect on the Company.

The Company has invested and will continue to invest significant financial resources to continuously upgrade the methods and systems for safeguarding the reliability of its plants, production facilities, well execution, vessels, transport and storage infrastructures, the safety and the health of its employees, contractors, local communities, and the environment, to prevent risks, to comply with applicable laws and policies and to respond to and learn from unforeseen incidents. However, these measures may ultimately not be completely successful in preventing and/or altogether eliminating risks of adverse events. Failure to properly manage these risks as well as accidental events like human errors, unexpected system failure, sabotages, cyberattacks or other unexpected factors could cause incidents of any kind of impact and magnitude which could trigger in a worst case scenario serious consequences, including loss of life, damage to properties, environmental pollution, legal liabilities and/or damage claims and consequently a disruption in operations and potential economic losses that could have a material and adverse effect on the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares. For example, in December 2024, a fire occurred at a fuel storage site operated by Eni, which caused the death of five people while working at site operations, several wounded and damage to property. The Group made a loss provision to account for all damage to people and property because insurance coverage was not enough.

LEGAL, IT AND FINANCIAL RISKS

a) Eni is exposed to the risk of material environmental liabilities in connection with pending litigation

Eni has incurred in the past and may incur in the future material environmental liabilities in connection with the alleged breach of environmental laws claimed by administrative bodies and third parties at industrial hubs where the Group is currently performing its activities or where the Group has ceased to operate and is performing decommissioning and remediation activities. Eni is also exposed to claims under environmental requirements and, from time to time, such claims have been made against the Company. Furthermore, environmental regulations in Italy and elsewhere typically impose strict liability. Strict liability means that in some situations Eni could be exposed to liability for clean-up and remediation costs, environmental damage, and other damages because of Eni’s conduct of operations that was lawful at the time it occurred or of the management of industrial hubs by prior operators or other third parties, who were subsequently taken over by Eni. In addition, plaintiffs may seek to obtain compensation for damage resulting from events of contamination and pollution or in case the Company is found liable for violations of any environmental laws or regulations. Due to the history and development of the Group, Eni is particularly exposed to this kind of risk in Italy.

The Group is performing remediation and cleaning-up activities at several Italian industrial hub where the Group’s products were produced, processed, stored, distributed, or sold, such as chemical plants, mineral-metallurgic plants, refineries, and other facilities, which were subsequently disposed of, liquidated, closed, or shut down. Eni has been alleged to be liable for having polluted and contaminated proprietary or concession areas where those dismissed industrial hubs were located.

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State or local public administrations have sued Eni for environmental and other damages and for clean-up and remediation measures in addition to those which were performed by the Company, or which the Company has committed to performing, including allegations of violations of criminal laws (for example for alleged environmental crimes such as failure to perform soil or groundwater reclamation, environmental disaster and contamination, illegal discharge of toxic materials, amongst others). Although Eni believes that it may not be held liable for having exceeded in the past pollution thresholds that are unlawful according to current regulations, but were allowed by laws then effective, or because the Group took over operations from third parties, it cannot be excluded that Eni could potentially incur such environmental liabilities. Eni’s financial statements account for provisions relating to the expected costs to clean up and remediate contaminated areas and groundwater at Eni’s shut-down or operational Italian hubs, where legal or constructive obligations exist and the associated costs can be reasonably estimated in a reliable manner, representing management’s best estimates of the Company’s existing environmental liabilities.

Although the Company has provided for known environmental obligations that are probable and reasonably estimable, it is likely that the Company will continue to incur additional liabilities in the future. The additional costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the remediation actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. These future costs may be material to results of operations in the period in which they are recognized, but the Company does not expect these costs will have a material effect on its consolidated financial position or liquidity.

b) Risks related to legal proceedings and compliance with anti-corruption legislation

Eni is the defendant in several civil and criminal actions and administrative proceedings. In future years Eni may incur significant losses due to: (i) uncertainty regarding the final outcome of each proceeding; (ii) the occurrence of new developments that management could not take into consideration when evaluating the likely outcome of each proceeding in order to accrue the risk provisions as of the date of the latest financial statements or to judge a negative outcome only as possible or to conclude that a contingency loss could not be estimated reliably; (iii) the emergence of new evidence and information; and (iv) underestimation of probable future losses due to circumstances that are often inherently difficult to estimate. Certain legal proceedings and investigations in which Eni or its subsidiaries or its officers and employees are defendants might involve allegations of breaching anti-bribery and anti-corruption laws and regulations and other ethical misconduct. Such proceedings are described in the Notes to the Consolidated Financial Statements (note no.28). Ethical misconduct and noncompliance with applicable laws and regulations, including noncompliance with anti-bribery and anti-corruption laws, by Eni, its officers and employees, its partners, agents or others acting on the Group’s behalf, could expose Eni and its employees to criminal and civil penalties and could be damaging to Eni’s reputation, business prospects and results of operations.

c) Risks from acquisitions

Eni is constantly monitoring the market in search of opportunities to acquire individual assets or companies with a view of achieving its growth targets or complementing its asset portfolio. Acquisitions entail an execution risk – the risk that the acquirer will not be able to effectively integrate the purchased assets to achieve expected synergies. In addition, acquisitions entail a financial risk – the risk of not being able to recover the purchase costs of acquired assets, in case of a prolonged decline in the market prices of commodities. Eni may also incur unanticipated costs or assume unexpected liabilities and losses in connection with companies or assets it acquires. If the integration and financial risks related to acquisitions materialize, expected synergies from acquisition may fall short of management’s targets and Eni’s financial performance and shareholders’ returns may be adversely affected.

d) Eni’s crisis management systems may be ineffective

Eni has developed contingency plans to continue or recover operations following a disruption or incident. An inability to restore or replace critical capacity to an agreed level within an agreed period could prolong the impact of any disruption and could severely affect business, operations and financial results. Eni has crisis management plans and the capability to deal with emergencies at every level of its operations. If Eni does not respond or is not seen to respond in an appropriate manner to either an external or internal crisis, this could adversely impact the Group’s reputation, its business prospects and results of operations.

e) Cyberattacks, disruption to or breaches of Eni’s critical IT services or digital infrastructure and security systems could adversely affect the Group’s business, increase costs and damage Eni’s reputation

The Group’s activities depend heavily on the reliability and security of its information technology (IT) systems and digital security. The Group’s IT systems, some of which are managed by third parties, are susceptible to being compromised, damaged, disrupted or shutdown due to failures during the process of upgrading or replacing software, databases or components, power or network outages, hardware failures, cyberattacks (e.g., viruses, computer intrusions), user errors or natural disasters. Cyber threat is constantly evolving. The oil and gas industry is subject to fast-evolving risks from cyber threat actors, including nation states, criminals, terrorists, hacktivists and insiders. Attacks are becoming more sophisticated with regularly renewed techniques while the digital transformation amplifies exposure to these cyber threats. The adoption of new technologies, such as the Internet of Things (IoT) or the migration to the cloud, as well as the evolution of architectures for increasingly interconnected systems, are all areas where cyber security is a very important issue.

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The Group and its service providers may not be able to prevent third parties from breaking into the Group’s IT systems, disrupting business operations or communications infrastructure through denial of service, attacks, or gaining access to confidential or sensitive information held in the system. The Group, like many companies, has been and expects to continue to be the target of attempted cybersecurity attacks. While the Group has not experienced any such attack that has had a material impact on its business and results of operations, the Group cannot guarantee that its security measures will be sufficient to prevent a material disruption, breach, or compromise in the future which could negatively and significantly affect the Company, its reputation and results of operations. As a result, the Group’s activities and assets could sustain serious damage, services to clients could be interrupted, material intellectual property could be divulged and, in some cases, personal injury, property damage, environmental harm and regulatory violations could occur.

f) Violations of data protection laws carry fines and expose the Company and/or its employees to criminal sanctions and civil suits

Data protection laws and regulations apply to Eni and its joint ventures and associates in most countries in which they do business. The General Data Protection Regulation (EU) 2016/679 (GDPR) came into effect in May 2018 and increased penalties up to a maximum of 4% of global annual turnover for breach of the regulation. The GDPR requires mandatory breach notification, a standard also followed outside the EU (particularly in Asia). Non-compliance with data protection laws could expose Eni to regulatory investigations, which could result in fines and penalties as well as harm the Company’s reputation. In addition to imposing fines, regulators may also issue orders to stop processing personal data, which could disrupt operations. The Company could also be subject to litigation from persons or corporations allegedly affected by data protection violations. Violation of data protection laws is a criminal offence in some countries, and individuals can be imprisoned or fined.

If any of the risks set out above materialize, they could adversely impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholder returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares.

g) Eni is exposed to treasury and trading risks, including liquidity risk, interest rate risk, foreign exchange risk, commodity price risk and credit risk and may incur substantial losses in connection with those risks

Eni’s business is exposed to the risk that changes in interest rates, foreign exchange rates or the prices of energy commodities will adversely affect the value of assets, liabilities or expected future cash flows. The Group does not hedge its exposure to volatile hydrocarbons prices in its business of developing and extracting hydrocarbons reserves and other types of commodity exposures (e.g. exposure to the volatility of refining margins and of certain portions of the gas long-term supply portfolio) except for specific markets or business conditions. The Group has established risk management procedures and enters financial derivatives contracts to hedge its exposures to different commodity indexations and to currency and interest rates risks. However, hedging may not function as expected. In addition, Eni undertakes commodity derivatives contracts to optimize commercial margins or with a view of profiting from expected movements in market prices. Those derivatives may or may not be risk-reducing. Although Eni believes it has established sound risk management procedures to monitor and control commodity trading, this activity involves elements of forecasting and Eni is exposed to the risk of incurring significant losses if prices develop contrary to management expectations and to the risk of default of counterparties.

Eni is exposed to the risks of unfavorable movements in the Euro vs the U.S. dollar exchange rates primarily because Eni’s consolidated financial statements are prepared in Euros, whereas Eni’s main subsidiaries in the Exploration & Production sector are utilizing the U.S. dollar as their functional currency. This translation risk is unhedged. As a rule of thumb, a depreciation of the U.S. dollar against the euro generally has an adverse impact on Eni’s results of operations and liquidity because it reduces booked revenues by an amount greater than the decrease in U.S. dollar-denominated expenses and may also result in significant translation adjustments that impact Eni’s shareholders’ equity. In 2025, the Euro appreciated considerably versus the U.S. dollar (the average exchange rate for the year rose by 4.4%) and that trend negatively and significantly affected our reported results of operations and cash flow by an estimated €0.5 billion amount. The appreciation recorded on the last day of the year of the Euro vs the U.S. dollar exchange rate was even larger than the average (up 15%) and reduced the Group’s net equity by an estimated €6.4 billion, negatively affecting balance sheet ratios. Eni’s credit ratings are exposed to risk from possible reductions of the sovereign credit rating of Italy. Based on the methodologies used by Standard & Poor’s and Moody’s, a potential downgrade of Italy’s credit rating may have a potential knock-on effect on the credit rating of Italian issuers such as Eni and make it more likely that the credit rating of the debt instruments issued by us could be downgraded.

Eni is exposed to credit risk. Eni’s counterparties could default, could be unable to pay the amounts owed to us in a timely manner or meet their performance obligations under contractual arrangements. These events could cause the Company to recognize loss provisions with respect to amounts owed to it by debtors and cashflow shortfall. See Item 18 - Notes on Consolidated Financial Statements.

Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or that the Group is unable to sell its assets on the marketplace to meet short-term financial requirements and to settle obligations. Such a situation would negatively affect the Group’s results of operations and cash flows as it would result in Eni incurring higher borrowing expenses to meet its obligations or, under the worst conditions, the inability of Eni to continue as a going concern.

If any of the risks set out above materialize, this could adversely impact the Group’s results of operations, cash flow, liquidity, business prospects, financial condition, and shareholders returns, including dividends, the amount of funds available for stock repurchases and the price of Eni’s shares.

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Item 4. INFORMATION ON THE COMPANY

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 r egister ed head of fice is located at Piazza le Enrico Mattei 1, R ome, Ita ly (telephone number: +39-0659821).

Eni branches ar e located in:

San Donato Milanese (Milan), Vi a Emilia, 1; and

San Donato Milanese (Milan), Piazza Ezio V anoni, 1. Internet addr ess: 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.

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| ● | 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 CO 2 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”.

Str ate gy

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:

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 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).

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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 CO 2 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.

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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.

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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 CO 2 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.

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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 CO 2 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 CO 2 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 CO 2 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”.

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Key performance indicators

Climate and HSE

|  | 2025 | 2024
CLIMATE |  |  |
Net Scope 1+2 Upstream (a) | (million tonnes CO 2 eq) | 4.7 | 6.8
Net Scope 1+2 Eni (a) |  | 21.4 | 23.8
Intensity Net Scope 1+2+3 (b) | (gCO 2 eq./MJ) | 59.0 | 59.2
Direct GHG emissions (Scope 1) (c) | (million tonnes CO 2 eq) | 18.6 | 21.2
Indirect GHG emissions (Scope 2) (c) |  | 0.5 | 0.6
Direct methane emissions (Scope 1) (c) | (ktonnes CH 4) | 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.

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| ● | 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.

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| ● | 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.

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| ● | 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.

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| ● | 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.

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| ● | 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 CO 2 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.

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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 $/bbl 1 (compared to 3.69 $/bbl 2 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.

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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 rules 2. 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 Eni 3.

In 2025 4, 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.

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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.

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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.

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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).

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| 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.

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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.

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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 p r oduction, p r oduction prices and p r oduction costs

The matte r s r e g a r ding futu r e p r oduction, additions to r ese r v es and r elated p r oduction costs and estimated r ese r v es discussed bel o w and else w he r e he r ein a r e f or w a r d-looking statements that i n v ol v e risks and unce r tainties that could cause the actual r esults to dif f er material l y f r om those in su c h f or w a r d-looking statement s. Su c h risks and unce r tainties r elating to futu r e p r oduction and additions to r ese r v es in c lude political d e v elopments af f ecting the a w a r d of e xplo r ation or p r oduction inte r ests or w o r ld supp l y and prices f or oil and natu r al g a s, or c han g es in the unde r l ying economics of ce r tain of Eni’s impo r tant h y d r oca r bons p r oject s. Su c h risks and unce r tainties r elating to futu r e p r oduction costs in c lude delays or un e xpected costs incur r ed in Eni’s p r oduction ope r ation s.

In 2025, oil and n a tu r a l gas p r oduction a v ail a b le f or s a le a v e r a ged 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.

S a les v olumes of oil and gas p r oduction w e r e 566 mmBOE. The 16 mmBOE di f fe r ence o v er p r oduction on a v ail a b le-f o r-s a le basis (582 mmBOE in 2025) r e f lected main l y changes in i n v entory and other factor s.

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The t a b les b e l o w p ro vide Eni subsidiaries and its equity-accounted entities’ p r oduction (an n u a l v olumes and dai l y a v e r a ges), b y f in a l p r oduct ma r k eted of liquids and n a tu r a l gas b y country and ge o g r a phic a l a r ea of each of the last th r ee f isc a l y ear s.

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.

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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.

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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.

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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 ac r eage

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.

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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 t a b le b e l o w p ro vides certain in f o r m a tion a bout the Compa n y’s oil&gas p r opertie s. It p ro vides the tot a l g r oss and net d eve loped and und eve loped oil and n a tu r a l gas ac r e a ge in w hich the G r oup and its equity-accounted entities had inte r est as of December 31, 2025. A g r oss ac r e a ge is one in w hich Eni o wns a w o r king inte r est.

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| 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%).

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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.

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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).

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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.

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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.

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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.

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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.

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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

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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.

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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 w o r l d wide s a les of n a tu r a l gas amounted to 43.72 BCM. S a les in It a l y amounted to 21.00 BCM, w hile s a les in Eu r opean ma r k ets w e r e 18.73 BCM th a t included 0.91 BCM of gas sold to certain importers to It a l y.

The b usiness r esults of ope r a tions in 2025 and its st r a tegy a r e described in “Item 5 – G r oup r esults of ope r a tions” and “Item 5 – Man a gement’s e xpect a tions of ope r a tion s.”

Supply of natu r al g as

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.

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The t a b le b e l o w sets f orth Eni’s pu r chases of n a tu r a l gas b y sou r ce f or the periods indic a ted.

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 g as

Eni is s e lling gas to w holes a le ma r k ets in It a l y and in a n umber of Eu r opean countrie s. The w holes a le ma r k et includes s a les to la r ge accounts (industri a ls and the r mo e lectric utilities) and on Eu r opean spot ma r k et s.

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.

S a les to long-te r m b u y ers w e r e 0.91 BCM, down by 27.8% compa r ed to the p re vious y ear due to the lower a v ail a bility of Li by an 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

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The LNG b usiness

Eni LNG b usiness can count cur r ent l y on a port f olio of cont r acted long-te r m supplies main l y f r om: Q a ta r, Nigeria and Indonesia. In the plan period, Eni intends to d eve lop its LNG b usiness l ev e r a ging on the integ r a tion with the E&P segment and the v a loriz a tion of the equity ga s. Fin a l ma r k ets of th a t gas include Eu r op e and Asia. The b usiness’s p r o f it a bility will be a lso dr iv en b y enhancing the comme r ci a l p r esence in p r emium ma r k ets and conti n uing integ r a tion with t r ading act i vitie s.

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

Inte r national t r ansport

Eni has t r ansport rights on a la r ge Eu r opean net w o r k of integ r a ted inf r astructu r es f or t r ansporting n a tu r a l ga s, w hich links k ey consumption ma r k ets with the main p r oducing a r eas (Algeria, the North Sea, including the Netherlands and Norway, and Li by a). Eni has cont r acted the t r ansport c a pacity under ship-o r-p a y cont r act s, w hich a r e similar to t a k e-o r-p a y cont r act s.

The main assets of Eni’s t r ansport act i vities a r e p ro vided in the t a b le b e l o w.

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 t r ansport activities

The TTPC pip e lin e, 740 kilometer long, is made up of t w o lines th a t a r e each 370-kilometers long with a t r ansport c a pacity of 34.3 BCM/y and f iv e comp r ession st a tion s. This pip e line t r ansports n a tu r a l gas f r om Algeria ac r oss T unisia f r om Oued Saf Saf a t the Algerian bo r der to C a p Bon on the Mediter r anean coast w he r e it links with the TMPC pip e lin e.

The TMPC pip e line f or the import of Algerian gas is 775 - kilometers long and consists of f iv e lines th a t a r e each 155-kilometers long with a t r ansport c a pacity of 33.5 BCM/y. It c r osses the Sici l y Chann e l f r om C a p Bon to Maza r a d e l V a llo in Sici l y, the point of entry into the It a lian n a tu r a l gas t r ansport system.

The G r eenSt r eam pip e lin e, joint l y-o wned with the Li by an N a tion a l Oil C orporation, started ope r a tions in October 2004 f or the import of Li by an gas p r oduced a t the Eni ope r a ted f i e lds of B a hr Ess a lam and W afa. It is 516-kilometers long with a t r ansport c a pacity of 11.5 BCM/y c r ossing the Mediter r anean Sea f r om M e llit a h on the Li by an coast to G e la in Sici l y, the point of entry into the It a lian n a tu r a l gas t r ansport system.

The Blue St r eam under w a ter pip e line (w a ter depth g r e a ter than 2,150 meters) links the R ussian coast to the T u r kish coast of the Black Sea. This pip e line is 774 - kilometers long on t w o lines and has t r ansport c a pacity of 16 BCM/y. It is part of a joint v entu r e to s e ll gas p r oduced in R ussia on the T u r kish ma r k et. 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.

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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 e xpenditu r es

See “Item 5 – Liquidity and c a pit a l r esou r ces – C a pit a l e xpenditu r es b y segment”.

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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 b usiness r esults of ope r a tions in 2025 and its st r a tegy a r e described in “Item 5 – G r oup r esults of ope r a tions” and “Item 5 – Man a gement’s e xpect a tions of ope r a tions”.

| 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 Ecofining TM 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.

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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

Ma r k eting

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.

R etail 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).

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R etail sales in the R est of Eu r ope

Retail sales in the Rest of Europe were 2.27 mmtonnes, a slight decrease from 2024 (-1.3%) a s 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 st r ong l y p r esent in the w holes a le ma r k et in It a l y, including s a les of dies e l fu e l f or automot iv e use and f or he a ting purpose s, f or a gricultu r a l ve hicles and f or v ess e ls as well as s a les of fu e l oil. Major customers a r e other oil companies, r es e ller s, a gricultu r a l user s, ma n ufacturing industrie s, pu b lic utilities and t r ansport s, as we ll as f in a l users (t r ansporter s, condominium s, fa r mer s, f isher s, etc.). Enilive p ro vides its customers with its e xpertise in the a r ea of fu e ls with a wide r ange of p r oducts th a t c o v er a ll ma r k et r equi r ement s. Customer ca r e and p r oduct distri b ution a r e supported b y a widesp r ead comme r ci a l and l o gistic a l o r ganiz a tion p r esence th r oughout It a l y articul a ted in loc a l ma r k eting o f f ices and a net w o r k of a gents and concessionai r e s.

In 2025, s a les v olumes on w holes a le ma r k ets in It a l y (8.22 mmtonnes) decreased b y 17% f r om 2024, mainly due to lower product availability in specific geographical areas.

W holes a le s a les outside Italy w e r e 2.90 mmtonne s, up by 1.4% f r om 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.

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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.

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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.

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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 CO 2 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 b usiness r esults depend he a vi l y on t r ends in r e f ining ma r gin s, i.e. the sp r ead bet w een the cost of the oil feedstock and the price of the r e f ined p r oducts obtained f r om the crude p r ocessing.

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.

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R efining

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.

Ita l y

Eni’s r e f ining system in It a l y is composed of the w hol l y-o wned r e f ineries of Sannazza ro, L i v orno and T a r ant o, as we ll as its 50% st a k e in the Milazzo r e f inery in Sici l y. Eni’s r e f ineries ope r a te to maximi z e asset v a lue acco r ding to ma r k et conditions and the integ r a tion with ma r k eting act i vitie s.

The Sannazza r o r e f inery has a b a lanced c a pacity of 180 KBBL/d and a co n v ersion ind e x of 54%. Loc a ted in the P o V a lle y, in the center of Northern It a l y, Sannazza r o is one of the most e f f icient r e f ineries in Eu r op e. The high f l e xibility and co n v ersion c a pacity of this r e f inery a ll o ws it to p r ocess a wide r ange of feedstock. The main equipment in the r e f inery is: t w o primary distill a tion columns and t w o associ a ted v acuum unit s, th r ee desulphuriz a tion unit s, a f luid c a t a l ytic c r ac k er (FCC), t w o h y d r oc r ac k ers (HdC), t w o r e f o r ming unit s, a gasi f ic a tion p r oducing a syngas used in a combined c y cle p o w er gene r a tion. 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 T a r anto r e f inery has a b a lanced c a pacity of 104 KBBL/d and a co n v ersion ind e x of 56%. T a r anto has a st r ong ma r k et position due to the fact th a t it is the on l y r e f inery in Southern Continent a l It a l y and is upst r eam integ r a ted with the V a l d’Agri (Eni 61%) and Tempa Rossa f i e lds in Basilic a ta th r ough a pip e lin e. The main equipment is a topping-v acuum unit, a residue hydrocracking and a gasoil hydrocracking unit, a pl a t f o r ming unit and t w o desulphuriz a tion unit s.

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).

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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 r e f ining th r oughputs on o wn account w e r e 24.94 mmtonne s, 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 r e f inery utiliz a tion r a t e, r a tio bet w een th r oughputs and r e f inery c a pacit y, 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 ope r a tor in the It a lian oil and r e f ined p r oducts sto r a ge and t r ansport a tion b usines s.

Oil and r e f ined p r oducts a r e t r ansported: (i) b y sea th r ough spot and long-te r m cont r acts of tan k er ships; and (ii) inland th r ough a p r oprietary pip e line and depots net w o r k di r ect l y ope r a ted.

In particula r, Eni o wns and ope r a tes an integ r a ted inf r astructu r e consisting of 15 di r ect l y man a ged depots.

Eni also owns a network of oil and refined products pipelines extending approximately 1,200 kilometers operating. Eni l o gistic mod e l is o r gani z ed in f our operational management units (Northern depot s, Cent r a l depot s, Southern depots and LPG and Pip e line) operating in handling and storage of the p r oduct f l o ws in o r der to gua r antee high safet y, asset integrity and technic a l standards (HSE and asset integrity), as we ll as cost optimization and constant p r oducts a v ail a bility a long the countr y. Eni is a lso part of 7 di f fe r ent l o gistic 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.

Ox y g enates

Eni, th r ough its subsidiary Ecofu e l (100% Eni’s sha r e), s e lls a pp r o xim a t e l y 1 mmtonne/y of o x y gen a te s, main l y ethers (a pp r o xim a t e l y 1.6% of w o r ld demand, used as a gasoline octane booster) and methanol (main l y f or pet r ochemic a l use). About 77% of o x y gen a tes a r e p r oduced in Eni’s plants in It a l y (R a v enna), Saudi A r a bia (in joint v entu r e with S a bic) and V enezu e la (in joint v entu r e with P equ iv en) and the r emaining 23% is pu r chased.

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Chemicals

In 2025, sales of chemical products amounted to 2,719 ktonnes, declining from 2024 (down by 450 ktonne s, 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 t a b le b e l o w sets f orth Eni’s main chemic a l p r oducts a v ail a bility f or the periods indic a ted.

| 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 t a b le b e l o w sets f orth Eni’s main chemic a l p r oducts sale s f or the periods indic a ted.

| 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

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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 e xpenditu r es

See “Item 5 – Liquidity and c a pit a l r esou r ces – C a pit a l e xpenditu r es b y segment”.

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Corpor ate and Other activities

These acti vities include the f ollo wing b usinesses:

| ● | 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 CO 2 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 r eflect the seasona lity in demand f or natura l gas and certain refined products used in residentia l space heating, the demand f or w hich is typica lly highest in the first quarter of the y ear, w hich includes the coldest months and lo west in the third quarter, w hich includes the w armest months. Mor eove r, y ear- to-year comparability of results of operations is affected b y we ather conditions af fecting demand f or gas and other refined products in residentia l space heating. In colder y ears, w hich ar e characterized b y lo we r temperatur es than historica l a ve ra ge temperatur es, demand f or gas and products is typica lly higher than norma l consumption patterns, and vice v ersa.

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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 CO 2 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).

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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.

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Insur ance

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”.

En vir onmental 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.

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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.

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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:

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• 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.

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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:

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- 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.

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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 ent ered 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) perfo rms certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline.

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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).

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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.

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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.

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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.

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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.

R egulation of e xplor ation and pr oduction 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.

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R egulation of the Italian h y drocarbons 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.

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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 & P ower

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).

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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.

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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).

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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.

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Refining and marketing of petr oleum 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.

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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).

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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.

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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.

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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 pro ving an infringement of Article 101(1) or of Article 102 of the Treaty sha ll rest on the party or the authority a lleging 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 measur es;
| ● | 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.

Pr opert y, 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”.

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Item 4A. UNRESOLVED STAFF COMMENTS

None.

Item 5. OPER A TING AND FINANCIAL REVIEW AND PROSPECTS

This section is the Company’s analysis of its financial performance and of significant trends that may affect its future performance. It should be read in conjunction with the Consolidated Financial Statements and related Notes thereto included in Item 18. The Consolidated Financial Statements are prepared in accordance with International Financial Reporting Standards as issued by the IASB.

This section contains forward-looking statements, which are subject to risks and uncertainties. For a list of important factors that could cause actual results to differ materially from those expressed in the forward-looking statements, see the cautionary statement concerning forward-looking statements on page ii.

Basis of preparation

Eni is a diversified energy company, operating in several jurisdictions across all continents. It engages in exploration, development, production and trading of oil, gas and LNG, in the businesses of new energies including electricity production from renewable sources and biofuels manufacturing, the refining of crude oil and marketing of refined products and the production of plastics both from oil-based feedstock and from renewable feedstock. For financial reporting purposes and considering how the chief operating decision maker is assigning profit responsibilities and assessing managerial performance and capital allocation processes, Eni reportable operating segment have been identified as follows:

- Exploration & Production, which is integrating results of the E&P operating segment with those of activities of marketing, shipping and trading of oil and products to enhance synergies and to fully capture margins across the value chain;

- Global Gas & LNG Portfolio and Power, which is integrating results of the operating segment Global gas, power and LNG portfolio with those of the activities of managing and upgrading the fleet of gas-fired power plants which are ancillary to gas and power supply and trading activities;

- Enilive: this operating segment engages in the manufacturing of biofuels at the operated Italian plants of Venice and Gela and through the Chalmette JV in the USA, whilst advancing expansion plans in Italy and South-East Asia. It manages a network of refueling service stations in Italy and selected European markets, also providing services and non-fuel products to drivers. It also markets fuels through other channels (resellers, ports, airports, etcetera);

- Plenitude engages in the activities of retail marketing of gas, power and related services, with a customer base of about 10 million retail points of delivery (gas and electricity) in Europe (of which 8 million were in Italy) as of December 31, 2025. It engages in the renewable energy business (solar photovoltaic and wind facilities both onshore and offshore), which comprises building, commissioning, and managing renewable energy producing installations and managing and expanding a network of charging points for electric vehicles throughout the European territory;

- Refining and Chemicals: this reportable segment aggregates the results of the refining business and those of the chemicals business managed by Eni’s subsidiary Versalis. The Refining business engages in refining crude oil to manufacture fuels and in wholesale marketing activities, which mainly consist of the inter-company supply of refined products to the Group subsidiary Enilive and in sales to large accounts. The Chemical business engages in the production and marketing of basic petrochemical products, plastics and elastomers. Versalis is developing the business of manufacturing chemical products from renewable raw materials, bioplastics and bio-based products through the recently acquired subsidiary Novamont. Activities are concentrated in Italy and in Europe. The results of operations of the Refining business and the Chemical business have been combined in a single reporting segment because the businesses exhibit similar economic characteristics;

- Corporate and Other activities: include the costs of the main business support functions, as well as, the results of the Group environmental clean-up and remediation activities performed by the subsidiary Eni Rewind and of the businesses engaged in developing the projects for CO 2 capture and storage and/or utilization and agricultural hubs to ensure supply of bio-feedstock to the Group’s biorefineries.

Operating results

2025 trading environment

The 2025 trading environment negatively affected the Company’s results of operations and cash flow for the year, mainly due to a decline in the price of Brent crude oil and the appreciation of the EUR vs the USD. The price of the Brent benchmark crude oil, the main driver of the Group’s results of operations, was 69 $/bbl on average in the year and declined significantly from the average value of 81 $/bbl recorded in 2024, down by about 15%. Crude oil prices have gradually weakened from the second quarter of the year, driven by an uncertain macroeconomic backdrop due commercial disputes triggered by the decision of the US administration to impose import tariffs on its main trading partners and the related risks of an economic slowdown and other geopolitical risks. In the same period, supply growth has been outpacing demand rise due to continuing production gains in non-OPEC countries, notably the US, Canada, Brazil and Guyana, while the eight voluntary members of the OPEC+ DoC started unwinding the production cuts made in previous years to support prices. Both the International Energy Agency “IEA” and official statistics from the US government estimated that oil production exceeded consumption by around 2 mmbbl/d in 2025, with the surplus set to widen further in 2026. An uncertain macroeconomic outlook and the perceived build-up in supplies triggered a continued sell-off of future contracts by financial operators, driving down the price of the commodity. Early in January 2026, crude oil prices touched the lowest level in more than five years, with the Brent crude falling to around 60 $/bbl. From that point onwards, crude oil prices have been improving steadily, recovering to more than 100 $/bbl by start of March 2026 driven by better-than-expected macroeconomic data and escalating tensions in the Middle East.

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The outlook for 2026 remains uncertain due to projections of weak economic activity in China and Europe, as well as forecast of continued supply additions in the USA, Canada, Guyana, Brazil and other geographies, an improved political landscape in Venezuela which could open the Country’s oil sector to investments from foreign companies to increase production, and the stated intent by the OPEC+ plus alliance to return to the market all members’ available spare capacity. Factoring the described trends, the geopolitical risks related to ongoing tensions in the Middle East and the protraction of Russia’s military aggression of Ukraine and assuming a moderate macroeconomic growth, the management estimates crude oil prices at 70 $/bbl for the year 2026 (nominal terms). Under this pricing assumption, we expect to increase oil and gas production at a rate consistent whit our growth target in the 2026-2030 planning period envisaging a compounded average growth rate of around 4%. As discussed in Item 3-Risk factors, the Group results of operations are exposed to the variability of crude oil prices and the other scenario variables described herein.

In 2025, natural gas prices at the main European hubs were substantially in line with the previous year, albeit on a downward path due to continuing production ramp-ups and additions to LNG capacity in the US where production and export volumes have both reached all-time highs. Furthermore, gas production increased in other geographies like China, which is a net importer, while Canada which has large gas surpluses, entered the LNG export market. Supply additions and growing worldwide LNG flows also due to lower imports from China helped European gas-consuming countries to replace large volumes of gas previously imported from Russia via pipeline with little price volatility. Those developments resulted in gas prices at the main European hubs declining during the seasonal consumption peak of the last quarter, when prices normally rise. Due to recent developments in Middle East, we expect a high degree of volatility in the European gas market for 2026. Looking forward, we believe that gas prices will resume their downward trend as more LNG supplies come online.

Margins of petrochemicals products have been negatively and significantly affected by the European economic downturn and low growth of the Chinese economy, as well as the cost disadvantages of the European manufacturing sector due to comparatively higher expenses for feedstock and energy inputs, and environmental charges than in competing geographies and lack of scale against the backdrop of global overcapacity fueling continued price competition. We expect that an ongoing restructuring of our chemical business will start showing in 2026 results to partly offset a continued challenging environment.

On a positive side, margins of refined products improved from the second half 2025 due to several plant outages worldwide, reduced exports of refined products from Russia due the consequences of the war with Ukraine and increased sanctions from Western countries, and other market imbalances. Furthermore, margins of manufactured biofuels rebounded from the depressed level of 2024 due to better final prices.

Finally, the appreciation of the Euro vs the USD exchange rate (down by 7% for the yearly average and by 15% for the closing rate) negatively affected the reported amounts of revenues, earnings and cash flows at dollar-denominated subsidiaries, as well as reduced the Group net equity.

| 2025 |  | 2024 |  | 2023
Average price of Brent dated crude oil in U.S. dollars (1) | 69.06 |  | 80.76 |  | 82.62
Average price of Brent dated crude oil in euro (2) | 61.12 |  | 74.64 |  | 76.43
Average EUR/USD exchange rate (3) | 1.130 |  | 1.082 |  | 1.081
Spot gas price at the Italian PSV (4) | 39 |  | 36 |  | 42
Standard Eni Refining Margin (SERM)(5) | 7.3 |  | 5.1 |  | 8.1
Euribor - three month euro rate % (3) | 2.18 |  | 3.57 |  | 3.43

(1) Price per barrel. Source: S&P Global Energy.
(2) Price per barrel. Source: Eni’s calculations based on S&P Global Energy data for Brent prices and the EUR/USD exchange rate reported by the European Central Bank (ECB).
(3) Source: ECB.
(4) €/MWh natural gas prices. Source: ICIS European Spot Gas Markets.
(5) In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations.

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K e y consolidated financial data

|  |  | 2025 |  | 2024 |  | 2023
|  |  | (€ million)
Sales from operations |  |  | 82,151 |  | 88,797 |  | 93,717
Operating profit (loss) |  |  | 5,010 |  | 5,238 |  | 8,257
Adjusted operating profit (Non-GAAP measure) (1) |  |  | 8,344 |  | 10,348 |  | 13,805
Net profit (loss) attributable to Eni |  |  | 2,608 |  | 2,624 |  | 4,771
Adjusted net profit (Non-GAAP measure) (1) |  |  | 4,989 |  | 5,257 |  | 8,322
Net cash provided by operating activities |  |  | 13,330 |  | 13,092 |  | 15,119
Capital expenditures |  |  | 8,647 |  | 8,485 |  | 9,215
Acquisitions |  |  | 878 |  | 2,593 |  | 2,592
Disposal of assets, consolidated subsidiaries and businesses |  |  | 1,383 |  | 2,788 |  | 596
Shareholders’ equity including non-controlling interest |  |  | 52,787 |  | 55,648 |  | 53,644
Finance debt (including lease liabilities) |  |  | 34,164 |  | 36,801 |  | 34,065
Net borrowings excluding lease liabilities (1) |  |  | 9,386 |  | 12,175 |  | 10,899
Net profit (loss) attributable to Eni fully diluted | (€ per share) |  | 0.78 |  | 0.78 |  | 1.40
Dividend per share | (€ per share) |  | 1.05 |  | 1.00 |  | 0.94
Ratio of finance debt (including lease liabilities) to total shareholders’ equity plus finance debt (including lease liabilities) |  |  | 0.39 |  | 0.40 |  | 0.39
Gearing before lease liabilities ex IFRS 16 (1) |  |  | 0.15 |  | 0.18 |  | 0.17

__________
(1) For a discussion of the usefulness and a reconciliation of these non-GAAP financial measures with the most directly comparable GAAP financial measures see – "Non-GAAP measures of performance" and "Liquidity and capital resources – Financial Conditions" below.

Executive summary

In 2025, the Company’s results of operations and cash flows were negatively affected by an unfavorable trading environment driven by a steep decline in crude oil prices, which remained the key factor in determining the Company’s profitability, and to a lesser extent the appreciation of the EUR vs the USD. The average price of Brent benchmark crude oil fell by 15% in 2025 compared to 2024, down to 69 $/bbl on average (from 81 $/bbl in 2024). The downtrend in crude oil prices was caused by an uncertain macroeconomic outlook and by a continuing deterioration in market fundamentals due to supply growth outstripping demand additions.

The 2025 Group results were also affected by subdued natural gas prices and declining margins of commodity plastics. On a positive note, refining margins were helped by market dislocations and several plant outages on a worldwide scale, while the businesses of renewable power and of biofuels performed steadily.

A negative trading environment was further compounded by the devaluation of the USD dollar vs the EURO. The movement in EUR/USD exchange rate reduced the reported amounts of earnings at Eni Group dollar-denominated subsidiaries when translating their financial statements in Euros.

The management estimated that the decline in crude oil prices reduced the Group financial performance in 2025 as follows:

 Operating profit by an estimated €1.9 billion;

 Net cash provided by operating activities “operating cash flow” by an estimated €1.6 billion.

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The Group consolidated net profit attributable to Eni’s shareholders for 2025 was €2.61 billion, and was almost flat y-o-y.

Considering market headwinds, management believes that the Group recorded a solid performance in 2025 driven by several initiatives to withstand the impact of lower crude oil prices and of other exogenous factors. Those initiatives comprised working capital optimizations, cost cutting measures, capital discipline, portfolio management and other actions intended to optimize the Company cash-outs or accelerate the cash conversion cycle of revenues. Particularly, management leveraged its “satellite strategy” to valorize the Group subsidiaries which have been engaging in developing the businesses of renewables energies and of manufacturing biofuels, via direct investments in the share capital of such subsidiaries by private equity funds, interested in gaining exposure to such businesses.

As part of this, in 2025 the Group completed two very important transactions. The first related to an equity investment made by KKR in Eni’s subsidiary Enilive, which engages in the manufacture of biofuels and in the retail marketing of fuels and services to drivers, with the acquisition of a 30% interest resulting in cash proceeds of about €3.6 billion to Eni. A similar transaction was closed in relation to Plenitude, which is the other subsidiary of Eni engaging in the business of the new energies including the production of renewable power, where Ares made a 20% direct equity investment in Eni’s subsidiary share capital for cash proceeds of €2 billion to Eni. Both transactions did not have any impact on profit because they were recognized as transactions between owners.

Those transactions were part of the Group portfolio management for the year which also included the disposal for €1.1 billion of a 30% interest in the operated Baleine oilfield off Cote d’Ivoire, which was brought online from one of our exploration discoveries where we retained high working interest. This latter disposal was part of our dual exploration model designated to accelerate reserves monetization by selling part of our high working interests in exploration assets.

Despite a weak trading environment, the operating cash flow was a healthy €13.3 billion driven by solid results at E&P on the back of production growth and cost efficiencies, the contribution of the gas trading arm, steady performances at our transition-related satellites, Enilive/Plenitude, and several cash optimizations to improve working capital needs.

Those cash inflows were utilized to fund our organic growth capital projects for €8.6 billion and to return €5 billion of cash to shareholders via dividends (about €3.1 billion) and the execution of a share buy-back program for 2025 (€1.9 billion, also including completion of previous year program), which has been expanded in the course of the year from an originally planned €1.5 billion to a revised €1.8 billion in consideration of the Campany’s progress in deleveraging the balance sheet. After funding other financing needs, the surplus cash was utilized to reduce net borrowings which fell from €12.2 billion to about €9.4 billion at 2025 year-end. Net borrowing is a non-GAAP financial measure tracked by management to evaluate the soundness of the Company’s balance sheet and financial structure (see glossary for a definition of Net borrowings and the paragraph “liquidity and capital resources” for a reconciliation of net debt with the most comparable GAAP measure).,

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R epo r ted earnings

In 2025, the Group earned €5 billion of reported operating profit, translating to net profit pertaining to Eni’s shareholders of €2.61 billion after interest expense, income from investments and taxes. The 2025 operating profit was down by approximately €0.2 billion due to the E&P operating segment mainly on the back of unfavorable commodity and currency trends, partly offset by volume growth, lower expenses and lower identified items. Lower income taxes, but higher interest expense and reduced results at equity accounted entities and other investments translated into an overall improvement of about €0.2 billion, thus bringing net profit attributable to Eni’s shareholders unchanged year-on-year.

NON-GAAP measures of performance: adjusted operating profit and adjusted net profit

Adjusted operating profit (loss) and adjusted net profit (loss) are calculated by excluding the following items from the reported results: inventory holding gains or losses and identified gains and losses or extraordinary items (pre and post-tax, respectively) that in management’s view and results assessment do not reflect business base performance.

Extraordinary items recognized in 2025 mainly comprised asset impairments at the E&P operating segment (around €1.1 billion pre-tax), environmental provisions (€0.56 billion), impairment losses at other businesses (€0.5 billion), risk provisions (€0.3 billion) mainly relating to a dispute with the Italian Antitrust Authority, for an overall net positive adjustment of €2.4 billion net of tax effects and including a revaluation of deferred tax assets and a post-tax inventory holding loss. Those same items categories amounted to a net positive adjustment of €2.6 billion in 2024.

Management is excluding the above mentioned identified items from reported results when evaluating the Group and each operating segment’s underlying performance. By doing so, the management is determining and utilizing non-GAAP measures of financial performance, defined as “adjusted operating profit” and “adjusted net profit”. Management believes that those non-GAAP measures of financial performance furnish valuable information to investors and users of financial reports because the identified items excluded from the GAAP measures to determine the adjusted results are intrinsically difficult to forecast and are influenced by several factors like possible permitted accounting choices, the modalities whereby assets are increased by organic development vs acquisitions, evolution in the operating environment influencing the timing of recognition of expenses and provisions, and managerial decisions and judgement. Furthermore, we understand that those non-GAAP measures are utilized by other oil&gas companies, which are removing the same items as the ones identified by our Company from reported results, and this facilitates comparison of performances across the industry. Finally, we note that we have consistently applied those adjustments to our results for several reporting years, by this way preserving comparability of our performance as measured in terms of adjusted results over time.

A summary reconciliation of Group’s reported results vs adjusted results for the three-year period 2023-2025 is provided below:

|  | Year ended December 31,
|  | 2025 |  | 2024 |  | 2023
|  | (€ million)
GAAP operating profit (loss) |  | 5,010 |  | 5,238 |  | 8,257
Inventory holding (gains) and losses |  | 745 |  | 434 |  | 562
Identified net (gains) losses |  | 2,589 |  | 4,676 |  | 4,986
Total net items in operating profit |  | 3,334 |  | 5,110 |  | 5,548
Non-GAAP operating profit (loss) |  | 8,344 |  | 10,348 |  | 13,805
GAAP net profit (loss) |  | 2,608 |  | 2,624 |  | 4,771
Inventory holding (gains) and losses, post tax |  | 508 |  | 308 |  | 402
Identified net (gains) losses, post tax |  | 1,873 |  | 2,325 |  | 3,149
Total net items in net profit |  | 2,381 |  | 2,633 |  | 3,551
Non-GAAP net profit (loss) |  | 4,989 |  | 5,257 |  | 8,322

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The Group underlying performance – i.e. excluding the identified gains and losses as well as the inventory holding loss – was an adjusted operating profit of €8,344 million compared to €10,348 million in 2024, down by approximately 19% or €2 billion.

This performance reflected the lower contribution by (i) the E&P segment (down by €1.7 billion) due to a negative trading environment reflecting a decline in crude oil prices y-o-y (down by 15%) and the appreciation of the EUR/USD rate (up by 4%), partly offset by higher hydrocarbon production volumes, lower expenses as well as cost efficiency initiatives. Other businesses performed in line or better than 2024: (i) the GGP and Power segment contribution (up by €0.13 billion) reflected continued value maximization from gas portfolio optimization, offsetting a negative scenario; (ii) Enilive increased the results (up by €0.11 billion) driven by a recovery in bio-margins and higher volumes processed. The Chemical business (was negatively affected by a challenged trading environment and reported a loss of €0.82 billion, in line with the loss reported in 2024), and finally an adjusted operating loss was reported at the Refining business (with €0.1 billion, slightly better than 2024).

Excluding identified items and the inventory evaluation profit, adjusted net profit for 2025 was €4,989 million, a €268 million decrease compared to €5,257 million reported in 2024. The result was driven by a lower operating performance, lowering contribution from equity accounted entities driven by the negative commodity scenario partly offset by better operating and volume performances. The Group tax rate, excluding identified items (see paragraph “Taxes” of this item), was 44% and was lower than in 2025 (52% in 2024) due to a better geographical mix of profits before taxes in E&P reflecting higher contribution from jurisdictions with lower-than-average tax rates also as result of portfolio rationalization and as several exploration projects were matured to FID enabling the recognition of the tax benefits associated with previously incurred exploration expenses.

Breakdown of identified items

In 2025, identified items amounted to a total positive adjustment of €3,334 million in operating profit and of €2,381 million in net profit, including an inventory pre-tax loss of €745 million (€508 million post-tax) relating to oil and refined products. Those items mainly comprised:

(i) impairment losses of €1.1 billion in the Exploration & Production segment mainly driven by the alignment of disposal groups to their sale prices and downward reserves revisions and price effects at other oil&gas assets;

(ii) the write-down of capital expenditures made for compliance and stay-in-business at certain CGUs with expected negative cash flows in the Refining business (€0.25 billion);

(iii) impairment losses of chemical plants driven by a reduced profitability outlook because of continuing margins deterioration (€0.2 billion);

(iv) environmental and remediation provision of €0.56 billion which were recorded for about €0.17 billion by our subsidiary managing environmental remediation activities at dismissed Italian plants, €0.13 billion by the refining business and €0.17 billion by the chemicals business;

(v) provisions for redundancy incentives (€0.72 billion)

(vi) risk provisions (€0.3 billion) mainly relating to a proceeding pending before the Italian Antitrust Authority (AGCM) regarding the business of retail sales of biofuels.

These items were partly offset by the reclassification of the negative balance of €0.33 billion in relation to exchange rate differences and derivatives, and by the net gains on disposal assets mainly in the upstream business (€0.03 billion). Furthermore, the tax item included about €0.38 billion of write-up of deferred tax assets due to improved profitability prospects of Italian subsidiaries.

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For a breakdown of identified gains and losses by business segments, refer to the reconciliation of the Non-GAAP measures to the most comparable performance measures calculated in accordance with IFRS, in the Operating profit (loss) by segment section.

The table below sets forth details of the identified gains and losses included in the net results during the period presented.

|  | Year ended December 31,
|  | 2025 |  | 2024 |  | 2023
|  | (€ million)
Identified gains and losses of operating profit (loss) |  | 2,589 |  | 4,676 |  | 4,986
- environmental charges |  | 560 |  | 900 |  | 648
- gains on an environmental agreement with an Italian operator |  |  |  | (869) |  |
- impairment losses, net |  | 1,582 |  | 2,900 |  | 1,802
- impairment of exploration projects |  |  |  | 140 |  |
- net gains on disposal of assets |  | (21) |  | (38) |  | (11)
- risk provisions |  | 325 |  | 44 |  | 39
- provision for redundancy incentives |  | 72 |  | 73 |  | 158
- effects of fair-valued commodity derivatives |  | (26) |  | 1,056 |  | 1,255
- exchange rate differences and derivatives |  | (334) |  | 258 |  | (16)
- other |  | 431 |  | 212 |  | 1,111
Net finance (income) expense |  | 279 |  | (155) |  | 30
of which: |  |  |  |  |  |
- exchange rate differences and derivatives reclassified to operating profit (loss) |  | 334 |  | (258) |  | 16
Net (income) expense from investments |  | (158) |  | (319) |  | (698)
of which: |  |  |  |  |  |
- gain on the GIP deal in CCS activities |  | (73) |  |  |  |
- gain on the SeaCorridor deal |  |  |  |  |  | (834)
- gain on the divestment of a 10% stake in Saipem |  |  |  | (166) |  |
- net gain on the divestment of upstream assets |  |  |  | (373) |  |
Income taxes |  | (790) |  | (1,941) |  | (1,180)
Total non core gains and losses of net profit (loss) |  | 1,920 |  | 2,261 |  | 3,138
Attributable to: |  |  |  |  |  |
- non-controlling interest |  | 47 |  | (64) |  | (11)
- Eni's shareholders |  | 1,873 |  | 2,325 |  | 3,149

Cash flow and net borrowings

Group’s results of operations in 2025 drove a cash flow from operating activities “CFFO” of €13.3 billion, €0.24 billion higher than in 2024 and included €1.79 billion of dividends paid by equity-accounted and other non-controlled entities.

Cash inflows of the year funded capital expenditures of €8.6 billion to pursue Group’s development projects and to sustain oil&gas production, leaving a surplus of about €4.7 billion that was utilized to fund part of cash returns to Eni’s shareholders of €5 billion, consisting of €3.1 billion of dividends and stock repurchases of €1.9 billion. The stock repurchases comprised completion of the 2024 buy-back program and over 80% of the 2025 buy-back program of at least €1.8 billion. This latter was completed in February 2026.

Cash flow from divesting activities net of funds deployed for acquisitions ensured a surplus of around €6.3 billion. The main 2025 dispositions included the disposals of noncontrolling interests in consolidated subsidiaries relating to a 30% investment of private equity fund KKR into Enilive for €3.57 billion, a second investment tranche (2.4%) of the EIP fund into Plenitude (€0.21 billion) and a 20% investment by Ares Fund into Plenitude (€2 billion) as well as asset disposals (€1.38 billion) mainly relating to the sale of a 30% stake in the Baleine project and other non-strategic fields in Congo. Those inflows were partly offset by funds for acquisitions (for overall €0.9 billion) and mainly related to the expansion of renewable generation capacity at Plenitude (€0.5 billion), to acquisition of additional interest in upstream assets (€0.2 billion) as well as to the expansion of the agri-business activity (€0.1 billion).

As a result of those cash movements and including the repayment of lease liabilities and the incurrence of finance debt in connection with supplier finance agreements, GAAP finance debt including lease liabilities was €34.2 billion at December 31, 2025, about €2.6 billion higher than at the end of 2024.

Group net borrowings (Non-GAAP measure – see Glossary) decreased by €2.8 billion to €9.4 billion. The management’s tracked measure of financial structure – gearing (ratio of net borrowings to shareholders equity plus net borrowings – see glossary) came in at 0.15. This was remarkable considering that the USD devaluation reduced total equity by an estimated amount of €6 billion equivalent to around one point and half of gearing. For a discussion of use on Non-GAAP measures relating to finance debt, net borrowings and capital ratios see paragraph “Liquidity and capital resources” below.

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Critical accounting estimates

Oil and Natural Gas Reserves

The estimation of proved oil and natural gas reserve volumes is an ongoing process based on rigorous technical evaluations, commercial and market assessments, and detailed analysis of reservoir and well performance, development and production costs, and other factors. The estimation of proved reserves is controlled by the Company through long-standing approval guidelines and internal procedures and controls. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Headquarter Reserve Evaluators which have significant technical experience, culminating in reviews with and approval by senior management. Key features of the reserve estimation process are covered in Disclosure of Reserves in Item 4.

Oil and natural gas reserves include both proved and unproved reserves.

 Proved oil and natural gas reserves are determined in accordance with U.S. Securities and Exchange Commission (SEC) requirements. Proved reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic and operating conditions and government regulations. Proved reserves are determined using the average of first-of-month oil and natural gas prices during the reporting year.

 Proved reserves can be further subdivided into developed and undeveloped reserves. Proved developed reserves include amounts which are expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include amounts expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion. Proved undeveloped reserves are recognized only if a development plan has been adopted indicating that the reserves are scheduled to be drilled within five years, unless specific circumstances support a longer period of time.

The Company is reasonably certain that proved reserves will be produced. However, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals, government policy, consumer preferences, and significant changes in oil and natural gas price levels.

 Unproved reserves are quantities of oil and natural gas with less than reasonable certainty of recoverability and include probable reserves.

Revisions in previously estimated volumes of proved reserves for existing fields can occur due to the evaluation or re-evaluation of (1) already available geologic, reservoir, or production data, (2) new geologic, reservoir, or production data, or (3) changes in the average of first-of-month oil and natural gas prices and/or costs that are used in the estimation of reserves. Revisions can also result from significant changes in development strategy or production equipment and facility capacity, as well as management’s re-prioritization of capital commitments.

A downward revision in proved reserves normally results in higher amortization charges to profit and loss due to the unit-of-production method and reduces future production levels. It can also trigger a reduction in the recoverable amounts of underlying assets with possible recognition of an impairment loss. In 2025, the Company recognized about €570 million of impairment losses at Italian gas-producing assets and at minor assets in Turkmenistan, the United Arab Emirates and the USA due to downward reserve revisions considering that those were mature fields subject to more frequent reserves revisions due to reassessment of available data.

Unit-of-Production Depreciation

Oil and natural gas proved reserve volumes are used as the basis to calculate unit-of-production depreciation rates for most E&P assets. Acquisition costs of proved properties are depreciated using a ratio of asset cost to total proved reserves while capitalized drilling and developments costs are depreciated using a ratio of actual production volumes to proved developed reserves. In case of phased development projects where plants and production facilities like common treatment centers, and FPSO and FLNG vessels have technical lives that exceed the expected duration of proved reserves (both developed and undeveloped), in addition to proved reserves the Company includes in the ratio volumes of probable reserves in determining the UOP rate to obtain a more equitable apportionment of the asset cost over the economic life of the underlying reserves.

The volumes produced and asset cost are known, while reserves used in determining the UOP rate are based on estimates that are subject to some variability.

To the extent that proved reserves for a property are substantially de-booked because they are uneconomic at the prices determined in accordance with the US SEC rules, and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, the Company might apply an alternative estimation technique to determine the UOP rate. In such circumstances, the rate includes volumes of reserves estimated with regard to economic viability parameters, reasonable and consistent with management’s expectations of production, in order to recognize depreciation charges that result in a more equitable allocation of cost over the economic life of an upstream asset than being fully amortized at the time of reserve de-booking.

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Fair Value Used in Business Combinations

In accounting for business combinations, the purchase price paid to acquire a business is allocated to its assets and liabilities based on their respective estimated fair values as of the date of acquisition. If applicable, any excess of the purchase price over the fair value is recorded as goodwill. The assessment of fair value is based upon the views of a likely market participant group.

In respect of the recently completed acquisitions (particularly in 2024), the most significant amount of judgment involved the estimated fair values of property, plant and equipment related to crude oil and natural gas properties and to renewable electricity generation assets for which we used discounted cash flow models. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, commodity prices consistent with our internal plans, drilling, development and maintenance costs, estimations regarding future availability of generation assets and risk-adjusted discount rates.

The assumptions and inputs incorporated within the fair value estimates are subject to considerable management judgement and are based on industry, market, and economic conditions prevalent at the time of the acquisition. Actual results may differ from the projected results used to determine fair value.

See N ote 4 for further information regarding the acquisitions made during 2025.

Impairment

The Company tests assets (i.e. property, plant and equipment “PP&E”) or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Goodwill carrying amounts are tested annually, independently from the evidence of impairment indicators. The Company has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. However, considering the volatility of the trading environment and the fact that the Company engages in a commodity business, the management performs the recoverability test of fixed assets’ net book values at least once a year, also in cases when there is no evidence of impairment indicators. This process relies mostly on the Company’s planning and budgeting cycle.

The recoverability test of the carrying amounts of oil and gas properties is the most critical accounting estimates in the preparations of the Company’s financial statements due to materiality of stated amounts (oil&gas assets represents about 80% of the item PP&E) and because the estimation of assets’ value-in-use is highly judgmental and relies on management’s forecasts of highly uncertain variables, like long-term commodity prices. Because the lifespans of the vast majority of the Company’s oil&gas assets are measured in decades, the future cash flows of these assets are predominantly based on long-term oil and natural gas commodity prices and industry margins, development costs, and production costs. Significant reductions in the management’s view of oil or natural gas commodity prices or margin ranges, and changes in the development plans, including decisions to defer, reduce, or eliminate planned capital spending, can be an indicator of potential impairment, as well as an increase in the discount rate. Among these, forecasts of long-term crude oil and natural gas prices are the most important assumptions because they are the primary drives of asset’s future net cash flows.

In general, the Company does not view temporarily low realized prices as an indication of market imbalances that warrant a revision to the Company’s long-term pricing assumptions, which are the single, most important variables in determining the future net cash flows of oil&gas properties. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments, and technology and efficiency advancements. OPEC+ investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities, alternative energy sources, and levels of prosperity. During the lifespan of its major assets, the Company expects that oil and gas prices will experience significant volatility. Consequently, these assets will experience periods of higher earnings and periods of lower earnings, or even losses. In 2025, operating profit of the Company’s E&P operating segment fell 6% y-o-y driven by lower crude oil prices due to an oversupplied market. However, the Company believes that current imbalances are of short-term nature and therefore the management has retained its long-term price assumptions which are mostly unchanged from the previous year. Therefore, in 2025 the Company recognized €1.08 billion of impairment losses at its oil&gas assets which were primarily driven by factors other than long-term prices, like reserves revisions and disposal effects.

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When updating the recoverability test of the carrying amounts of oil&gas assets, the management generally relies on the estimation of assets’ values-in-uses, considering the difficulty in obtaining information about assets’ fair values. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on the assumptions developed in the budget and mid-term plan, which is reviewed and approved by the Board of Directors, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the Company’s assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, production volumes, development and operating costs including greenhouse gas emission prices and expenses planned to meet the Company’s emissions reduction targets. Notably, when assessing future cash flows, the Company includes the estimated costs in support of reaching its 2030 greenhouse gas emission-reduction plans, including its goal of net-zero Scope 1 and 2 emissions at all oil&gas properties by that timeline. Volumes are based on projected fields and facility production profiles. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities. Cash flow projections net of the related tax effects are then discounted to determine the net present value of those cash flows. The discount rate is a post-tax discount rate that approximates the one a market participant would utilize in estimating the net present value of assets similar to those owned by the Company. The Company utilizes post-tax cash flows and discount rates because it has estimated they would yield the same result as a pre-tax estimation.

In assessing the recoverability of the carrying amounts of its oil&gas assets the Company has adopted the following pricing assumptions, which remained largely unchanged from the previous assessment:

| 2026 |  | 2028-2030 |  | 2040 |  | 2050
Brent crude oil price $/bbl real terms 2025: | 68 |  | 75 |  | 65 |  | 53

Regarding natural gas properties which revenues are indexed to spot prices at European hubs our assumptions reflect a high degree of volatility in the short-term while remaining unchanged in the longer term, as follows:

| 2026 |  | 2028-2030 |  | 2040 |  | 2050
Natural gas spot prices at TTF $/mmBTU real terms 2025: | 11.8 |  | 7.9 |  | 7.6 |  | 6.9

Therefore, having retained its pricing assumptions substantially unchanged, in 2025 the Company recognized certain impairment losses which were mainly driven by downward reserves revisions as explained before.

Considering the highly judgmental nature of the assumptions underlying the recoverability of the carrying amounts of oil&gas properties, particularly long-term pricing assumptions, the Company stress-tested the outcome of its impairment review by applying a “haircut” of 10% to its pricing assumptions across all years of financial projections at each asset or group of asset as well as a one percentage point increase in the discount rate “weighted average cost of capital” WACC, holding all other factors constant, with the following impacts:

|  | Possible estimated impairment losses (cumulative amount) (€ billion)
-10% to Brent prices |  | (1.0)
+100 b.p, increase to WACC |  | (0.2)

Other stress tests of the recoverability of E&P assets are disclosed in Note 15 to the Consolidated Financial Statements.

An asset or an asset group is impaired if its estimated cash flows discounted at a rate reflective of the cost of the capital to the Group are less than the carrying values. Impairments are measured by excess of the carrying value over value-in-use or fair value when available.

Fixed assets in other Company’s operating segments are tested for recoverability using a methodology similar to the E&P operating segment. Elements of judgement include forecasts of future industry margins, wholesale price of electricity, maintenance and development costs and expectations about average utilization rates of plants and renewable electricity generation facilities. Evidence of impairment indicators also include recent periods of operating losses in the context of the Company’s longer-term view of prices and margins.

In 2025, the Company recognized a minor impairment loss at its polyethylene manufacturing plants in the Versalis business unit based on the recent history of losses and management’s view of structural weaknesses in the supply/demand balance and in industry margins.

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Other Impairment Estimates. Unproved oil&gas properties are assessed periodically to determine whether they have been impaired. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the Company’s future development plans, the estimated economic chance of success, and the continuing commitment on part of the management to pursue exploration and appraisal activities, as well as length of time that the Company expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.

Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the assets are considered impaired and adjusted to the lower value. Judgment is required to determine if assets are held for sale and to determine the fair value less cost to sell.

In 2025, we recorded an impairment loss of around €330 mln at a gas property to reflect the lower expected fair value in a disposal process than its carrying amount. This held-for-sale asset was part of the Company’s divestiture program to reduce risks and anticipate cash flows from long-lived assets.

Investments accounted for by the equity method are assessed for possible impairment when events or changes in circumstances indicate that the carrying value of an investment may not be recoverable. Examples of key indicators include trends in quoted market prices, a history of operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If the decline in value of the investment is other than temporary, the carrying value of the investment is written down to fair value. In the absence of market prices for the investment, discounted cash flows are used to assess fair value, which requires significant judgment.

Asset Retirement Obligations

The Company is subject to retirement obligations for oil&gas properties. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the expected expenditure, estimated amounts and timing of settlements, discount rates, and inflation rates. Those assumptions also consider the management’s expectations about possible impacts of the energy transition on the timing of assets decommissioning.

The most judgmental assumption about the recognition of decommissioning provisions concerns the expected timing of decommissioning, which incorporates estimations about the expected useful lives of oil&gas assets and the pace of the transition. In case our assumptions are too optimistic, we could incur an upward revision of the liability and increased amortization charges through P&L as well as being forced to review our finance needs. Management estimated that in case the timing of incurrence of decommissioning expenses is brought forward by five years, the book value of the provision would increase by around €1.2 billion.

In the case of refineries and petrochemicals complexes, decommissioning provisions are recognized when an asset is definitively shut down and no economic options exist to upgrade or reconvert the asset to produce decarbonized commodities.

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G r oup profit and loss

The table below sets forth a summary of Eni’s profit and loss account for the periods indicated. All line items included in the table below are derived from the Consolidated Financial Statements prepared in accordance with IFRS. For the disclosure on 2024 Group results compared to 2023 see the Annual Report on Form 20-F 2024, filed to the SEC on April 4, 2025.

|  | Year ended December 31,
|  | 2025 |  | 2024 |  | 2023
|  | (€ million)
Sales from operations |  | 82,151 |  | 88,797 |  | 93,717
Other income and revenues (1) |  | 1,478 |  | 2,417 |  | 1,099
Total revenues |  | 83,629 |  | 91,214 |  | 94,816
Operating expenses |  | (70,296) |  | (74,544) |  | (77,221)
Other operating (expense) income |  | 641 |  | (352) |  | 478
Depreciation, depletion and amortization |  | (7,349) |  | (7,600) |  | (7,479)
Impairment reversals (impairment losses) of tangible and intangible and right of use assets, net |  | (1,582) |  | (2,900) |  | (1,802)
Write-off of tangible and intangible and right of use assets |  | (33) |  | (580) |  | (535)
OPERATING PROFIT (LOSS) |  | 5,010 |  | 5,238 |  | 8,257
Finance income (expense) |  | (819) |  | (599) |  | (473)
Income (expense) from investments |  | 1,587 |  | 1,850 |  | 2,444
PROFIT (LOSS) BEFORE INCOME TAXES |  | 5,778 |  | 6,489 |  | 10,228
Income taxes |  | (3,020) |  | (3,725) |  | (5,368)
Net profit (loss) |  | 2,758 |  | 2,764 |  | 4,860
Attributable to: |  |  |  |  |  |
- Eni's shareholders |  | 2,608 |  | 2,624 |  | 4,771
- Non-controlling interest |  | 150 |  | 140 |  | 89

(1) | Includes, among other things, contract penalties, income from contract cancellations, gains on disposal of mineral rights and other fixed assets, compensation for damages and indemnities and other income.

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Analysis of the line items of the p r ofit and loss account

a) Sales from operations

The table below sets forth, for the periods indicated, sales from operations generated by each of Eni’s business segments including intragroup sales, together with consolidated sales from operations.

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (€ million)
Exploration & Production | 50,367 |  | 54,440 |  | 55,773
Global Gas & LNG Portfolio and Power | 17,120 |  | 18,876 |  | 24,168
Enilive and Plenitude | 29,278 |  | 31,301 |  | 32,877
Refining and Chemicals | 18,179 |  | 21,210 |  | 23,061
Corporate and other activities | 2,073 |  | 1,905 |  | 1,830
Consolidation adjustments | (34,866) |  | (38,935) |  | (43,992)
SALES FROM OPERATIONS | 82,151 |  | 88,797 |  | 93,717

2025 compared to 2024. Sales from operations (revenues) for 2025 (€82,151 million) decreased by €6,646 million from 2024 (or down by 7.5%) due to lower energy commodities prices and the dollar depreciation, which negatively affected all business segments.

The average Brent price decreased by 15% and negatively affected the reported amounts of revenues in the E&P segment including crude oil trading activities. That reduction was partly offset by higher traded volumes. Sales in the GGP and Power segment were negatively affected by lower gas supplies with volumes down 14% (or 7 bcm) and lower spot gas prices in the seasonally strong fourth quarter. Sales in the Refining and Chemicals segment were negatively affected by lower commodity prices and a decline in sales volumes of refined products and petrochemicals products (down 14%), the latter also reflecting plant closures. Furthermore, the appreciation of the EUR vs the USD exchange rate (up by 4% for the yearly average) negatively affected the reported amounts of revenues mainly in the E&P segment.

The drivers of the changes in revenues year-on-year are detailed in the following table:

Sales from operations: change 2025 vs 2024 | change | of which: |  | price effects |  | exchange rate effects |  | volume/mix effects
| (€ billion)
E&P | (4.1) |  |  | (5.4) |  | (2.3) |  | 3.6
GGP and Power | (1.8) |  |  | 0.2 |  |  |  | (2.0)
Enilive and Plenitude | (2.0) |  |  | (1.3) |  |  |  | (0.7)
Refining and Chemicals | (3.1) |  |  | (1.6) |  |  |  | (1.5)

Other income and r e v enues

2025 compared to 2024. Eni’s other income and revenues amounted to €1,478 million, a decrease of €939 million. The reduction from the previous year was due to the circumstance that in the previous year Eni recognized an exception €1,048 million gain relating to the agreement with an Italian operator for the sharing of environmental costs incurred by Eni at certain decommissioned Italian sites jointly managed in the past. This line item included income and revenues relating to other oil and gas services, amounts billed to joint operators, gains on the disposal of assets and other income.

b) Ope r ating e xpenses

The ta b le b e l o w sets f orth the components of Eni’s ope r a ting e xpenses f or the periods indic a ted.

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (€ million)
Purchases, services and other | 67,056 |  | 71,114 |  | 73,836
Impairment losses (impairment reversals) of trade and other receivables, net | 11 |  | 168 |  | 249
Payroll and related costs | 3,229 |  | 3,262 |  | 3,136
Operating expenses | 70,296 |  | 74,544 |  | 77,221

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2025 compared to 2024. Operating expenses for 2025 (€70,296 million) decreased by €4,248 million compared to 2024, down by 5.7%, primarily reflecting lower supply costs of raw materials (natural gas under long-term supply contracts, refinery and chemical feedstocks).

Payroll and related costs (€3,229 million) decreased slightly by €33 million from 2024 (down by 1.0%) mainly due to divestments activities outside Italy following the portfolio optimizations, partly offset by increases on wages mainly in Italy due to the renewal of collective labor agreements.

c) Dep r eciation, depletion, amortization, impairment losses (impairment r e v e r sals) net and write-off

The ta b le b e l o w sets f orth a b r eakd o wn of dep r eci a tion, depletion, amortiz a tion, impai r ment losses (impai r ment rev ersals) net and write-o f f f or the periods indic a ted.

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (€ million)
Exploration & Production | 6,061 |  | 6,353 |  | 6,271
Global Gas & LNG Portfolio and Power | 279 |  | 267 |  | 295
Enilive and Plenitude | 745 |  | 708 |  | 665
Refining and Chemicals | 146 |  | 161 |  | 142
Corporate and other activities and impact of unrealized intragroup profit elimination | 118 |  | 111 |  | 106
Total depreciation, depletion and amortization | 7,349 |  | 7,600 |  | 7,479
Impairment losses (impairment reversals) of tangible and intangible assets, goodwill and right of use assets, net | 1,582 |  | 2,900 |  | 1,802
Write-off of tangible and intangible and right of use assets | 33 |  | 580 |  | 535
Total depreciation, depletion, amortization, impairment losses (impairment reversals) of tangible and intangible and right of use assets, net and write off of tangible and intangible and right of use assets | 8,964 |  | 11,080 |  | 9,816

2025 compa r ed to 2024. In 2025, depreciation, depletion and amortization charges (€7,349 million) decreased by €251 million from 2024, mainly in the Exploration & Production segment following the appreciation of the EUR vs. USD and the effect of amortization suspension at certain assets that were reclassified as held-for-sale. Those decreases were partly offset by higher charges due to projects start-ups and reserves revisions. Charges increased in the Enilive and Plenitude segment due to start-ups of new renewable energy installations.

In 2025, the Group recorded impairment losses at property, plant and equipment for a total amount of €1,582 million, out of which €1,081 million were recorded at the Exploration & Production segment, mainly at certain assets in Congo and Cote d’Ivoire due to the alignment to the fair value of divestments as part of an ongoing portfolio optimization. Other impairment charges were driven by reserves revisions and changed pricing assumptions at oil&gas assets in Italy, Turkmenistan, the United Arab Emirates and the USA. The Refining and Chemicals segment incurred €451 million of impairment losses driven by the write-off of expenditures incurred in the year for compliance and stay-in-business at certain Cash Generating Units with expected negative cash flows in the Refining business (€253 million) and in the Chemicals business (€198 million), with the latter also including a write-off of an uneconomical business line due to a reduced profitability outlook because of continuing margins deterioration.

Write-off of tangible and intangible and right of use assets amounted to €33 million and mainly related to the E&P segment as capitalized costs of suspended exploratory wells were expensed through profit due to unsuccessful assessment of commerciality of reserves or economic feasibility of projects in Algeria and Oman. Exploration wells write-offs were significantly lower than in the comparative period.

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d) Ope r ating p r ofit (loss) b y s e gment

The ta b le b e l o w sets f orth Eni’s ope r a ting p r o f it b y b usiness segment f or the periods indic a ted.

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (€ million)
Exploration & Production | 6,302 |  | 6,715 |  | 8,693
Global Gas & LNG Portfolio and Power | 1,770 |  | (909) |  | 2,626
Enilive and Plenitude | 652 |  | 1,589 |  | (74)
Refining and Chemicals | (2,485) |  | (1,681) |  | (2,121)
Corporate and other activities | (1,499) |  | (371) |  | (948)
Impact of unrealized intragroup profit elimination | 270 |  | (105) |  | 81
Operating profit (loss) | 5,010 |  | 5,238 |  | 8,257

Exploration & Production. In 2025, the Exploration & Production segment reported an operating profit of €6,302 million, with a decrease of €413 million compared to the operating profit of €6,715 million reported in 2024. This decrease was driven by lower crude oil prices (international oil price for the Brent benchmark crude oil declined by 15%) reflecting oversupplied markets and macroeconomic uncertainty.

In 2025, Eni’s average realized prices for crude oil and natural gas liquids decreased by 7% on average, with Eni’s average liquids prices decreasing by 13%. Lower crude oil realizations exchange rate effect and impacts of divestments made in 2024 were partly offset by production growth, better volume mix, cost efficiencies, significantly lower exploration wells write-offs and asset impairment losses.

In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in segment base performance, management generally excludes the identified gains and losses presented below to assess the underlying industrial trends and obtain a better comparison of core business performance across reporting periods. In 2025, identified gains and losses included impairment losses of €1,081 million and minor other charges net.

Excluding those items, the E&P segment reported a Non-GAAP operating profit of €7,493 million, with a decrease of €1,727 million from 2024, down by 19%, driven by lower realizations in US dollars at equity production, exchange rate effect and impacts of divestments made in 2024. These negatives were partly offset by higher production sold, better volume mix effects, lower exploration write-offs, as well as by cost efficiencies.

| change | of which: |  | price effects |  | exchange rate effects |  | volume/mix effects |  | cost effects
| (€ million) |  |
Change in E&P Non-GAAP operating profit (loss) 2025 vs. 2024 | (1,727) |  |  | (1,798) |  | (378) |  | 118 |  | 331

|  | Year ended December 31,
|  | 2025 |  | 2024 |  | 2023
Exploration & Production |  | (€ million)
GAAP operating profit (loss) |  | 6,302 |  | 6,715 |  | 8,693
Impairment losses (impairment reversals), net |  | 1,081 |  | 2,203 |  | 1,043
Net gains on disposal of assets |  | (10) |  | (25) |  | 2
Environmental provisions |  | 24 |  | 9 |  | 81
Risk provisions |  | 122 |  | 9 |  | 7
Reclassification of currency derivatives and translation effects to management measure of business performance |  | (48) |  | 22 |  | 73
Write off of exploration projects |  |  |  | 140 |  |
Other |  | 22 |  | 147 |  | 225
Total identified gains and charges |  | 1,191 |  | 2,505 |  | 1,431
Non-GAAP operating profit (loss) |  | 7,493 |  | 9,220 |  | 10,124

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Global Gas & LNG Portfolio (GGP) and Power

This reportable segment aggregates the results of the GGP business engaged in the purchase and marketing of gas, LNG and electricity and in trading activities, with those of the power business engaged in the production of electricity from cogeneration plants feed with gas and in providing backup capacity to the Italian grid because this business is ancillary to GGP.

In 2025, the GGP and Power segment reported an operating profit of €1,770 million compared to a loss of €909 million in 2024. This increase was positively affected by movements in fair-valued commodity derivatives entered into (from a loss of €1,740 million in 2024 to a gain of €377 million in 2025), a large part of which was lacking correlation with the underlying performance due to the accounting under IFRS, as well as lower sales volumes, reduced gas prices in the seasonally strong fourth quarter, and other scenario effects.

In reviewing the performance of the Company’s GGP and Power segment and with a view to better explaining year-on-year changes in the segment performance, management generally excludes certain fair-valued commodity derivatives with gains and losses recognized through to profit to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods.

We enter into commodity and currency derivatives to reduce our exposure to: (i) the commodity risk due to different indexation between the purchase cost and the selling price of gas or to lock in a commercial margin once a sale contract has been signed or is highly probable; and (ii) the underlying exchange rate risk due to the fact that our selling prices are indexed to the euro and our supply costs are denominated in dollars. These derivatives normally hedge the Group net exposure to commodities and exchange rates but do not meet the requirements for being accounted for as hedges in accordance with IFRS. As part of our ordinary activities, we also entered into forward gas sale contracts which are intended to be settled with the delivery of the commodity and which are accounted at fair value because they were not eligible for the own use exemption at their inceptions, whereas purchase costs of gas were accounted on an accrual basis.

In explaining year-on-year changes and in evaluating the business performance, management believes that is appropriate to exclude the fair value of commodity derivatives which lacked the formal criteria to be accounted for as hedges or were not eligible for the own use exemption, including the ineffective portion of cash flow hedges. We also excluded from our measure of underlying performance the effects of the settlement of certain commodity derivatives of which the underlying physical transaction had yet to be finalized with the delivery of the commodity. Furthermore, although the Group classifies within net finance expense those gains and losses on currency derivatives, as well as on the alignment of trade receivables and payables denominated in dollars into the accounts of euro subsidiaries at the closing rate, we believe that it is appropriate to consider those gains and losses on currency derivatives and currency differences at our dollar-denominated trade payables and receivables as part of the underlying business performance. In 2025, those fair value effects on commodity derivatives amounted to a gain of €377 million, while in 2024 those fair value effects amounted to a charge of €1,740 million. In 2025, identified items also included a €46 million charge determined as a timing difference between the value of gas inventories accounted for under the weighted-average cost method provided by IFRS as measured at the balance sheet date and the management’s own measure of performance, which considers the storage injection season and the withdrawal season and defer the margins captured by leveraging the seasonal “summer vs. winter” spreads in gas prices net of the effects of the associated commodity derivatives to when those volumes held in storage are actually sold, normally during the next withdrawal winter season.

Excluding the below-listed gains and charges, the GGP business reported a Non-GAAP operating profit of €1,015 million, with a decrease of €84 million from 2024, while the Power business reported an adjusted operating profit of €347 million, up by €211 million from 2024, for a net increase of 127 million for the segment. The increase was due a one-off gain in the Power business due to a contract renegotiation, partly offset by negative scenario effects, lower sales volumes and reduced benefits of contract renegotiations and settlments in the GGP business. The GGP business operating performance was underpinned by continued margin improvement from gas and LNG portfolio optimization activities, including asset-backed trading actions.

| change | of which: |  | price effects |  |  |  | contract renegotiations and risk provisions |  | cost effects
| (€ million) |  |
Change in GGP and Power Non-GAAP operating profit (loss) 2025 vs. 2024 | 127 |  |  | (67) |  |  |  | 255 |  | (61)

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|  | Year ended December 31,
|  | 2025 |  | 2024 |  | 2023
Global Gas & LNG Portfolio and Power |  | (€ million)
GAAP operating profit (loss) |  | 1,770 |  | (909) |  | 2,626
Impairment losses (impairment reversals), net |  | (18) |  | 101 |  | (38)
Provision for redundancy incentives |  | 2 |  | 1 |  | 6
Fair value (gains)/losses on commodity derivatives |  | (377) |  | 1,740 |  | 99
Reclassification of currency derivatives and translation effects to management measure of business performance |  | (292) |  | 228 |  | (105)
Other |  | 277 |  | 74 |  | 825
Total identified gains and charges |  | (408) |  | 2,144 |  | 787
Non-GAAP operating profit (loss) |  | 1,362 |  | 1,235 |  | 3,413
- Global Gas & LNG Portfolio |  | 1,015 |  | 1,099 |  | 3,247
- Power |  | 347 |  | 136 |  | 166

Enilive and Plenitude. In 2025, the Enilive and Plenitude segment reported an operating profit of €652 million, compared to an operating profit of €1,589 million in 2024, representing a decrease of €937 million. Enilive reported an operating profit of €499 million (€282 million in 2024), while Plenitude reported an operating profit of €153 million, compared to an operating profit of €1,307 million in 2024.

The main item excluded from GAAP operating profit in determining the Non-GAAP profitability measure of Plenitude were the effects related to fair value changes of commodity derivatives lacking the formal criteria to be accounted as hedges under IFRS, which exhibited significant volatility y-o-y, and provisions for environmental remediation and other charges.

In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes derivatives effects and the other identified gains and losses described above in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods.

Excluding those items, the Enilive business reported a Non-GAAP operating profit of €682 million (an operating profit of €571 million in 2024), helped by higher results of the biorefining business in Italy, mainly driven by a recovery of biofuels margins and by higher processed volumes. The performance of the retail business was steady.

The Plenitude business reported a Non-GAAP operating profit of €554 million, lower than operating profit of €616 million in 2024, due to weaker results in the retail business, mainly related to a reduced contribution of the activity of energy efficiency solutions and increasing competitive pressure, partly offset by higher volumes of electricity generation at renewable plants reflecting capacity additions.

| change | of which: |  | price effects |  |  |  | volume/mix effects |  | cost effects
| (€ million) |  |
Change in Enilive Non-GAAP operating profit (loss) 2025 vs. 2024 | 111 |  |  | 80 |  |  |  | 95 |  | (64)
Change in Plenitude Non-GAAP operating profit (loss) 2025 vs. 2024 | (62) |  |  | (50) |  |  |  | 14 |  | (26)

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The items excluded from GAAP operating loss in determining the Non-GAAP measure of profitability mainly include effects associated with commodity fair-valued derivatives, lacking the formal criteria to be classified as hedges under IFRS which amounted to a charge of €368 million.

|  | Year ended December 31,
|  | 2025 |  | 2024 |  | 2023
Enilive and Plenitude |  | (€ million)
GAAP operating profit (loss) |  | 652 |  | 1,589 |  | (74)
(Profit) loss on inventory |  | 115 |  | 112 |  | 47
Risk provisions |  |  |  | 2 |  | 8
Impairment losses (impairment reversals), net |  | 7 |  | 113 |  | 45
Environmental provisions |  | 57 |  | 38 |  | 36
Provision for redundancy incentives |  | 2 |  | (2) |  | 22
Fair value (gains)/losses on commodity derivatives |  | 368 |  | (682) |  | 1,142
Reclassification of currency derivatives and translation effects to management measure of business performance |  | (1) |  | (1) |  | 2
Other |  | 36 |  | 18 |  | 29
Total identified gains and charges |  | 584 |  | (402) |  | 1,331
Non-GAAP operating profit (loss) |  | 1,236 |  | 1,187 |  | 1,257
of which: |  |  |  |  |  |
- Enilive |  | 682 |  | 571 |  | 742
-Plenitude |  | 554 |  | 616 |  | 515

Refining and Chemicals

In 2025, this segment reported an operating loss of €2,485 million compared to a loss of €1,681 million in the previous year, due to an almost €0.6 billion increased loss on inventories evaluated at the weighted average cost or net realized value whichever is the lower, and a deteriorated performance of the chemical business affected by a negative scenario.

The main item excluded from GAAP operating profit in determining the Non-GAAP profitability measure of this segment is the inventory holding gain (or loss). Inventory holding gains or losses represent the difference between the cost of sales of the volumes sold during the period calculated using the cost of supplies incurred during the same period and the cost of sales calculated using the weighted average cost method. Under the weighted average cost method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historic cost of purchase, or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant impact on reported income thereby affecting comparability. The amounts disclosed represent the difference between the charge (to the income statement) for inventory on a weighted average cost method basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during the period is principally calculated on a quarterly or monthly basis by dividing the total cost of inventory acquired in the period by the number of barrels acquired. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. We regard the inventory holding gain or loss, including any write-down to align the carrying amounts of inventories to their net realizable value at the reporting date, as lacking correlation to the underlying business performance which we track by matching revenues with current costs of supplies.

Other identified charges included asset impairments and environmental risk provisions.

In 2025, Eni’s refining business reported a Non-GAAP operating loss of €77 million, in line with the year-ago loss.

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In addition to the inventory holding profit (or loss), the identified items of this business for the year 2025 comprised the write-down of capital expenditures made for compliance and stay-in-business at certain CGU with expected negative cash flows (€253 million) and environmental provisions of €133 million reflecting updated estimates of remediation costs at operational hubs.

The Chemical business reported a non-GAAP operating loss of €819 million in 2025, compared to a non-GAAP operating loss of €814 million in 2024 due to lower products margins and to a lesser extent, reduced sales volumes driven by lower demand across all business segments due to a slowdown in the macro environment and comparatively higher production costs in Europe for energy inputs and other expenses, which reduced the competitiveness of Versalis production with respect to US and Asian players, against the backdrop of global overcapacity and rising competitive pressures. Those negatives were partly offset by lower expenses due to plant closures and cost efficiencies. The Eni’s subsidiary is implementing a vast and complex turnaround plan to regain profitability by shutting down unprofitable plants, upgrading uneconomical facilities to manufacturing hubs for the energy transition and developing remunerative product lines like biochemicals, polymers from recycled plastics and compounding. As part of this plan, the two loss-making cracking plants of Brindisi and Priolo have been definitively halted. The management expects improvements to the operating profit in the course of 2026.

In addition to the inventory holding profit (or loss), the identified items of this business for the year 2025 comprised an impairment loss taken at polyethylene plants reflecting a deteriorated profitability outlook and the write-down of capital expenditures made for compliance and stay-in-business (€198 million) at certain CGU with expected negative cash flows and environmental provisions of around €173 million relating estimations of remediation costs in hubs under transformation and other charges of around €77 million reflecting the costs incurred to close down unprofitable plants.

| change | of which: |  | price effects |  |  |  | volume/mix effects |  | cost effects
| (€ million) |  |
Change in Refining Non-GAAP operating profit (loss) 2025 vs. 2024 | (1) |  |  | 141 |  |  |  | (108) |  | (34)
Change in Chemical Non-GAAP operating profit (loss) 2025 vs. 2024 | (5) |  |  | (42) |  |  |  | (43) |  | 80

|  | Year ended December 31,
|  | 2025 |  | 2024 |  | 2023
Refining and Chemicals |  | (€ million)
GAAP operating profit (loss) |  | (2,485) |  | (1,681) |  | (2,121)
(Profit) loss on inventory |  | 684 |  | 95 |  | 557
Environmental provisions and other costs net of a gain of an environmental agreement |  | 306 |  | 177 |  | 337
Impairment losses (impairment reversals), net |  | 451 |  | 455 |  | 726
Net gains on disposal of assets |  | (5) |  | (2) |  | (9)
Risk provisions |  | 36 |  | 33 |  | 11
Provision for redundancy incentives |  | 11 |  | 19 |  | 31
Fair value (gains)/losses on commodity derivatives |  | (8) |  | (1) |  | (1)
Reclassification of currency derivatives and translation effects to management measure of business performance |  | 7 |  | 6 |  | 11
Other |  | 107 |  | 9 |  | 96
Total identified gains and charges |  | 1,589 |  | 791 |  | 1,759
Non-GAAP operating profit (loss) |  | (896) |  | (890) |  | (362)
- Refining |  | (77) |  | (76) |  | 252
- Chemicals |  | (819) |  | (814) |  | (614)

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Corpo r ate and Other act i vities. These activities are mainly cost centers comprising holdings, financing and treasury activities in support of operating subsidiaries, central functions like legal affairs, human resources, captive insurance activities, general and administrative support, as well as research and development, new technologies, business digitalization and the environmental activity developed by the subsidiary Eni Rewind. Furthermore, the results of CCUS and Agribusiness of Eni have been included in the “Corporate and other activities” reporting segment. More information on the Company's segment reporting is disclosed in note n.35 to the Consolidated Financial Statements.

The aggregate Corporate and Other activities reported an operating loss of €1,499 million compared with a loss of €371 million in 2024. A higher loss was due to a risk provision relating to a proceeding pending before the Italian Antitrust Authority (AGCM) and the circumstance that in the previous year Eni recognized a one-off gain relating to the agreement with an Italian operator for the sharing of environmental costs incurred by Eni at certain decommissioned Italian sites jointly managed in the past.

e) Net finance e xpenses

The ta b le b e l o w sets f orth a b r eakd o wn of Eni’s net f inancial e xpenses f or the periods indic a ted:

|  | Year ended December 31,
|  | 2025 |  | 2024 |  | 2023
|  | (€ million)
Income (expense) on derivative financial instruments |  | (80) |  | 278 |  | (61)
of which - Derivatives on exchange rate |  | (86) |  | 310 |  | (63)
- Derivatives on interest rate |  | 6 |  | (32) |  | 2
Exchange differences, net |  | 133 |  | (38) |  | 255
Finance expense from banks on short and long-term debt |  | (1,026) |  | (1,185) |  | (874)
Interest expense for lease liabilities |  | (348) |  | (314) |  | (267)
Interest income due to banks |  | 191 |  | 294 |  | 356
Net income from financial assets measured at fair value through profit or loss |  | 235 |  | 388 |  | 284
Finance expense due to the passage of time (accretion discount) |  | (250) |  | (261) |  | (341)
Other finance income and expense, net |  | 204 |  | 17 |  | 81
|  | (941) |  | (821) |  | (567)
Finance expense capitalized |  | 122 |  | 222 |  | 94
NET FINANCE EXPENSES |  | (819) |  | (599) |  | (473)

In 2025, net finance expenses were €819 million (€599 million in 2024). The increase in net finance expenses in 2025 compared to 2024 was due to lower gains at commodity derivatives due to trends in the EUR vs USD exchange rates and lower income recorded at fair-valued financial assets held for trading.

f) Net income f r om i n v estments

The ta b le b e l o w sets f orth a b r eakd o wn of Eni’s net income from investments f or the periods indic a ted:

|  | Year ended December 31,
|  | 2025 |  | 2024 |  | 2023
|  | (€ million)
Share of gains (losses) from equity-accounted investments |  | 1,161 |  | 866 |  | 1,336
Dividends |  | 242 |  | 227 |  | 255
Net gains (losses) on disposals |  | 77 |  | 562 |  | 430
Other income (expense), net |  | 107 |  | 195 |  | 423
|  | 1,587 |  | 1,850 |  | 2,444

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In 2025, the Group reported a net profit from investments of €1,587 million, down by €263 million from 2024 mainly due to lower net gains on the disposal of assets (down by €485 million), following the circumstance that in 2024 this line item included the gains on the divestment of certain assets in the E&P segment as well as the sale of a 10% stake in the equity interests of Saipem. This reduction was partly offset by increasing Eni’s share of profits generated by equity-accounted investments (up by €295 million) and was mainly driven by higher profits in the Exploration & Production segment (up by €212 million), mainly driven by a higher net result at Vår Energi due to asset revaluations and exchange rate gains, and in the Refining and Chemical segment (up by €47 million) as well as in the Corporate and Other activities segment (up by €44 million).

A break-down of profits earned for the main investments is provided below:

|  | (i) | in E&P, we recognized a profit of €1,116 million, an increase of €212 million. It included Eni’s share of results in the joint venture Vår Energi (€602 million), the Azule Energy Holdings joint venture (€415 million), as well as Eni’s share in Ithaca Energy (loss of €15 million);
|  | (ii) | The GGP SeaCorridor associate for €32 million;
|  | (iii) | The Refining ADNOC Refining&Trading associate, where we recognized a profit of €121 million ;
|  | (iv) | the joint venture Saipem, where we recognized a profit of €71 million.

Dividends of €242 million were paid by minority investments in certain entities which were designated at fair value through other comprehensive income under IFRS 9, except for dividends which were recorded through profit. These entities mainly comprised Nigeria LNG Ltd (€156 million) and Everen Ltd (€30 million).

Net gains on the disposal of assets amounted to €77 million, decreasing by €485 mainly and referred to the divestment of an interest in Ithaca Energy and the sale of a 49.99% stake in Eni CCUS Holding.

g) T a x es

In 2025, income taxes decreased by €705 million to €3,020 million and compared to the pre-tax profit of €5,778 million resulted in a tax rate of 52.3% (compared to 57.4% in 2024). The reduction in 2025 tax rate was due to : i) recognition of €385 million of deferred tax assets at Italian subsidiaries due to reinstatement of previously written-off tax-loss carryforwards reflecting an improved profitability outlook; ii) a better geographical mix of profits before taxes in E&P reflecting higher contribution from jurisdictions with lower-than-average tax rates also as result of portfolio rationalization; iii) recognition of the tax benefit associated with previously incurred exploration expenses at certain development projects that were matured to final investment decision “FID” in 2025; iv) lower non-deductible charges recorded at certain E&P foreign subsidiaries.

The management also calculated an adjusted tax rate which excluded identified items from taxable profit and the tax effect associated with identified items and write-ups of previously impaired tax assets from the line-item income taxes. This adjusted tax rate, which is the measure of tax rate tracked by management, decreased by approximately 8 percentage points in 2025 compared to 2024, to 44%. The reduction in the Group adjusted tax rate was driven by the E&P segment due to recognition of a one-off benefit as several development projects were matured to FID enabling the recognition of the tax benefit associated with previously incurred exploration expenses, and a better geographical mix of pre-tax profits as explained above.

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Liquidity and capital r esou r ces

Eni’s cash requirements for working capital, dividends to shareholders, capital expenditures, acquisitions and share repurchases have been financed in the last three years primarily by a combination of funds generated from operations, issues of equity investments (hybrid bonds), divestments of property, plant and equipment and shareholdings in equity accounted entities, or the reimbursement of operating financing receivables owed to Eni by unconsolidated entities, and in 2025 also by taking on new finance debt. The Group continually monitors the balance between cash flow from operating activities and net expenditures, targeting a sound and balanced financing structure.

The following table summarizes the Group cash flows and the principal components of Eni’s change in cash and cash equivalent for the periods indicated.

This cash flow statement is a GAAP measure of cash flow and is presented herein to help readers understand the change in the year of the Group net borrowings which is a NON-GAAP measure as explained further on.

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (€ million)
Net profit (loss) | 2,758 |  | 2,764 |  | 4,860
Adjustments to reconcile net profit to net cash provided by operating activities: |  |  |  |  |
- amortization and depreciation charges, impairment losses, write-off and other non monetary items | 7,209 |  | 9,951 |  | 7,781
- net gains on disposal of assets | (99) |  | (601) |  | (441)
- dividends, interest, taxes and other changes | 3,590 |  | 4,246 |  | 5,596
Changes in working capital related to operations | 2,735 |  | 1,286 |  | 1,811
Dividends received by equity investments | 1,785 |  | 1,946 |  | 2,255
Taxes paid | (3,737) |  | (5,826) |  | (6,283)
Interests (paid) received | (911) |  | (674) |  | (460)
Net cash provided by operating activities | 13,330 |  | 13,092 |  | 15,119
Capital expenditures | (8,647) |  | (8,485) |  | (9,215)
Acquisition of investments and businesses | (878) |  | (2,593) |  | (2,592)
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments | 1,383 |  | 2,788 |  | 596
Other cash flow related to investing activities | 183 |  | (996) |  | (348)
Net cash inflow (outflow) related to financial activities | (1,339) |  | (531) |  | 2,194
Changes in short and long-term finance debt | (2,555) |  | (1,293) |  | 315
Repayment of lease liabilities | (1,250) |  | (1,205) |  | (963)
Dividends paid and changes in non-controlling interests and reserves | 537 |  | (4,522) |  | (4,882)
Net issue (repayment) of perpetual hybrid bond | (328) |  | 1,640 |  | (138)
Effect of changes in consolidation and exchange differences of cash and cash equivalent | (198) |  | 83 |  | (62)
Net increase (decrease) in cash and cash equivalent | 238 |  | (2,022) |  | 24
Cash and cash equivalent at the beginning of the year | 8,183 |  | 10,205 |  | 10,181
Cash and cash equivalent at year end | 8,421 |  | 8,183 |  | 10,205

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| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (€ million)
Net cash provided by operating activities | 13,330 |  | 13,092 |  | 15,119
Capital expenditures | (8,647) |  | (8,485) |  | (9,215)
Acquisitions of investments and businesses | (878) |  | (2,593) |  | (2,592)
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments | 1,383 |  | 2,788 |  | 596
Other cash flow related to capital expenditures, investments and divestments | 183 |  | (996) |  | (348)
Repayment of lease liabilities | (1,250) |  | (1,205) |  | (963)
Net borrowings (1) of acquired companies | (762) |  | (631) |  | (234)
Net borrowings (1) of divested companies | 362 |  |  |  | (155)
Exchange differences on net borrowings and other changes | (1,141) |  | (364) |  | (1,061)
Dividends paid, share repurchases and changes in minority interest and reserves | 537 |  | (4,522) |  | (4,882)
Net issue (repayment) of perpetual hybrid bond | (328) |  | 1,640 |  | (138)
Change in net borrowings(1) before IFRS 16 effects | 2,789 |  | (1,276) |  | (3,873)
Repayment of lease liabilities | 1,250 |  | 1,205 |  | 963
Inception of new leases and other changes | (497) |  | (2,322) |  | (1,348)
Change in net borrowings after IFRS 16 effects (1) | 3,542 |  | (2,393) |  | (4,258)
Net borrowings (1) at the beginning of the year | 18,628 |  | 16,235 |  | 11,977
Net borrowings (1) at year end | 15,086 |  | 18,628 |  | 16,235

(1) Net borrowings is a non-GAAP financial measure. For a discussion of the usefulness of net borrowings and its reconciliation with the most directly comparable GAAP financial measures see “Financial Condition” below.

In 2025, adjustments to reconcile the net profit reported in the year to net cash provided by operating activities mainly related to depreciation, depletion, amortization, impairment charges and results of equity-accounted entities for €7,209 million. Adjustments to net profit also included accrued income taxes (€3,020 million) and net interest expense (€812 million), which were partly offset by amounts actually paid (€3,737 million and €911 million, respectively).

The dividends received by equity-accounted investments of €1,785 million mainly related to Azule Energy Holdings, Vår Energi and Adnoc R&T, while other dividends recorded through profit of €156 million mainly related to Nigeria LNG.

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a) Chan g es in w o r king capital r e lated to ope r ations

In 2025, working capital generated an inflow of €2,735 million driven by several initiatives to optimize working capital needs including non-recourse arrangements to discount certain receivables in support of supply and trading activities and the management of credit risk, partly offset by the cash-outs relating to utilizations of provisions in connection with advancement of Group’s decommissioning activities at oil&gas assets and environmental remediation programs.

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (€ million)
Exploration & Production | 6,253 |  | 6,055 |  | 7,135
Global Gas & LNG Portfolio and Power | 109 |  | 110 |  | 119
Enilive and Plenitude | 1,232 |  | 1,303 |  | 1,064
Refining and Chemicals | 663 |  | 632 |  | 556
Corporate and other activities | 430 |  | 408 |  | 360
Impact of unrealized intragroup profit elimination | (40) |  | (23) |  | (19)
Capital expenditures | 8,647 |  | 8,485 |  | 9,215
Acquisitions of investments and businesses | 878 |  | 2,593 |  | 2,592
| 9,525 |  | 11,078 |  | 11,807
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments | (1,383) |  | (2,788) |  | (596)

Capital expenditures totaled €8,647 million and €8,485 million, respectively in 2025 and in 2024.

For a discussion of capital expenditures by business segment and a description of year-on-year changes see “Capital expenditures by segment”.

Cash outflows for acquisitions of €878 million mainly related to the purchase of renewable generation capacity at Plenitude (€0.5 billion) and additional working interest at certain fields in the E&P (€0.1 billion). These outflows were offset by the divestment of a 30% stake in the Baleine project (€1.1 billion) and other non-strategic fields in Congo.

b) Dividends paid, sha r e r epu r chases and chan g es in non-cont r olling inte r ests and r eser v es

In 2025, dividends paid and changes in non-controlling interests and reserves (€537 million) related to the dividends paid to Eni shareholders (€3,080 million which comprised two quarterly installments of the 2024 dividend for about €1.5 billion and the first and the second quarterly installment of the 2025 dividend of €0.26 per share each, amounting to €1.6 billion). The company purchased own shares for an amount of €1,896 million to complete the 2024 buy-back program (€0.4 billion) and as a part of the 2025 new buy-back program (€1.5 billion). As of February 18, 2026, the 2025 buy-back program was completed with an overall amount of 119 million shares purchased for a cash outlay of €1,800 million.

Cash returns to shareholders were offset by the cash-ins associated with transactions among owners as the Company agreed to dispose noncontrolling interests in Enilive where KKR equity fund finalized an investment of 30% in the share capital of the subsidiary for net proceeds of €3.57 billion to Eni, and Plenitude where Ares equity fund purchased a 20% interest for €2 billion and previously EIP fund increase its outstanding stake by further 2.4% to 10% for cash consideration of €0.21 billion.

Financial condition

Management assesses the Group’s capital structure and financial condition by tracking net borrowings, which is a non-GAAP financial measure. Eni calculates net borrowings as total finance debt (short-term and long-term debt, including finance leases as per IFRS 16) derived from its Consolidated Financial Statements prepared in accordance with IFRS less: cash, cash equivalents and certain highly liquid investments not related to operations including, among others, a liquidity reserve made of held-for-trading securities and finally other liquid assets not related to operations, mainly cash deposits at exchanges and other financial counterparts established as a collateral of derivative transactions. The Group also included in its financial assets subtracted from gross finance debt certain long-term financing receivables owed to us by non-consolidated entities to reflect the increasing financial autonomy of such entities as provided by our “satellite strategy”, resulting in the Group being exposed only to a credit risk with respect to those entities. The amount of those long-term financing receivables reclassified among financial assets was around €3 billion as of December 31, 2025. Net borrowing is also calculated by excluding liabilities of financial leases (ex IFRS 16).

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Financial assets measured at fair value through profit or loss constituting part of the Group’s liquidity reserves amounted to around €7 billion as of end of 2025 and were accounted as mark-to-market financial instruments. Of this amount, fixed income securities issued by industrial companies and financial institutions were €6.1 billion. Although the fair value of these investments is netted from financial debt in our calculation of net borrowings, there is no certainty that these investments could be readily monetizable at their carrying value, particularly in the event of market stress. For further information, see “Item 18 – Note 7 – Financial assets at fair value through profit and loss – of the Notes to the Consolidated Financial Statements”.

Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways in which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest plus net borrowings “gearing” to assess Eni’s capital structure, to analyse whether the ratio between finance debt and total funds is well balanced compared to industry standards and to track management’s short-term and medium-term targets. That ratio is also calculated excluding IFRS 16 lease liabilities from both numerator and denominator. Management continuously monitors trends in net borrowings and trends in gearing in order to optimize the use of internally-generated funds versus funds from third parties. The measure calculated in accordance with IFRS that is most directly comparable to net borrowings is total finance debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to gearing is the ratio of total debt to shareholders’ equity (including non-controlling interest) plus total finance debt. Eni’s presentation and calculation of net borrowings and gearing may not be comparable to other companies.

The tables below set forth the calculations of net borrowings and gearing for the periods indicated and their reconciliation to the most directly comparable GAAP measure.

| (€ million) | Dec 31 2025 | Dec 31 2024
Total finance debt including lease liabilities |  | 34,164 | 36,801
less: |  |  |
Cash and cash equivalents (a) |  | (8,242) | (8,183)
Financial assets measured at fair value through profit or loss |  | (6,991) | (6,797)
Financing receivables held for non-operating purposes (b) |  | (3,845) | (3,193)
Lease liabilities |  | (5,700) | (6,453)
Net borrowings excluding lease liabilities (a) |  | 9,386 | 12,175
Shareholders' equity including non-controlling interest (b) |  | 52,787 | 55,648
Gearing before lease liabilities ex IFRS 16 (a/b+a) |  | 0.15 | 0.18
(a) It includes €142 mln of cash at held-for-sale subsidiaries provisionally deposited at third-party banks at the end of 2025 and then moved to the Group cash pooling at the beginning of 2026.
(b) Considering Eni’s strategy based on the satellite model which envisages an increasing financial autonomy of non-consolidated entities, it includes loans granted to certain JVs, where Eni is exposed solely to a credit risk as a repayment plan is scheduled. Therefore, such financing receivables have been netted against gross finance debt to determine Eni’s net borrowings and to calculate the Group gearing. See also Item 18 - Note 20 on Consolidated Financial Statements.

|  | As of December 31,
|  | 2025 |  | 2024
|  | (€ million)
Shareholders’ equity including non-controlling interest as per Eni’s Consolidated Financial Statements prepared in accordance with IFRS |  | 52,787 |  | 55,648
Ratio of finance debt including lease liabilities to total equity plus finance debt |  | 0.39 |  | 0.40
Less: ratio of cash, cash equivalents and financial assets to total equity plus net borrowings |  | (0.17) |  | (0.15)
Ratio of net borrowing to total equity plus net borrowings (gearing including IFRS 16 lease liabilities) |  | 0.22 |  | 0.25
Ratio of net borrowing excluding lease liabilities to total equity plus net borrowings excluding lease liabilities (gearing ex IFRS 16) |  | 0.15 |  | 0.18

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At December 31, 2025, total finance debt of €34,164 million including lease liabilities consisted of €8,363 million of short-term debt (including the portion of long-term debt due within twelve months equal to €3,434 million) and €20,101 million of long-term debt. At the same date, lease liabilities were €5,700 million (short-term portion €1,263 million).

In 2025, net borrowings including lease liabilities amounted to €15,086 million, representing a €3,542 million decrease from 2024 driven by net cash provided by operating activities and proceeds from asset disposal and divestments of noncontrolling interests in subsidiaries significantly exceeding capital expenditures, cash returns to shareholders and other contractual obligations as IFRS 16 lease liabilities (down to €5,700 million as of December 31,2025 from €6,453 million as of December 31, 2024) mainly related to the Exploration & Production segment and comprised leases of certain FPSO vessels and platforms used in the development of the OCTP offshore projects in Ghana, Area 1 in Mexico and the Baleine project in Cote d’Ivoire, as well as the multi-year rental of rigs; to the Enilive business line relating to highways concessions, land leases, leases of service stations for the sale of oil products and the car fleet dedicated to the car sharing business; to the Corporate and Other activities segment mainly regarding property rental contracts (real estate and IT).

Net borrowings excluding the lease liabilities, which is the Non-GAAP measure of financial condition mostly tracked by management would amount to €9,386 million, down by €2.8 billion compared to December 31, 2024.

The ratio of finance debt to total equity plus finance debt was 0.39 at 2025 year-end, including the IFRS 16 lease liability (0.40 in 2024). Total equity of €52,787 million decreased by €2,861 million from December 31, 2024. This was due to negative foreign currency translation differences (€6,410 million) reflecting the depreciation of the US dollar vs. the euro as of December 31, 2025 vs. December 31, 2024, the payment of dividends to Eni shareholders (two tranches of the 2024 dividend for €1.5 billion and the first and the second quarterly instalment of the 2025 dividend for €1.6 billion) as well as the buy-back of Eni shares (€1.9 billion). Those decreases were partly offset by the net profit for the period (€2.76 billion), and the recognition through retained earnings of the positive difference between the book value of the noncontrolling interests in the subsidiaries Enilive and Plenitude divested to third parties and the consideration received (€3.4 billion).

The Group Non-GAAP measure of its financial condition mostly tracked by management was gearing calculated as ratio of net borrowings to total equity plus net borrowings excluding lease liabilities and was 0.15 at year end. Considering that in 2025 the non-controlling interest increased significantly, gearing calculated considering only equity attributable to Eni’s shareholders (€47.9 billion) would be 0.16.

Capital e xpenditu r es by segment

Exploration & Production. In 2025, capital expenditures of the Exploration & Production segment amounted to € 6,253 million and mainly related to the development of hydrocarbon fields (€5,502 million). Significant expenditures were directed mainly in the United Arab Emirates, Libya, Egypt, Indonesia, Algeria, Congo and Italy.

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Global Gas & LNG Portfolio and Power.

In 2025, capital expenditure in the Global Gas & LNG portfolio and Power totaled €109 million relating to power plants upgrading.

Enilive and Plenitude In 2025, capital expenditures in the Enilive and Plenitude segment amounted to €1,232 million. Plenitude’s capital expenditure was €764 million related to development activities in the renewable business, acquisition of new customers, as well as development of electric vehicles network infrastructure, Enilive’s capital expenditure was €468 million mainly related to biorefineries and marketing activity in Italy and in the rest of Europe, regulation compliance and stay-in-business initiatives in the retail network, as well as HSE initiatives.

Refining and Chemicals

In 2025, capital expenditures in the Refining and Chemicals segment amounted to €663 million and mainly related to: (i) traditional refining in Italy (€481 million) relating to the reconversion of Livorno in biorefinery, maintenance and stay-in-business; and (ii) circular economy and asset integrity in the chemical business (€182 million).

Recent d e v elopments and significant transactions

The ta b le b e l o w sets f orth certain indic a tors of the t r ading e n vi r onment f or the periods indic a ted (rounded for the first quarter 2026):

|  | Three months ended March 31, |  | January 1 through March 19,
|  | 2025 |  | 2026
Average price of Brent dated crude oil in U.S. dollars (1) |  | 75.7 |  | 76
Average EUR/USD exchange rate (2) |  | 1.052 |  | 1.17
Standard Eni Refining Margin (SERM) (3) |  | 3.8 |  | 10
Gas at the TTF in $/mmBTU |  | 14.4 |  | 13

(1) | Price per barrel. Source: S&P Global Energy.
(2) | Source: ECB.
(3) | In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations.

See “management expectations of operations” below for a discussion on how key market indicators are performing against management’s expectations.

The main business transactions that occurred in the first quarter 2026 are reported in Item 4. See also section “Subsequent events” in the Notes to the Consolidated Financial Statements.

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Management’s expectations of operations

Business trends

Exploration & Production

In the next five-year plan 2026-2030, the management intends to increase the financial returns of the E&P segment at a constant scenario basis leveraging profitable production growth, capital and cost discipline, and reduction of time-to-market of projects. At the same time, we are planning to reduce CO2 direct emissions and methane emissions at our E&P operations.

Our plans are assuming a Brent crude oil price scenario of:

| 2026 |  | 2027 |  | 2028-2030 |  | 2040 |  | 2050
Brent crude oil price $/bbl real terms 2025: | 68 |  | 66 |  | 75 |  | 65 |  | 53

Our long-term price forecast factored our expectations about possible impacts of the energy transition on crude oil demand and prices. Our Brent price assumption in nominal terms for 2026 is 70 $/bbl.

Against those pricing assumptions, we plan to increase production at a compounded average growth rate “CAGR” of around 3-4% through 2030. This growth rate would be higher when excluding impacts of the planned divestment of part of our working interests at certain assets. The main drivers of this expected growth are the development of new projects in Libya, Qatar, UAE, Egypt, the subsequent project phases at the Baleine field off Cote d’Ivoire and at the Congo FLNG project where a floating production vessel was moored at the end of 2025, the start of an LNG-focused joint venture in Indonesia, as well as new fields start-ups and ramp-ups in Angola and Norway. The long-term plateau will be supported by the development of our more recent discoveries, like the gas discoveries off Cyprus, the Coral North gas discovery off Mozambique, where we took FID in 2025, and finally the first gas at the large Argentina FLNG project expected in the medium term. New fields start-up and ramp-up will contribute around 850 KBOE/d of new production in 2030, underpinning achievement of our growth objectives. LNG expansion is expected to make the largest contribution to this expected growth. Therefore, our production plans contemplate a gradual increase of the proportion of natural gas, liquefied natural gas and natural gas liquids in the production mix till achieving a higher share than liquids by 2030. Another feature of our production plans is geographic diversification as we expect to significantly increase the share of Americas and Far East in our portfolio at 2030, gaining better exposure to fast growing energy markets.

Due to market risks and uncertainties, management intends to retain a strong focus on capital and cost discipline, on shortening the projects cycle and on reducing the time-to-market of our reserves and the breakeven Brent price as levers to maintain our development projects profitable through the cycle.

We plan to invest a major part of the Group €29 billion gross expenditures budgeted for the next five-year plan 2026-2030 to explore for and develop hydrocarbons reserves. Those expenditures do not include expected expenditures that will be incurred by our participated joint ventures and associates, like the expenditures that will be incurred by Var Energi, Azule Energy, Ithaca Energy and the LNG joint venture in Indonesia/Malaysia, this latter expected to become operational by mid-2026. Those equity-accounted entities are expected to self-finance their respective capital expenditures requirements, without recurring to shareholders’ funds. Our capex plan includes the assumptions of continuing inflationary pressures throughout the E&P supply chain, albeit at a slower pace than in recent years, and a gradual appreciation of USD vs the EUR.

Our strategy is designed to retain profitable and cash-generative E&P operations, by leveraging accretive exploration and effective development and field operation activities to accelerate the time-to-market of reserves which will help the Company reduce projects’ pay-back period, minimize financial exposure and lower the full cycle cost of the barrel and hence the Brent breakeven price. The execution of an asset disposition plan will help accelerate the cash conversion cycle of reserves, i.e. in a stage earlier than production. Asset dispositions will target high-potential discoveries with large working interests, where we can dilute our stakes maintaining the operatorship in line with our dual exploration model, as well as mature producing fields. The cash proceeds from asset disposals will reduce the cash requirements to fund the organic growth plans. As part of this model, in 2025 we divested a 30% interest in the large Baleine oilfield offshore Cote d’Ivoire with net proceeds of €1.1 billion and we are planning to divest a further 10% interest of this asset as well as a 25% interest in the Congo FLNG project.

We believe that this strategy based on capital discipline and acceleration of the cash conversion cycle of reserves is warranted to reduce the segment’s financial exposure and the Brent price of breakeven of projects given current uncertainties in the short- and medium-term outlook due to a possible macroeconomic slowdown and risks of oversupplies, as well as the risks posed by the energy transition in a longer term.

We plan to carefully select our development projects against our pricing assumptions and minimum requirements of internal rates of return. We intend to reduce financial exposure and the execution risk leveraging on a phased approach in developing our projects. Although we plan to deliver our planned projects on time and on budget, several of our projects are complex due to scale and reach of operations, environmentally sensitive locations, external conditions, including offshore operations, potential industry bottlenecks like in the case of shipyards and rigs and other industry limits and other considerations including the risk factors described in Item 3. These constraints and factors might cause delays and cost overruns. In addition, costs of industrial inputs (labor, materials, field services) are expected to rise driven by inflation, albeit at a smaller pace than in recent years. Sticky inflationary pressures in the oil supply chain have been driven by downsizing, restructuring, merging and investment reduction at suppliers of specialized oilfield services, rigs, and other equipment in response to a prolonged downturn in the oil sector from 2015 throughout the COVID pandemic and now again with the 2025 oil price downturn, resulting in possible or actual constraints in the supply of vessels, rigs and skilled labor. Our capital plans included our best assumptions of expected cost increases due to inflation. To deliver on our expected rate of returns at our projects and on reducing the time-to-market of reserves we are planning to:

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 performing project activities in accordance with a so-called parallel approach as opposed to a sequential approach, for example the discovery appraisal and pre-fid activities, by upgrading existing plants and vessels and by deploying a phased project approach to achieve early start-up and then ramping up production, thus reducing the time-to-market and financial exposure. An example of this approach is the Baleine project where we reached an initial production target of 70 Kbbl/d in just four years from the discovery (2021) by utilizing a refurbished floating production vessel to speed up activities. In the meantime, a new floating production vessel is being built to achieve the production ramp up to plateau. The Congo FLNG project, which started at the end of 2022, achieved the start of phase two by end of 2025 with the installation and commissioning of a second vessel for the floating production of LNG which has significantly increased installed LNG production capacity and is set to make its first LNG loading shortly. The development of gas reserves located in the Coral discovery area off Mozambique will be boosted by installation of a second unit for floating LNG production in the Coral North area, which is expected to start operations in just three years leveraging the know-how of the Coral South FLNG deployment;

 signing master agreement with our main suppliers to maximize cost savings and by designing facilities using a modular approach that enables us to extend the useful lives of plants and vessels;

 leveraging on near-field or infrastructure-led exploration that has proven to be effective at increasing the reserves at already producing fields thus enabling to exploit synergies from existing facilities so to reduce the time to market and extend the useful lives of existing plants. For example, the important natural gas discoveries off Indonesia, among which the recent Konta discovery, are planned to be developed through the production facilities existing in the area, including the spare capacity available at the Bontang liquefaction plant and the operated Jangkrik FSU vessel. Those development strategies will help reduce the time-to-market of reserves and obtain expenditures savings in development activities;

 continuing in-sourcing of critical engineering and project management phases, for example by exercising tight control over construction, hook-up and commissioning, which based on our experience could significantly improve the ability of the Company to carry out projects on time and on budget;

 applying our design-to-cost method whereby the Company has redirected its exploration efforts towards mature and low-complexity areas where we can achieve fast time-to-market and cost synergies, for example the Congo LNG project and the discoveries in Indonesia. We expect that cost control and profitable operations will be supported by continued progress in our technologies designed to improve drilling performance and the recovery factor and digital investment to improve workplace safety and asset integrity thus reducing asset downtime.

According to our plans, exploration will continue ensuring cost-effective replacement of produced reserves and fast time to market, supporting cash generation and evolving our reserve portfolio towards the planned mix of resources featuring a larger proportion of natural gas relative to the portfolio as well as geographic diversification. Our exploration initiatives will comprise two clusters:

 Exploration projects in near-field prospects and in proven/mature areas and in other infrastructure-lead basins i.e. in permits close to producing fields, where we can leverage existing infrastructures to readily develop the discovered resources, attaining fast contribution to cash flow and production levels with minimum impact on expenditures;

 Selected initiatives in high-risk/high-rewards plays, where we retain high working interest and the operatorship, which will enable us to apply our dual exploration model in case of material discoveries with a view of accelerating the conversion of resources into cash.

Our production plans include assumptions relating to production levels in certain countries that are particularly exposed to risks of disruptions and political instability, including possible disruptions to our production levels in the countries involved in the current Middle East conflict. To factor in possible risks of unfavorable geopolitical developments in those countries, which may lead to temporary production losses and disruptions in our operations in connection with, among others, acts of war, sabotage, hits to production facilities social unrest, clashes, and other form of civil disorder, we have applied a haircut to our future production levels based on management’s appreciation of those risks, past experience and other considerations. This contingency factor does not cover worst-case developments and extreme events, which could determine prolonged production shutdowns. Furthermore, in recent years we have pursued a strategy intended to diversify the geographic reach of our operations aiming at reducing the geopolitical risk in our portfolio.

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Global Gas & LNG Portfolio

The gas market is currently in a situation of oversupply driven by massive additions to LNG export capacity in USA, where production and LNG exports have reached all-time highs, Qatar where a large LNG project is set to come online shortly and then Canada where a first LNG export plant started operations, while the biggest gas-importing country, China, has slowed down its LNG purchases also due to rising internal production. Gas demand has been weakening due to the scale-up of renewable generation capacity in EU, China and elsewhere, rising competition from the nuclear energy and weak economic activity in EU, partly offset by rising consumption from data centers. We expect gas prices to weaken in the medium-to-long term. The current disruptions to LNG production in the Middle East as a consequence of the conflict situation are expected to impact the market fundamentals at least in the short term leading to increased price volatility.

Against this backdrop, our GGP business has established a business model designed to achieve steady profitability and cash generation which are largely insulated from trends in natural gas prices and in market volatility. This business model is leveraging the continuing optimization of the segment’s asset portfolio (long-term contracts with contractual flexibilities, physical flows, access to transport capacity, availability of storage capacity, trading activities) and integration with E&P by trading growing amount of equity LNG to capture the full margin of the gas value-chain, as well as contractual renegotiations.

Our planning assumptions are discounting the zeroing of natural gas purchases from Russia, although our long-term supply contracts with Russia’s state-owned company Gazprom are still in force. Our sales commitments relating to supplies to our retail subsidiary Plenitude, to our natural gas-fired power plants owned by the subsidiary EniPower and other ongoing selling obligations will be covered by purchases under our outstanding long-term contracts with suppliers other than Russian counterparts and by maximizing the integration between the E&P and the GGP segments.

Against this scenario, the Company’s priority in its GGP business is to retain stable profitability and cash generation based on the following drivers:

(i) To continuously renegotiate our long-term gas supply and sale contracts to align pricing terms and delivery quantities to current market conditions and dynamics as they evolve;

(ii) To resume a growth trajectory in sales volumes by leveraging increasing supplies of LNG and signing sales contracts with Asian customers to balance and diversify the portfolio.;

(iii) To improve margins by maximizing portfolio optimizations leveraging synergies between gas and LNG and assets flexibilities;

(iv) To grow the LNG trading business leveraging on the integration with the E&P segment with the aim of maximizing the profitability of equity gas supplies along the entire value-chain. We plan to increase contracted supplies of LNG through new supplies from E&P’s equity production in Algeria, Congo, Qatar, Mozambique, and Cyprus leveraging the expected ramp-up of equity production of LNG to achieve a robust portfolio of reselling opportunities, aiming at obtaining a significant increase in contracted LNG volumes by 2030.

We make use of commodities and financial derivatives to hedge against the risks of different indexation formulas in our gas procurement costs vs. selling prices in relation to contracted sales or highly probable sales. A number of these derivatives may be accounted as trading derivatives because they lack formal criteria to be treated as hedges in accordance with IFRS and consequently are recorded through profit and loss and may add a component of volatility to our results of operations. Those derivatives are normally risk-reducing, although there is also a degree of uncertainty about results. Furthermore, we are also making use of derivatives to improve margins by leveraging on market volatility and availability of assets like the flexibilities associated with our take-or-pay gas contracts, LNG contracts, transport rights to capture arbitrage opportunities (for example the winter vs summer spread, the spot vs. the Brent indexation spread) and time lags in contracts indexation formulae. Those asset-backed derivatives are of speculative nature with gains and losses recognized through profit. Although asset availability tends to limit the possible downside risks associated with those derivatives, still the Company is exposed to price volatility and to the incurrence of losses also of significant amounts.

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Enilive (biofuels & marketing)

Enilive, operational from January 1, 2023, has been established through the spin-out of Eni’s activities in the field of biofuels manufacturing and in the retail marketing of fuels and non-fuels products. It also engages in selling fuels to wholesale markets and the cargo market. Enilive is designated to market increasing volumes of decarbonized fuels to people on the move, leveraging integration with its biorefineries as well as to grow the share of revenues from non-fuel products and services leveraging emerging trends in mobility and marketing innovations. In 2025, Eni and private equity fund KKR completed an investment transaction whereby KKR acquired an ownership interest of 30% in the share capital of Enilive with net proceeds of €3.6 billion to Eni. Eni is retaining control of the entity. This transaction highlight the value of the Enilive business model which integrates manufacturing operations in the biofuels segment with a significant retail market presence based on a network of modern and advanced service stations. Enilive will leverage its integrated business model to improve profitability going forward. Our forecast is also assuming a gradual increase in the spreads of biofuels over the costs of feedstock, which include waste&residues and vegetable oils as demand for biofuels is seen rising in the medium term driven by shifting consumers’ preferences and a favorable regulatory environment with mandatory target of biofuels volumes supplied to the market in the Eu economic space and in the USA. According to our forecast, increasing biofuels consumption will occur both in road transport and in the airline sector, with global demand significantly exceeding supplies from the medium term onwards.

To meet the expected increase in demand for biofuels, the Group is implementing an industrial plan to significantly grow the manufacturing capacity building a global business with the goal of reaching 5 million tons of installed capacity by 2030. The action plan contemplates upgrading existing plants, building and commissioning three biorefineries in Italy by reconverting traditional plants and international expansion with the expected start-up of two new plants under construction in South Korea in partnership with LG Chem and in Malaysia in partnership with Petronas and Euglena, as well as other initiatives at various stages of maturation. Our expansion will leverage our co-developed “Ecofining” technology to produce hydrogenated vegetable oils “HVO” and sustainable aviation fuels “SAF”, retaining high level of SAF optionality to capture market trends. The management is engaged in building a reliable and sustainable supply chain of bio-feedstock to be processed at the Company’s manufacturing units, maximizing feedstock flexibility. As part of that plan, we are developing a vertically integrated business model, which contemplates establishing a network of agricultural hubs in many of the countries of E&P operations, in Africa, in Italy and in other geographies. This activity is intended to not compete with the food chain and to produce a vegetable oil at Eni’s dedicated mills by treating supplies of raw vegetables grown by local farmers, supplied to Eni’s biorefineries under long-term agreements. The agricultural business will be scaled up in the planning period to reach a significant level of supplies by 2030. This vertical integration will strengthen Enilive’s access to supplies and boost margins on the production of biofuels, insulating our company from the volatility of raw materials costs.

In Marketing activities, where we expect a very competitive environment, we are seeking to retain steady and robust profitability mainly by focusing on innovation of products and services anticipating customer needs, strengthening our line of premium products, as well as efficiency. We plan to enhance the network by upgrading several service stations to transform them from traditional outlets into mobility hubs to capitalize on the growing demand for a wider mobility experience and by expanding the number of service stations where we will market our innovative HVO-based biofuels and other alternative energy carriers (for example the service of recharging electric vehicles and biomethane). Profitability will be also supported by increasing sales of non-fuel products and services leveraging new formats and partnerships with established operators in various fields and cross-selling opportunities with retail customers of Plenitude. Based on those drivers, the management expects that Enilive will significantly improve its profitability going forward.

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Plenitude

Plenitude is Eni’s subsidiary managing the Group legacy business to sell gas and power to the residential sector, as well as the new businesses of renewable generation of electricity and a network of charging points for EV. Plenitude intends to leverage synergies among those businesses to improve its profitability going forward. Plenitude has the mission to supply its customers with increasing volumes of decarbonized energy commodities, contributing to the Group medium and long-term targets of reducing CO2 emissions. In 2025, Eni and private equity fund Ares completed an investment transaction whereby Ares acquired an ownership interest of 20% in the share capital of Plenitude with net proceeds to Eni of €2 billion. Previously, Eni and private equity fund EIP agreed an equity investment of almost €0.8 billion (structured in two deals with same characteristics in 2024 and 2025) whereby EIP acquired noncontrolling interest of 10% in the share capital of Plenitude. Eni is retaining control of Plenitude. Furthermore, as announced in March 2026, the management has commenced a reorganization of the shareholding structure of Eni’s subsidiary Plenitude, which is involving the current noncontrolling shareholders of the entity Ares fund and Energy Infrastructure Partners. The aim is to establish a new governance framework based on joint control between Eni and Ares, which will result in the derecognition of Plenitude from Eni's financial statements, with a significant improvement to Eni’s financial position. Completion of this deal has been assumed in Eni’s financial plans for 2026.

Our forecast foresees that the EU power market will grow at a moderate pace till 2030 and that the environment for the expansion of renewable electricity production and generation capacity will remain supportive. In the retail market, we expect a very dynamic and competitive environment with the entrance of new operators and we see an opportunity in enhancing the offer to retail customers to preserve our market share. Finally, the business of recharges for EV will evolve in connection response to changing dynamics in the adoption rates of EV.

We plan to accelerate the development of the installed renewable capacity of wind and solar plants to reach about 15 GW of installed capacity by 2030 by developing the existing portfolio of projects and leveraging external growth through selected and synergistic business combinations and joint ventures entities. We plan to expand our network of charging points for electric vehicles with the objective of installing 30 thousand rechargers by 2030, in line with the expected rates of adoption of electric vehicles and by selecting the expenditures targeting mature markets and highly profitable installations. In the retail segment, we plan to grow our customer base, leveraging the pending acquisition of energy provider Acea Energia to strengthen our presence in the core Italian retail market and growing selectively outside Italy with the target to reach 15 million customers in Europe by 2030. We plan to boost profitability per customer and to preserve the customers portfolio in the context of expected rising competitive pressures by enhancing scale and reach of the commercial offer. Planned commercial initiatives include increasing supply volumes of equity renewable energy, expansion of the offer of new products and services other than the commodity and continuing innovation in marketing processes including the deployment of digitalization in the acquisition of new customers, a reduction in the cost to serve and effective management of working capital. Customer retention and expansion will also leverage cross-selling opportunities and joint marketing initiatives with Enilive. Based on those drivers, the management expects that Plenitude will significantly improve its profitability going forward.

Refining

The downstream oil refining business is exposed to structural headwinds in the European sector due to lack of scale, global overcapacity, higher energy costs and environmental expenses than in other geographies and tough competition from player in Middle East, Far East and Africa which can count on advantages due to economies of scale, lower expenses and proximity to expanding markets. The profitability of our refining business will be affected by expected weak economic growth in Europe and a structural reduction in consumption of fossil fuels in our key European markets due to an expected penetration of EVs and mandated measures by EU governments to reduce CO2 emissions. Based on those assumptions, we plan to retain a strong focus on plant efficiency and reliability, cost discipline, measures to optimize energy consumption in the operations to maximize our realized refining margins. Considering the structural weaknesses of the refining sector in Europe, we plan to continue evaluating economically-viable solutions to restructure and downsize our oil-based, operated refineries in Italy. Currently, works have started to transform the Livorno hub into a biorefinery, based on the same reconfiguration process that we deployed in the past to upgrade the Gela and the Venice refineries. The Livorno biorefinery is expected to start operations at the end of 2026, and by that time it is planned to be contributed to Enilive. Alo the Sannazzaro hub will be restructured with construction of a biorefinery unit, where authorization from relevant Italian authorities have been achieved and a final investment decision by the management is expected shortly.

Chemicals business

In 2025, the Eni’s chemicals sector managed by the subsidiary Versalis reported another year of losses due to the structural weaknesses of the business of commodity plastics, because of global overcapacity and rising competition from producers in USA, Middle and East Asia, which are advantaged by economies of scale and lower operating expenses than European player like our Versalis, against the backdrop of sluggish economic growth in Europe and a slowdown in demand, which exacerbated the price competition. The Eni’s business was negatively affected by comparatively higher costs of plant utilities indexed to natural gas (for example the cost of natural gas in Europe is several times higher than in USA) and environmental obligations than in other geographies, which made overseas products more competitive than ours, and those trends negatively affected products margins and sales volumes. In 2025, realized margins of commodity plastics fell to their worst level in years.

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Those negative trends are likely to continue affecting business performance in the future. Furthermore, the current disruptions to the streams of products from Middle East due to the ongoing conflict represent a risk to the profitability outlook of Versalis due to possible spikes in feedstock expenses. The Company is executing a comprehensive plan of restructuring and transformation of Versalis, which will leverage Eni’ technologies to establish new product platforms in the segments of transition and circular economy, as well as upgrading chemicals from bio-feedstock and specialties, seeking to reduce exposure to the most commoditized market segments and to achieve a structurally more sustainable and competitive products mix. In the course of 2025, two large, loss-making cracking units, the ones at Brindisi and Priolo, were definitively shut down and works have started to reconvert the two hubs in manufacturing districts for the renewable energies. The improvement in the Group profit and loss and cash flow due to those closures are expected to show off in 2026. The levers of the industrial plan comprise: (i) to complete restructuring and upgrading of the hubs which were shut down in 2025 and to restructure other loss-making plants aiming at reducing the exposure towards the most commoditized segments of the industry; (ii) to develop the segment of bioplastics and biochemicals leveraging the integration of the recently-acquired Novamont and by ensuring the supply of competitive and flexible feedstock; (ii) to increase the weight of differentiated products called “specialties” which, based on our experience, are more profitable than commodity plastics, also leveraging on growing our market share in the compounding and specialized formulations through Finproject that we acquired in 2021, (iv) to develop the business of the circular economy by increasing production of polymers made from the mechanical recycling of waste plastics or through the expected scale-up of a technology for producing polymers via the chemical recycling of waste plastics, currently in a pilot phase; (v) to reduce fixed costs and to further rationalize capital expenditures. Based on those actions, the management expects Versalis to recover profitability by the end of the plan period.

Expected Group financial performance

For 2026, we expect net cash provided by operating activities (“operating cash flow”) and cash from divesting activities to be the main sources of cash to fund our capital plans, returns to shareholders and other commitments. Our operating cash flow is mainly driven by our E&P business due to its relatively larger size and higher profitability compared to our other businesses. Therefore, our operating cash flow is exposed to the volatility of hydrocarbons prices, that are highly correlated to the macroeconomic cycle, the global balance between demands and supplies and the worldwide levels of inventories, among others. Based on our experience, those backdrop conditions can vary very rapidly. Furthermore, due to physical characteristics of reservoirs and fields, oil supplies have a little degree of flexibility in the short term to respond to eventual swings in demand, which can be swift and significant. Accordingly, hydrocarbons prices corrections can be sudden and severe. Due to those considerations, our operating cash flow features high variability and little predictability.

The 2026 outlook is compounded by many risks and uncertainties in connection with the uneven pace of recovery in the global economy, considering an ongoing slow pace in the Chinese economy which is the second largest consumer of crude oil in the world, stagnant activity in the Eurozone, the impacts of trade disputes on international commerce, the willingness of the OPEC+ cartel to stick with its current plans of gradually tapering the production cuts and the level of compliance of cartel members with quotas, the monetary policy of the US Federal Reserve, and finally the evolution of the conflict between Russia and Ukraine and other geopolitical risk factors, particularly the escalating tensions in the Middle East which culminated in acts of war involving USA, Israel and Iran, and Iranian retaliatory attacks in the Gulf area and Israel with possible risks of enlargement of the conflict. Any negative development in the macroeconomic context could negatively affect demand for crude oil and the price of the barrel.

From an industrial standpoint the greatest uncertainties will involve the ability of US shale producers to continue growing production despite financial discipline and reports from market sources that shale growth may have plateaued. Another factor will be the evolving situation in Venezuela and the Country’s ability to revive its ailing oil sector with the support of international oil companies, which could add more supplies to an already oversupplied market. Considering those risks and uncertainties, we have retained flat Brent price assumptions, and we are forecasting a crude oil price at 70 $/bbl for 2026. As disclosed in Item 3, our results of operations and cash flow are subject to trends in crude oil prices and, to a lesser extent, prices of natural gas and products. We estimate that each one-dollar change in the price of the Brent crude oil from our planning assumption impacts our cash flow from operation by around €110 million. This sensitivity applies for a given range of variation in the price of crude oil. We are assuming spot prices of natural gas at European hubs to be around 12 $/mmBTU, flat compared to 2025, and the Company’s gouge of the refining trading environment, SERM at 6 $/bbl, lower than in 2025. The average EUR vs USD exchange rate is assumed at 1EUR=1.15 USD. We are estimating our cash flow from operations to vary by about €80 million for each one-dollar change in the spot prices of natural gas in Europe, while we are estimating our cash flow from operations to vary by about €90 million for each one-dollar change in the SERM. The Group’s results and cash flow are also exposed to trends in the exchange rate of the EUR vs the USD; currently, we are estimating our cash flow from operating activities to vary by about €390 million for a 5 USD/cent movement in the EUR/USD cross rate.

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Against the volatility of our operating cash flows, our funding requirements for developing hydrocarbons reserves are characterized by a low degree of flexibility. The E&P segment is a capital-intensive business and needs large amounts of financial resources to support production volumes and to develop new oil&gas reservoirs. Hydrocarbons development projects are long lead-times projects due to the complexity of activities to be carried out before production is achieved, hence the payback of capital projects usually begins in a very distant future, leaving the Company exposed both financially and to price volatility during the execution phase. Once a final investment decision has been made to develop a new hydrocarbon field and contracts have been signed to build production facilities, platforms, vessels, FPSO units and other equipment, management may face difficulties at postponing or stopping cash outlays in response to a sudden contraction in operating cash flows. Management can reduce incremental investments at producing fields, like workover or infilling operations, when economic and operating conditions allow for that. The Company is executing an important growth plan and in case the scenario for crude oil and gas prices evolves adversely, the Company may experience a cash flow shortfall leading to inability to fund its capital commitments and the dividend by internally generated funds. In such a situation, the Company could be forced to take on new debt or to draw its liquidity reserves and that could negatively affect the Company’s results of operations, returns, and put at risk its targets of financial structure. We plan to make an amount of capital expenditures of around €7 billion in 2026, driven by new project start-ups and ramp-ups in E&P, cost inflation, by development of the renewable generation capacity of our subsidiary Plenitude, the manufacturing capacity of biofuels, and the restructuring of the chemicals business and refineries. The business of renewable generation is currently absorbing cash because it is in a ramp-up phase.

Furthermore, we expect to fund a significant portion of the planned cash requirements in 2026 through the execution of an asset disposal plan which will encompass a possible dilution of our working interest in E&P assets (for example large discovery areas or fields currently in production phase) and other disposals. Those proceeds are included in our 2026 financial plan. Furthermore, as announced in March 2026, the management has commenced a reorganization of the shareholding structure of Eni’s subsidiary Plenitude, which is involving the current noncontrolling shareholders of the entity Ares fund and Energy Infrastructure Partners. The aim is to establish a new governance framework based on joint control between Eni and Ares, which will result in the derecognition of Plenitude from Eni's financial statements, with a significant improvement to Eni’s financial position. Completion of this deal has been assumed in Eni’s financial plans for 2026.

Execution of this disposal plan is exposed to risks in connection with an uncertain macro-outlook and the announcement of asset disposal plans by several companies competing with Eni, which could reduce transaction values.

Management is retaining a prudent financial framework, based on capital and cost discipline, selective investment criteria, pre-set cash allocation priorities and retention of a maximum limit of ratio of indebtedness. New capital projects are approved when they fit strict economic criteria, including being profitable in a low-price environment and having short pay-back periods and reduced time-to-market to limit financial exposure. By applying those criteria, we aim to increase projects’ resilience to possible risks relating to price volatility and, in the long-term, to the energy transition.

One of the pillars of our financial discipline is our internal requirement of self-financing the planned capital expenditures through operating cash flows, leaving a surplus to fund other cash requirements, first the dividend and financial obligations at maturity. For 2026 under our pricing, exchange and inflation rates assumptions, we expect to generate enough cash flow from operations to fund the planned capital expenditures of about €7 billion, leaving a surplus. That surplus and the expected proceeds from our disposal plan will be deployed to fund other Company’s cash commitments, which will mainly comprise cash returns to shareholders, disbursements in connection with pending acquisitions and the repayment of lease liabilities and other commitments, among which dividends to noncontrolling interests, retaining a preset ratio of net borrowings to total sources of funds “gearing” which is expected to remain within the range set by the management at 0.1-0.15.

For further information see Item 3 – Risk factors and notes to the consolidated financial statements.

This financial framework is completed by the maintenance of a liquidity reserve consisting of cash on hand, marketable securities and committed credit lines, which have been dimensioned to help the Company withstand a sudden contraction in operating cash flows, a spike in the volatility of commodity prices leading to increased margining obligations in connection with our derivatives transactions, or short-term difficulties in accessing capital markets. At the end of 2025 this liquidity reserve amounted to €18.8 billion of cash on hand and held-for-trading securities and other financing receivables and €9 billion of committed borrowings facilities.

The actions planned in the next five-year period featuring profitable hydrocarbons production growth, an increasing contribution of our transition businesses managed by Plenitude and Enilive due to a planned expansion of renewable capacity, biofuels manufacturing capacity additions, continuing gas and LNG portfolio optimizations in GGP, and expected progress in the restructuring of downstream oil businesses coupled with capital and cost discipline will underpin a solid cash generation. On those bases, and considering the proceeds expected from the execution of our disposal plan, we expect to be in a position to ensure competitive shareholders returns and to retain a robust balance sheet with our core ratio of net borrowings to total equity plus net borrowings (both before IFRS 16 lease liabilities) – gearing – expected to remain within a planned range of 0.1-0.15 across the plan period.

In the next five-year plan 2026-2030, we expect to incur about €29 billion of capital expenditures, of which a major part is planned to be directed to the exploration and development of hydrocarbons reserves.

To support the Group cash generation, we are planning to execute a cost saving program of about €2.3 billion in the period 2024-2027, which was raised from a previous €1.8 billion target.

Due to cash flow unpredictability as a function of the scenario volatility, management is always allocating a portion of funds to uncommitted projects, which can be more comfortably cancelled or postponed in case of a downturn in oil prices. In the five-year plan 2026-2030 out of the planned capital budget of €29 billion, the portion allocated to uncommitted projects represents on average more than 30% of expenditures in each year of the financial projections.

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Our financial projections and capital investment decisions are based on management’s appreciation of the cost of capital to the Group at about 6% post-tax. This rate is in line with 2024 because a perceived reduction in the volatility of Eni’s share and a reduced market risk premium were offset by higher expected interest rates on debt. When making final investment decisions, the thresholds against which specific investment internal rate of returns are benchmarked are defined by adding to the above-mentioned cost of capital, a risk premium associated with the country where the investment will be executed and an additional business risk premium to cover high-risk investments (like exploration projects) and to provide an extra return.

This financial outlook is subject to the volatility of crude oil prices and to the other risk factors described in Item 3.

Remuneration policy

Management is committed to delivering on a progressive and competitive shareholder remuneration policy, that is reflective of the expected improvement in underlying earnings and cash flows on a constant scenario basis and of the increased resiliency of the business to cyclical fluctuations. In setting the level of shareholders’ remuneration, management is also considering its assumptions about future trends in crude oil prices and in other market variables.

As part of that framework, the management is planning to return shareholders an amount of cash representing a portion in a range of 35 to 45% of the expected cash flow from operations before working capital requirements “adjusted cash flow”. That portion is higher than the previous range of 35-40% to take into account a perceived solid financial structure of the Company, lower expected expenditures than in the past and a growing contribution of dividends from equity-accounted entities to the cash flow. In 2025, the management gauged this adjusted cash flow measure at around €12.5 billion and cash returns to shareholders came in close to the upper limit of that range as we returned €5 billion of cash to shareholders comprising the 2025 dividend of €1.05 per share (equal to €3.15 billion, with the third and fourth instalments to be distributed in the first half 2026) and the 2025 buy-back program of €1.8 billion, which was completed in February 2026.

Going forward, distributions will continue contemplating a combination of dividends and share repurchases. We expect to gradually increase the dividend in future years in line with the expected improvement in the Group underlying financial performance, and to enhance the dividend resilience to the scenario. Share repurchases will complement the dividend and are intended as a flexible tool to distribute raising amount of cash generated by the business in case of upside in the scenario variables, a better than budgeted company’s performance or other factors. For the full year 2026, we expect to distribute shareholders an amount equal to 40% of the adjusted cash flow which will be earned by the Company under the assumption of 70 $/bbl of Brent crude oil (nominal terms) through dividends and share repurchases.

According to our financial framework, in case the Group results of operations are trending higher than management’s plans due to a better pricing environment than management expectations (i.e. a Brent crude oil price higher than 70 $/bbl) and/or an improved business underlying performance, management intends to distribute up to 60% of the incremental cash flows through share repurchases (in line with the past), until management’s expected Brent crude oil price for the full year reaches 90 $/bbl on average. In case management’s forecast of the Brent crude oil price exceeds 90 $/bbl for 2026 full year, the Company intends to distribute shareholders 100% of the incremental adjusted cash flow at a Brent price higher than 90 $/bbl and/or other scenario variables 50% above planned levels (namely spot natural gas prices and refining margins) as extraordinary dividend.

In case the commodity scenario underperforms management’s expectations, the Company plans to leverage on its financial flexibility as well as on possible revisions of the capital expenditure plans considering the proportion of uncommitted projects in our development portfolio, to preserve shareholders’ returns.

For 2026, having assessed the progress of the Company in executing its strategy, based on a sound financial position and management scenario assumptions, management is planning to increase the yearly dividend to €1.1 per share, up 4.8% from 2025. This dividend is expected to be paid in four equal quarterly instalments in September 2026, November 2026, March 2027, and May 2027. Therefore, the expected cash out for dividend payments in 2026 will include two instalments of the 2025 dividend of €0.26 per share each, and two instalments of the planned 2026 dividend of €0.27 per share each.

Consistently with its remuneration policy, for 2026 Eni plans to execute a share buyback program of at least €1.5 billion assuming a Brent scenario of 70 $/bbl and that the Company delivers its planned adjusted cash flow for the year. Execution of this buyback program is subject to shareholders’ approval at the Annual General Meeting scheduled for May 2026. In case of a better oil price environment and/or better business underlying performance, the buyback is expected to be increased to an upper limit of €4 billion.

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Off-balance sheet arrangements

Eni has entered into certain off-balance sheet arrangements, including several guarantees and commitments, as described in “Item 18 – Note 28 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements”. Eni’s principal contractual obligations, including commitments undertake-or-pay or ship-or-pay contracts in the gas business, are disclosed under “Contractual obligations” in the same footnote. See the Glossary for a definition of take-or-pay or ship-or-pay clauses. Those off-balnce sheet agreements also comprise various forms of guarantees provided by Eni on behalf of unconsolidated subsidiaries and affiliated companies, mainly relating to guarantees for loans, lines of credit and performance under contracts.

Off-balance sheet arrangements comprise those arrangements that may potentially impact Eni’s liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of Eni’s business purposes, Eni is not dependent on these arrangements to maintain its liquidity and capital resources; nor is management aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on the Company’s financial condition, results of operations, liquidity or capital resources.

Liquidity risk

Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace as to be unable to meet short-term financing requirements and to settle obligations. Such a situation would negatively impact the Group results and cash flow as it would result in the Company incurring higher borrowing expenses to meet its obligations, divesting assets at discount to their fair values or under the worst of conditions the inability of the Company to continue as a going concern. At present, the Group believes it has access to sufficient funding and has also both committed and uncommitted borrowing facilities as we retain cash reserves and cash on hand to meet currently foreseeable funding requirements. The Group cash reserve consists of cash on hand and very liquid financial assets (short-term deposits, held-for-trading securities and other financial assets) of €18.8 billion and committed borrowing facilities of €9 billion. This liquidity reserve based on our financial framework can alternatively be used to absorb temporary swings in cash flows from operations, to provide financial flexibility to pursue the Group development programs or to fund the Group contractual obligations with respect to the repayment of financing debt at maturity up to a 48-month horizon. For a description of how the Company manages the liquidity risk see “Item 18 – Note 28 to the Consolidated Financial Statements”. Due to the continued volatility in commodity markets, we might incur increased liquidity risks due to the need to deposit larger amounts of cash collateral at financial institutions and commodity-based exchanges to guarantee the settlement of derivatives contracts (margin calls). The Group is continuously assessing the ability of its financial headroom to cope with possible market turbulence and volatility. To withstand uncertain financial markets and macroeconomic conditions, the Group has retained a level of financial flexibility in planning future capital requirements to grow the business, as a portion of the capital expenditure plan of €29 billion of the five-year period 2026-2030 is allocated to uncommitted projects (more than 30% on average in the plan).

W o r king capital

Management believes that, considering unutilized credit facilities, the Company’s liquidity reserves, our credit rating and access to capital markets, Eni has sufficient working capital for its foreseeable requirements.

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C r edit risk

Credit risk is the risk that our commercial or financial partners fail to pay amounts due to us in connection with the provision of goods and services, financing or derivatives transactions. In recent years, the Group has experienced a significant level of counterparty default due to Europe and Italy’s weak economic growth and financial difficulties affecting national oil state-owned entities and local companies, which are joint operators in Eni-lead projects. It is possible that the ability of our debtors to pay amounts due to us will deteriorate in the next future, in case of a deepening of the current economic slowdown, leading us to recognize significant amounts of expected credit losses in future reporting periods.

For a description of how the Company manages the credit risk see “Item 18 – Note 28 to the Consolidated Financial Statements”. For more information about the allowance for doubtful accounts calculated in accordance with the expected credit loss model see “Item 18 – Note 8 to the Consolidated Financial Statements”.

Volatility of the macro environment

Global financial markets are volatile due to several macroeconomic risk factors and unpredictable developments. In case of unpredictable developments in the Russia military aggression against Ukraine or in the Middle-East tensions, intensification of trade disputes between the USA and its main trading partners, or a financial crisis triggering a downturn in economic activity and energy demand, in the event of a credit crunch, or if Eni is unable to access the financial markets (including cases where this is due to Eni’s financial position or market sentiment as to Eni’s prospects) at a time when cash flows from Eni’s business operations may be under pressure, the Company may incur significantly higher borrowing costs than in the past or difficulties obtaining the necessary financial resources to fund Eni’s development plans, therefore jeopardizing Eni’s ability to maintain long-term investment programs. A reduction in the investments needed to develop Eni’s reserves and to grow the business may significantly and negatively affect Eni’s business prospects, results of operations and cash flows, and may impact shareholder returns, including dividends and share price appreciation. The retention of cash reserves and borrowing facilities and the financial flexibility in the expenditure program are tools that Eni may activate in case of unfavorable macro developments and systemic crises.

Ma r k et risk

The fair values of Eni’s financial assets and liabilities as well as expected cash flow from highly probable transactions are exposed to movements in commodity prices, currency fluctuations and changes in interest rates. Unfavorable movements in prices and rates could significantly and negatively affect Eni’s results of operations and cash flow.

The Group does not hedge its strategic exposure to volatile hydrocarbons prices in the activity of producing its oil&gas reserves, except for specific transactions or particular market circumstances. Other strategic, unhedged exposures include long-term gas supply contracts for the portion not balanced by sales contracts (already stipulated or expected), the margin deriving from the chemical transformation process, the refining margin and long-term storage functional to the logistic-industrial activities. The Group enters into commodity derivatives to manage exposure to price volatility in commercial activities involving the reselling of commodities in view of optimizing margins. Frequently, exposures to price volatility or to different indexation between the cost of supplies and the reselling prices are not hedged on a transaction-by-transaction basis; instead, exposures are pooled at Group level and derivatives are activated to hedge net exposures, with gain and losses recognized through profit.

Eni’s euro-denominated subsidiaries incur revenues and expenses in currencies other than the euro or are otherwise exposed to currency fluctuations because prices of oil, natural gas and refined products generally are denominated in, or linked to, the U.S. dollar, while a significant portion of Eni’s expenses are incurred in euros and because movements in exchange rates may negatively affect the fair value of assets and liabilities denominated in currencies other than the euro. Therefore, movements in the U.S. dollar (or other foreign currencies) exchange rate versus the euro affect results of operations and cash flows and year-on-year comparability of the performance. These exposures are normally pooled at Group level and net exposures to exchange rate volatility are netted on the marketplace using derivative transactions. However, the effectiveness of such hedging activity is uncertain, and the Company may incur losses also of significant amounts.

Eni is exposed to fluctuations in interest rates that may affect the fair value of Eni’s financial assets and liabilities as well as the amount of finance expense recorded through profit. Eni enters into derivative transactions with the purpose of minimizing its exposure to the interest rate risk.

For a description of how the Company manages the Market risk see “Item 18 – Note 28 of the Notes on Consolidated Financial Statements”.

R esea r ch and de ve lopment

For a description of Eni’s research and development operations in 2025, see “Item 4 – Research and development”.

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Item 6. DIREC T OR S, SENIOR MA N A GEMENT AND EMP L O YEES

Di r ectors and Senior Management

The following table lists the Company’s Board of Directors as at December 31, 2025:

Name |  | Position |  | Year elected or appointed |  | Age
Giuseppe Zafarana |  | Chairman |  | 2023 |  | 62
Claudio Descalzi |  | CEO |  | 2014 |  | 70
Elisa Baroncini |  | Director |  | 2023 |  | 59
Massimo Belcredi |  | Director |  | 2023 |  | 64
Roberto Ciciani |  | Director |  | 2023 |  | 53
Carolyn Adele Dittmeier |  | Director |  | 2023 |  | 69
Federica Seganti |  | Director |  | 2023 |  | 59
Cristina Sgubin |  | Director |  | 2023 |  | 45
Raphael Louis L. Vermeir |  | Director |  | 2020 |  | 70

In accordance with Article 17.1 of Eni’s By-laws, the Board of Directors is made up of 3 to 9 members.

The current Board of Directors was appointed by the ordinary Shareholders’ Meeting held on May 10, 2023 which also established the number of Directors at nine for a term of three financial years. The Board’s term will therefore expire with the Shareholders’ Meeting called to approve the financial statements for the year ending December 31, 2025.

The Board of Directors is appointed by means of a slate voting system: slates may be presented by the shareholders representing at least 0.5% of the Company’s share capital. According to the Eni By-laws, three out of nine Directors are appointed from among the candidates of the non-controlling shareholders.

Giuseppe Zafarana, Claudio Descalzi, Elisa Baroncini, Roberto Ciciani, Federica Seganti, and Cristina Sgubin were the candidates of the Ministry of the Economy and Finance. Massimo Belcredi, Carolyn Adele Dittmeier and Raphael Louis L. Vermeir were the candidates of institutional investors (non-controlling shareholders). The Shareholders’ Meeting appointed Giuseppe Zafarana as the Chairman of the Board of Directors and, on May 11, 2023, the Board appointed Claudio Descalzi as the Chief Executive Officer of the Company.

Four Directors out of nine were drawn from the less represented gender, reaching the ratio of at least two-fifths of the Directors as provided by Italian law and Eni’s By-laws.

The following provides details on the personal and professional profiles of the Directors.

Giuseppe Zafarana was born in Piacenza in 1963 and has been Chairman of the Board of Directors of Eni since May 2023. He is a member of the Italian Corporate Governance Committee. Furthermore, he is Chairman of the Board of Directors of Fondazione Eni Enrico Mattei (FEEM) since June 28, 2023 and, since June 13, 2024, Chairman of the Board of Directors of Finint Investments, an asset management company belonging to the Banca Finint Group.

He graduated in Law, Political Sciences and Economic and Financial Security Sciences and obtained a II level Master's Degree in Corporate Tax Law from Luigi Bocconi University in Milan.

Experience

His military career began in 1981, when he attended the 81st "Osum II" course at the Corps Academy. He went into service in 1985 and held several operational assignments in Lombardy, Veneto, Lazio, Calabria and Sicily, commanding various divisions, taking on assignments in the leading investigative departments of the Corps and carrying out relevant Military staff functions. From 1995 to 1997, he attended the biennial Advanced Tax Police Course and a highly qualified stage in the United States of America, on the subject of contrasting organised crime. He was Provincial Commander of Rome (from 2003 to 2008) and Regional Commander of Lombardy (from 2015 to 2016).

Moreover, he performed several assignments in the training sector, in particular as commander of the Academy of the Guardia di Finanza, and later served as Chief of Staff of the General Command of the Guardia di Finanza (from 2016 to 2018), and interregional commander for Central Italy (from 2018 to 2019). From May 2019 to May 2023 he held the office of Commander General of the Guardia di Finanza. He taught at the Academy of the Guardia di Finanza, the School of the Tributary Police of the Guardia di Finanza, and the School of the economic-financial Police of the Guardia di Finanza. He has been awarded various decorations and honours, including the Knight Grand Cross of the Order of Merit of the Italian Republic.

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Claudio Descalzi was born in Milan and has been Eni’s CEO since May 2014. He is a member of the General Council and of the Advisory Board of Confindustria and Director of Fondazione Teatro alla Scala.

He is a member of the National Petroleum Council. He is one of the founding CEOs of the Oil and Gas Climate Initiative, and was awarded the Atlantic Council’s Distinguished Business Leadership Award in 2022.

Experience

He joined Eni in 1981 as Oil & Gas field petroleum engineer and then became project manager for the development of North Sea, Libya, Nigeria and Congo. In 1990 he was appointed Head of Reservoir and operating activities for Italy. In 1994, he was appointed Managing Director of Eni’s subsidiary in Congo and in 1998 he became Vice President & Managing Director of Naoc, a subsidiary of Eni in Nigeria. From 2000 to 2001 he held the position of Executive Vice President for Africa, Middle East and China. From 2002 to 2005 he was Executive Vice President for Italy, Africa, Middle East, covering also the role of member of the board of several Eni subsidiaries in the area. In 2005, he was appointed Deputy Chief Operating Officer of the Exploration & Production Division in Eni. From 2006 to 2014 he was President of Assomineraria and from 2008 to 2014 he was Chief Operating Officer in the Exploration & Production Division of Eni. From 2010 to 2014 he held the position of Chairman of Eni UK.

In 2012, Claudio Descalzi was the first European in the field of Oil&Gas to receive the prestigious “Charles F. Rand Memorial Gold Medal 2012” award from the Society of Petroleum Engineers and the American Institute of Mining Engineers. He is a Visiting Fellow at The University of Oxford. In 2014 he founded the Oil and Gas Climate Initiative together with other CEOs of major Oil & Gas companies to lead the industry’s response to climate change. In December 2015 he was made a member of the “Global Board of Advisors of the Council on Foreign Relations”. In December 2016 he was awarded an Honorary Degree in Environmental and Territorial Engineering by the Faculty of Engineering of the University of Rome, Tor Vergata. In May 2022 he was awarded by the Atlantic Council with the Distinguished Business Leadership Award for the extraordinary role he has played in the energy sector at an international level, for the technological transformation of the company aimed at complete decarbonisation by 2050 and for his contribution to the new challenge of Italian and European energy security. He graduated in physics in 1979 from the University of Milan.

Elisa Baroncini was born in Castel San Pietro Terme (Bologna) in 1966 and has been Eni Director since May 2023. She is Professor of International Law at the Alma Mater Studiorum – University of Bologna, where she teaches International Trade and Investment Law, The International Law on Sustainable Development, International Energy Law and she is a member of the teaching board of the PhD program in Juridical Sciences. Founder and Coordinator of DIEcon, the interest group on International Economic Law of the Italian Society of International Law (SIDI), she co-chaired the interest group on International Economic Law of the European Society of International Law (ESIL) in 2012-2022 and since December 2023 she was appointed as a Member of the Executive Council of Society of International Economic Law (SIEL). She is a member of the Journal of World Investment and Trade and of the review Diritto del commercio internazionale – Bologna Editorial Board.

In December 2024 she was renewed for the 2025-2028 triennium by the University of Bologna as a member of the Scientific Council of the Alma Mater Institute for Advanced Studies and was appointed "TSD Expert" (international arbitrator) by the European Commission for dispute resolution mechanisms of the European Union new generation free trade agreements. She is also a member of the "Interuniversity Centre on the Law of International Economic Organisations" (CIDOIE), as well as a member of the “Associazione delle docenti universitarie dell’Università di Bologna” (AdDU)” Scientific Committee. She participates in various associations and organizations active in the fields of governance and international and European law (Leuven Centre for Global Governance Studies, Society of International Economic Law, Società italiana di diritto internazionale, International Law Association (ILA) – Branch of Italy, Associazione italiana studiosi di diritto dell’Unione europea).

Experience

She is the author of several publications among Italian and foreign publishers and magazines, particularly in the field of international economic law and the external relations and trade policy of the European Union. She has been a Visiting Professor at various foreign universities and Visiting Researcher at the European University Institute (EUI), and member and manager of national and international research projects. After being appointed as Coordinator of the Re-Globe Jean Monnet Module (2022-2025), of the Seed Funding Una Europa WHC@50 project and of the Seed Funding Una Europa ImprovEUorGlobe project, she is currently Scientific Director of the project "The World Trade Organization as a protagonist of sustainable development in the relaunch of the multilateral system", funded by the Ministry of Foreign Affairs and International Cooperation. Additionally, Elisa Baroncini holds the Jean Monnet Chair with the SustainEUorPlanet project and is a member of the Scientific Committee of the Advanced Training Course on Energy Law at the University of Bologna. Elisa Baroncini's fields of research include: the crisis of the WTO appellate body and the multilateral system reform process; the relationship between trade liberalisation and non-trade values; the new generation of free trade agreements of the European Union; transparency in international economic law; the role of the European Parliament and Commission in finalizing international agreements; UNESCO and international economic law; exceptions related to national security in international economic law; EU trade policy and Sustainable Development Goals (SDGs) of the UN Agenda 2030; Energy Trilemma and International Energy Law.

She graduated with honour in law, with the “Baldisseri” award as best dissertation of the year in European Community Law, from the University of Bologna, where she also obtained a PhD in European Community Law.

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Massimo Belcredi was born in Brindisi in 1962 and has been Eni Director since May 2023. He is Full Professor of Corporate Finance at the Faculty of Economics of the Università Cattolica del Sacro Cuore in Milan; and Founder and Director of FIN-GOV (Centre for financial research on corporate governance of the Catholic University).

He is a member of the Steering Committee of Cor-Gov (Master II level in Corporate Governance) and of the committee of the Department of Economics and Business Management. He is a member of the Italian Academy of Business Economics (AIDEA) and the Association of Professors of Economics of Financial Market Intermediaries (ADEIMF). He is also a member of the Rivista Bancaria (Minerva Bancaria) Scientific Committee. Since 2021 he has been Director of Armònia SGR and a member of the Nedcommunity Scientific Committee. He provides technical consultancy and advice on the subjects of corporate finance and corporate governance, support for the board evaluation, remuneration policies, and related-parties transactions.

Experience

He has been a member of the Board of Directors, European Financial Management Association and of the Editorial Board, Journal of Management Governance. He is author of several national and international publications, primarily in the field of corporate governance, directors' remuneration, economic analysis of listed companies law, business crises, and has worked as a consultant for Assonime on corporate governance, company law and crisis and regulation of financial markets matters, also participating in the working group for the development of the Italian Corporate Governance Code.

Since 2003, he was Director in unlisted and listed companies, as well as companies under the supervision of Public Authorities (Arca SGR, Banca Italease, BPER Banca, Erg, Gedi and Pirelli Tyre), being also appointed as a member or chairman of internal committees (Nomination, Remuneration, Control and Risk, Related Parties). He was a member of the Advisory Board for the transformation and privatisation of municipal companies in the Municipality of Rome, and a member of the competition commissions for Consob and the Energy and Gas Authority (AEEG). In 2014 he received the "Ambrogio Lorenzetti" award for corporate governance, category ‘Board of Director’s’. He was Professor at the University of Svizzera Italiana and the University of Bologna. He graduated in Business and Economics from the Università Cattolica del Sacro Cuore in Milan, where he also held the role of researcher and associate professor of Corporate Finance.

Roberto Ciciani was born in Rome in 1972 and has been Eni Director since May 2023. He is a lawyer, currently General Manager and Director of Directorate I of the Economy Department at the Ministry of Economy and Finance.

He is a Director and member of the Remuneration Committee of TELT – Lyon-Turin Euroalpine Tunnel.

Experience

He began his career at Studio Legale Compagno. He then took part to the final stage of the 2nd management training course-competition and took on the role of lawyer at the Tiber River Basin Authority, a public body responsible for landscape protection (from 2001 to 2002). Since 2002 he has held managerial positions in several Directorates of the Treasury and Economy Department - Ministry of Economy and Finance. He was a member of the Higher Council of the Sicily Foundation (from 2016 to 2019), a Director of Poste Tutela SpA, a company owned by Poste Italiane Group (from 2013 to 2016), and MEFOP SpA, a majority state-owned company for the development of pension funds (from 2013 to 2019).

He has extensive, meaningful experience in the economic-financial sector, both at international and european level, in administrative, accounting and management procedures; he has considerable knowledge of risk monitoring and management, and has developed skills in the analysis of problems relating to international and domestic law and economics, banking, finance, business, the prevention of tax and financial crimes and market abuse, primarily gained through pre-legislative work at national, European and international level (definition of standards and international recommendations). He was Professor at the Sapienza, Tor Vergata and LUISS Guido Carli universities in Rome. He graduated in law from the Sapienza University of Rome, where he also held a PhD in Administrative Law.

Carolyn Adele Dittmeier was born in Salem (USA) in 1956 and has been Eni Director since May 2023. She is currently Independent Director and member of the Audit and Risk Committees of HSBC Uk Bank Plc.

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She is also independent director and Chairman of the Control and Risk Committee of Illycaffé S.p.A. and a member of the Board of Statutory Auditors of Moncler SpA and of the Bologna University Business School Foundation. She has taken part to the European Growth Audit Network (coordinated by Tapestry), which organizes benchmark meetings between the Audit Committee Chairs of major European companies, with a focus on “high growth” companies. She is a certified internal auditor and certified risk management assurance professional. She was promoter, and still plays a leading role, in the working group for risks and controls within Nedcommunity.

Experience

She began her career at KPMG in 1978, as an auditor at Philadelphia, Pennsylvania, USA, later launching a corporate governance services practice in Italy. She held the position of Financial Manager and, subsequently, Internal Audit Manager for the Montedison/Compart Group. From 2002 to 2014 she served as Internal Audit Manager of the Poste Italiane Group, and of the Supervisory Body, as sole auditor. From 2017 until September 2024, she served as an Independent Director, as well as the President of the Audit Committee and a member of the Corporate Governance, Sustainability, and Nomination Committee of Alpha Services & Holdings SA and its subsidiary Alpha Bank SA, where she also held the position of Lead Director on ESG issues.

From 2012 to 2015 she was a member of the Audit Committee of the FAO (United Nations Food and Agriculture Organisation), where she became President in 2014. She was also an independent director and chairman of the Control and Risk Committee at Autogrill SpA and Italmobiliare SpA. From 2014 to April 2023, she was Chairman of the Board of Statutory Auditors of Assicurazioni Generali SpA. From 2016 to the end of 2023, she was senior advisor of Ferrero International SA as a member of Audit Committee.

From 2004 to 2014, she held various positions at the Institute of Internal Auditors (IIA), including those of president of ECIIA and AIIA. She is author of publications on risk governance and Internal Auditing and, in 2014 and 2017 respectively, she received the Ambrogio Lorenzetti Award, Board Members category, and the Minerva (Federmanager) Women of Excellence award. She works periodically at LUISS Guido Carli University, lecturing on corporate governance, risk management, internal control and internal auditing. She graduated in Economics from the Wharton School, University of Pennsylvania, USA.

Federica Seganti was born in Trieste in 1966 and has been Eni Director since May 2023. She is currently Chairman and Chief Executive Officer of the Friuli Venezia Giulia regional finance company Friulia SpA as well as Director of Nexi SpA and Revo Insurance SpA.

She is Professor of Finance, Core Faculty at the MIB Trieste School of Management, and of Insurance Operations Technique at the Department of Economics and Statistics at the University of Udine. She is Director of the Master’s course in Insurance & Risk Management and the Corporate Master’s course in Risk Management and Finance at the MIB Trieste School of Management.

Experience

From 1994 to 2022 she was Director in several listed and unlisted companies (Fincantieri SpA, Eurizon Capital SGR, Autostrada Pedemontana Lombarda SpA, InRete SpA, Autovie Servizi SpA, Autovie Venete SpA), while also being appointed as a member or Chairman of advisory committees (Nomination, Remuneration, Control and Risks). From 2003 to 2008 she was Commissioner at Covip - Supervisory Commission on Pension Funds, from 2010 to 2016 a Member of the Occupational Pensions Stakeholder Group of EIOPA - European Insurance and Occupational Pensions Authority, and from 2017 to 2019 of the Strategy Advisory Board of EY Financial Services. From 2017 to April 2023, she was an independent Director of Hera SpA, where she was also Chairman of the Ethics and Sustainability Committee. From 2022 to 2025 she was Chairman of BTX Italian Retail and Brands Srl and a Director of BancoPosta Fondi SpA SGR (where she was Chairman of the Remuneration Committee and member of the Risk Committee).

She was a contract professor of Transport Economics at the University of Trieste. She is the author of many publications and has been awarded three prizes. She has a degree in Political Science from the University of Trieste, and a PhD in Finance from the School of Finance (University of Trieste, Udine, Florence and Bocconi Milan), as well as an MBA in International Business from the MIB Trieste School of Management.

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Cristina Sgubin was born in Frosinone in 1980 and has been Eni Director since May 2023. Lawyer, expert in corporate law, corporate governance and regulation. She is currently Director of SACE, ISPRA (Higher Institute for Environmental Protection and Research), Vianini SpA, Biesse SpA and Xenia SpA.

She is also Secretary General of Telespazio SpA, a leading international company operating in the satellite sector. She lectures on both degree and master's courses in Public Economic Law and Administrative Law.

Experience

She gained extensive experience as a lawyer for leading national and international law firms, then she pursued the in-house managerial career. As a lawyer, she has served the IPI (Institute of Industrial Promotion), in-house company of the Ministry of the Economic Development (“MISE”, now Ministry of Enterprises and Made in Italy) for Promuovitalia S.p.A. and for the Ministry itself. She was General Counsel of Italo-Nuovo Trasporto Viaggiatori SpA. While working at Leonardo she subsequently became Head of Regulatory Affairs, and then Chief of Staff to the Chief Executive Officer. Since 2021 she has been Secretary General of Telespazio, responsible for legal and corporate affairs, compliance, security and anti-corruption.

She is author of monographs, particularly on complex industrial crises, collective works and scientific articles. She had a law degree from the University of Rome Tor Vergata and a level II University Master's degree in "Law and management of public services" from the LUMSA University in Rome.

Raphael Louis L. Vermeir was born in Merchtem (Belgium) in 1955 and has been Eni Director since May 2020. Since April 2021 he has been Lead Independent Director, appointment confirmed in May 2023. He is currently an independent advisor for the mining and oil industry.

He serves as Trustee of the Classical Opera Company in London, as well as Chairman of Malteser International and board member of Sedibelo Resources Limited. He is Fellow of the Energy Institute and the Royal Institute of Naval Architects.

Experience

He joined ConocoPhillips in 1979, initially working in marine transportation and production engineering services in Houston, Texas. He then handled upstream acquisitions in Europe and Africa and managed Conoco's exploration activities in continental Europe from the Paris headquarters. In 1991 Vermeir moved to London to lead the business development activities for refining and marketing in Europe. In 1996 he became managing director of Turcas in Istanbul (Turkey). He returned to London in 1999 to lead strategic initiatives in Russia and to complete major acquisition deals in the North Sea. He also headed an integration team during the Conoco-Phillips merger. In 2007 he became head of external affairs Europe and in 2011 was appointed as president of operations in Nigeria. Subsequently and until 2015, Vermeir was Vice President of Government Affairs International for ConocoPhillips.

Raphael Vermeir was a member of the Board of Directors of Oil Spill Response Ltd and until 2011 was Chairman of the International Association of Oil and Gas Producers for four years in a row. Since 2016 and until April 2021 was Senior Advisor for Energy Intelligence and Strategia Worldwide. From 2016 and until 2021 he was Chairman of IP week. Since 2016 until 2022 he was Senior Advisor for AngloAmerican. From April 2021 Raphael Vermeir has been appointed as Lead Independent Director of Eni. He served as Trustee of St Andrews Prize for the Environment. A Belgian national, he graduated in Electrical and Mechanical Engineering from the Ecole Polytechnique in Brussels. He holds a Masters of Science degrees in engineering and management from the Massachusetts Institute of Technology.

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Senior Mana g ement

The table below sets forth the composition of Eni’s Senior Management as at December 31, 2025. It includes the CEO, as General Manager of Eni SpA, as well as the Chief Operating Officers and the executives who report directly to the CEO and to the Board, and on its behalf, to the Chairman.

Name |  | Management position |  | Year first appointed to current position |  | Total number of years of service at Eni |  | Age
Claudio Descalzi |  | Chief Executive Officer of Eni |  | 2014 |  | 44 |  | 70
Guido Brusco |  | Global Natural Resources Chief Operating Officer and General Manager |  | 2022 |  | 28 |  | 55
Francesco Gattei |  | Chief Transition & Financial Officer, Chief Operating Officer and General Manager |  | 2020 |  | 30 |  | 56
Giuseppe Ricci |  | Industrial Transformation Chief Operating Officer |  | 2021 |  | 40 |  | 67
Gianfranco Cariola |  | Internal Audit Director |  | 2021 |  | 14 |  | 57
Grazia Fimiani |  | Integrated Risk Management Director |  | 2021 |  | 29 |  | 55
Luca Franceschini |  | Integrated Compliance Director and Board Secretary and Board Counsel |  | 2016 |  | 34 |  | 59
Claudio Granata |  | Director Stakeholder Relations & Services |  | 2020 |  | 42 |  | 65
Erika Mandraffino |  | External Communication Director |  | 2020 |  | 19 |  | 53
Lapo Pistelli |  | Public Affairs Director |  | 2020 |  | 10 |  | 61
Stefano Speroni |  | Legal Affairs & Commercial Negotiation Director |  | 2020 |  | 7 |  | 63
Roberto Ulissi |  | Corporate Affairs and Governance Director |  | 2006 |  | 19 |  | 63
Lorenzo Fiorillo |  | Technology, R&D & Digital Director |  | 2024 |  | 26 |  | 51

The Global Natural Resources Chief Operating Officer and General Manager, the Chief Transition & Financial Officer, Chief Operating Officer and General Manager, the Industrial Transformation Chief Operating Officer and the Director Stakeholder Relations & Services are members of the Eni Steering Committee, chaired by the Chief Executive Officer. The Eni Steering Committee meets monthly and in any case, as a rule, in view of the meetings of the Board of Directors to examine issues of strategic interest and to be brought to the attention of the Board of Directors itself. Owners of other positions participate in the work of the committee in relation to the topics to be discussed. The Chairman of the Board of Directors is invited to participate in all meetings. The Board Secretary and Counsel participates in the activities of the committee for issues related to the Board of Directors. The Secretarial activities of the Eni Steering Committee are carried out by the Director of Corporate Affairs and Governance.

The Global Natural Resources Chief Operating Officer and General Manager, the Chief Transition & Financial Officer, Chief Operating Officer and General Manager, Industrial Transformation Chief Operating Officer, the Director Legal Affairs and Commercial Negotiations, the Director Corporate Affairs and Governance, the Director Integrated Compliance, the Director External Communication, the Director Stakeholder Relations & Services, the Director Internal Audit, the Director Public Affairs, the Director Integrated Risk Management, the Director Technology, R&D & Digital, the Director CCUS, Forestry & Agro-Feedstock, the Director Development, Operations & Energy Efficiency, the Director Exploration, the Director Global Gas & LNG Portfolio, the Director Power Generation & Marketing, the Director Refining Evolution and Transformation, the Director Upstream, the Director Global Trading, the Head Accounting and Financial Statements, the Head Planning, Control and Insurance are members of the Management Committee 6, which provides advice and support to the Chief Executive Officer. Other managers may be invited to attend meetings based on the agenda. The Chairman of the Board is invited to attend meetings. The duties of the Committee Secretary are performed by the Director Corporate Affairs and Governance.

As of August 1, 2020, the Head of the Accounting and Financial Statements has been appointed by the Board of Directors as the Officer in charge of preparing Company’s financial reports pursuant to Italian law, replacing the CFO, acting upon a proposal of the CEO in agreement with the Chairman, following consultation with the Nomination Committee and with the approval of the Board of Statutory Auditors.

The Internal Audit Director is appointed by the Board of Directors as Director in charge of the internal control and risk management system, acting upon a proposal of the Chairman in agreement with the Chief Executive Officer.

The Board of Directors decides with the support of the Control and Risks Committee and the Nomination Committee, after having heard the Board of Statutory Auditors. The Board Secretary and Board Counsel is appointed by the Board of Directors upon a proposal of the Chairman.

Other members of Eni’s senior management are appointed by Eni’s CEO and may be removed without cause.

6 The committee includes also the Chairman of the Board and CEO's of certain Eni's subsidiaries.

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Senior Mana g e r s

Guido Brusco was Born in Maratea in April 1970, he graduated with Honors in Mechanical Engineering at “La Sapienza” University of Rome. He holds the position of Eni’s Chief Operating Officer Global Natural Resources and General Manager since October 1, 2024. He joined Eni in 1997, starting his career in the technical areas of the Exploration & Production business holding positions of increasing complexity and seniority across different countries, up to the role of Managing Director in Kazakhstan in 2013 and subsequently in Angola in 2015. He held the positions of Executive Vice President for the Sub-Saharan Africa Region and then Director of Eni’s Upstream business. He took over as Chief Operating Officer Natural Resources in February 2022. Since October 2024, he has been appointed Chief Operating Officer Global Natural Resources as well as General Manager1, overseeing exploration activities, engineering, development and production of oil&gas, LNG and Power, Trading and Portfolio management, sustainable development, Carbon Capture and Storage, forestry and agro-feedstock and, lastly, to the realization of asset development projects. He has been appointed Chairman of Confindustria Energia, Italy's Federation of energy sector associations, in July 2023. He has been a Board Director of Vår Energi (since December 2021), of Azule Energy (since August 2020) and of Ithaca Energy (since October 2024).

Francesco Gattei was born in Bologna in February 1969, he graduated in Economy and Commerce with a thesis in the oil market. He holds the position of Chief Transition & Financial Officer, Chief Operating Officer and General Manager since October 1, 2024. He joined Agip S.p.A. in 1995 and participated in major negotiation processes in Central Asia and Russia, firstly as Business Analyst and subsequently as Negotiator. From 2001 to 2005 he was Head of Negotiations & Commercial Planning in Libya activities during the start-up and then the construction phases of the Western Libyan Gas Project. From 2006 to 2008, he returned to Eni’s headquarters to become Head of Business Planning and Development activities for Africa, Europe, Asia and America during a period of major business growth, supporting the E&P Division’s Deputy General Director. In 2009, he was appointed Head of Upstream M&A, contributing to the rationalization of the portfolio, particularly in the UK and United States. In 2011, he became Senior Vice President of Market Scenarios and Strategic Options in Eni SpA, where he was also appointed Secretary of the Scenario and Sustainability Committee, a post he held until 2019. In 2014, he was appointed Head of Investor Relations and also acted as Secretary to Eni's Advisory Board from 2016 to 2019. In 2019, he moved to Houston to become Upstream Director of the Americas, managing the E&P business in the USA, Mexico, Venezuela and Argentina. He was a member of the Board of Directors of Saipem from 2014 to 2015. Since 2020, he is Board Member of Vår Energi, a company listed on the Oslo Stock Exchange. He was appointed Eni Chief Financial Officer on August 1st, 2020. On October 1st, 2024, he has been appointed Chief Transition & Financial Officer as well as Chief Operating Officer and General Manager, overseeing the process and the implementation of Eni economic and financial strategy, as well as the management and evolution of the sustainable mobility, retail gas & power and renewables businesses. Since October 2024, he’s Board Member of Ithaca Energy.

Giuseppe Ricci was born in Casale Monferrato in 1958. He was appointed Chief Operating Officer of Energy Evolution on January 1, 2021. He joined Eni in 1985 initially working in the study and development of new refining processes at the Sannazzaro refinery, before becoming involved in the creation and consolidation of the joint venture with Kuwait Petroleum at the Milazzo refinery. In 2000 he returned to head office where he was responsible for Refining Processes Development and oversaw the performance optimization at the refining facilities of Agip Petroli. He left central technologies to take over, in 2004, as director of the Gela Refinery, a particularly challenging assignment both from a managerial perspective and in terms of the refining cycle and the complexity of the plant; in 2006 he was appointed managing director of the refinery. In June 2010 he was appointed as Senior Vice President of the Industrial Sector for Refining & Marketing, with responsibility for the refineries, storage deposits, oil pipelines and plant and facilities in Italy, as well as the management of subsidiary and associated companies in Italy and abroad. As Industrial Director he also held a series of additional responsibilities, such as the chairmanship of Gela and Milazzo. In 2012 he took on the delicate role of Eni’s Executive Vice President Health, Safety Environment and Quality with responsibility for providing the guidelines, coordination and control of safety, industrial health, product safety, the environment and quality. On September 12th, 2016, he was appointed as Chief Refining & Marketing Officer. On July 2020 as Eni’s Deputy Chief Operating Officer of Energy Evolution and Director Green/Traditional Refinery and Marketing. Since July 2017 up to June 2023 he was appointed President of Confindustria Energia and since 2018 President of AIDIC (Italian Association of chemical Engineering). He took over as Chief Operating Officer Energy Evolution from January 1st, 2021. Since October 1, 2024, he has been appointed Chief Operating Officer Industrial Transformation, overseeing the industrial transformation activities of traditional refining and chemical, as well as the business development activities and environmental remediation.

Gianfranco Cariola was born in Cosenza in 1968, he was appointed as Director Internal Audit at Eni on April 1, 2021. Between 1993 and 1999, he served as Officer at Guardia di Finanza (Italian Tax Police) General Command. Afterwards, he joined KPMG- KLegal, where he took on the role of Ordinary Member working for a number of major multinational groups in the field of risk management, compliance programs and internal control systems. In 2001 he was seconded to KPMG LLP in Washington DC where he specializes in the structuring of compliance programs and anti-corruption models. In 2003, he moved to the Internal Audit Department of Eni spa where he initially worked on Eni’s Group compliance 231 models; then, he was appointed as Senior Audit Vice President and Head of Planning, Methodologies and Eni’s Internal Control System. From 2013 to 2016, he was the Group Chief Audit Executive and Head of Anti-Corruption and Transparency at RAI spa. Between 2016 and November 2019, he joined Ferrovie dello Stato Italiane spa (FS spa) as Group Chief Audit Executive. On December 2019 he was appointed as Chief Audit Executive at TIM spa. He graduated in Economics, qualified as Italian Certified Public Accountant, in 2008, he completed an Executive MBA in General Management at the SDA Bocconi School of Management and the Polytechnic University of Milan. In 2017 he obtained a second degree, in Economic and Financial Security Sciences.

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Grazia Fimiani was born in Salerno in 1970. She was appointed Director of Integrated Risk Management at Eni on January 1, 2021. Having graduated with honors in Economics and Commerce from Sapienza University in Rome, she joined Eni in 1996, following a brief experience in the financial sector. At Eni, she began her professional career in the Human Resources department, by gaining transversal experience on the processes of Organizational Management, HR Planning and Development. She then went on to management roles in International Business, in particular in the Gas & Power sector, acquiring increasing responsibilities until she took on the role of HR Business Partner in the Gas & Power division. During this period, she coordinated and managed aspects of Human Resources related to business development projects, with particular reference to the integration of entities/companies subject to acquisition at European level and to the re-engineering of business processes, required by the growing exposure of the sector to the dynamics of market. In 2014 she was appointed Head of Human Resources and Organization of Eni reporting to the Chief Services & Stakeholder Relations Officer and, from July 2020, as the Human Capital & Procurement Coordination Director. In this role she coordinated central functions of the Organization Management, HR Development, Industrial Relations and all the activities related to HR Business Partner in several Eni Business areas (Natural Resources, Energy Evolution, Support Functions), as well as the Excellence Centers focused on Recruitment and Training (Eni International Resources and Eni Corporate University). From 2016 to June 2021 she was a standing member, representing Eni in the Executive Committee of Valore D. She participated in sessions of ‘In The Boardroom 4.0 – Eighth Class’ executive training program for Board members. In October 2022, as Eni representative, she was appointed Council Member of World Business Council for Sustainable Development. She is currently member of Boards of Directors of Versalis and Eni Trading & Biofuels, as well as of Eni Foundation.

Luca Franceschini was born in Milan in 1966, from July 1, 2020 he is Head of Integrated Compliance and, from January 1, 2021, also Secretary of the Board of Directors. He is lawyer registered with the Italian Bar Association in Rome. After graduating in Law from the University of Milan, he first joined Eni in 1991 in the legal department of the then Agip S.p.A., providing legal assistance, initially, in commercial litigation and procurement area, and, subsequently, in a wide range of national and international projects in the Exploration & Production sector. In 2000, during the process for the liberalization of the natural gas sector, he was involved in the spin-off of the gas storage business and in the establishment and operational start of Stogit SpA, for which he became head of Legal and Corporate Affairs. He made his return to Eni Spa in 2005 as head of Italian Legal Assistance in the Gas & Power division. Following the concentration of all legal functions in Eni’s central Legal Department, he takes on positions of increasing responsibility, becoming, in 2009, head of legal assistance for Italian Business and Antitrust and in 2015, head of Legal and Regulatory Compliance. After the separation of the compliance function from the Legal Affairs department, in 2016 he became head of the new Integrated Compliance department. In 2017 he was awarded “Compliance Officer of the Year” by the Top Legal Corporate Counsel Awards and the Inhouse Community Awards. He is a member of the Scientific Committee of the Advanced Training Course for Corporate Counsel of the Luiss Business School. He was also member of the boards of directors of Italgas and Stogit.

Claudio Granata was born in Rome in 1960. He holds the position of Director Stakeholder Relations & Services since October 1, 2024 and he has been appointed Chairman of the board of Eni Corporate University since November 2014. He started working in Eni in 1983 and from 1983 to 1994 worked as a labour market and social welfare expert with ASAP (the trade union association for Eni Companies). From 1994 to 1999 he continued his experience with Eni Corporate as an expert in industrial relations. In 2000 he was made responsible for Staff and Organisation within Eni Servizi Amministrativi, a company that was set up to centralise Eni’s administrative activities. In 2001, he took over the management of Eni’s territorial divisions, restructuring the management of staff by geographical area and in 2003 he took on the role of Business HR for Eni Corporate, ensuring support for departments in the management and development of Eni Corporate’s managerial resources during a period of profound change (2002-2004), which was characterised by the mergers of Snam and AgipPetroli and the restructuring of staff organisation. In the same year he was also appointed head of Human Resources and Organisation of SOFID (Eni’s financial services company). In 2006 he was appointed Human Resources Director of the E&P Division, where he oversaw the planning, management, development and compensation processes for human resources and organisation activities. He also collaborated with the top management in the reorganisation of macro processes for the division and promoted change management initiatives. He became a board member of Eni International Resources Ltd in 2006 and was Chairman of the board of Eni International Resources Ltd from 2012 to 2013. From 2012 to March 2015, he was a board member of Eni UK ltd. In 2013 he was appointed Executive Vice President Sustainable Development, Safety, Environment and Quality at E&P, responsible for overseeing safety, environment and quality processes to promote integration with operational processes and contribute to improvements in "time to market" and efficiency. He was appointed Chief Services & Stakeholder Relations Officer in Eni since July 1, 2014. Until May 2016, he was a member of the Board of Directors of the Eni Foundation. He was appointed Director Human Capital & Procurement since July 1, 2020.

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Erika Mandraffino was born in Syracuse in 1972, mother of two. She was appointed Director External Communication of Eni on November 1, 2020. After graduating in European Business Administration in London, where she lived almost uninterruptedly from 1991 to 2005, she began her career as a corporate and financial communications consultant at Ludgate Communications where she worked from 1996 to 1999. Before joining Eni in 2006 as head of the financial and international press office, to then become head of Eni Group media relations in 2011, she worked as Director at the Brunswick Group in London, managing the international communication of European corporates (in Italy, Spain, Holland, Portugal) during crisis situations, mergers, acquisitions and IPOs. From 2000 to 2001 she worked as a communication consultant at Barabino & Partners in Rome. From October 2013 to February 2015 she was Saipem’s Senior Vice President of Institutional Relations and Communication, where she built the external relations department reporting directly to the CEO and managed the company’s communication in a period of crisis. In 2015 she was called back to Eni as Senior Vice President Media Relations and Corporate Publishing, a position held until April 2016 when she took on the role of Senior Vice President Media Relations and Social Networks. In 2018 she became Senior Vice President Global Media Relations and Crisis Communications. From July 1, 2020 she was Eni’s Director Media Relation reporting directly to the CEO until she assumed the current role. She has also been Chairman of Versalis S.p.A from May 2018 until January 2021.

Lapo Pistelli was born in Florence in 1964. He was appointed Director Public Affairs of Eni on July 1, 2020. Graduated with honors in 1988 in International Law at the Political Science faculty “Cesare Alfieri” at the University of Florence, he started working at a research center, while serving for two mandates in the local administration of Florence. He was member of the Italian Parliament from 1996 to 2015 (1996/2004 and 2008/2015), and also member of the European Parliament (2004/2008). He served as Deputy Minister of Foreign Affairs and International Cooperation of Italy from 2013 to 2015. He resigned from all his institutional and political roles in July 2015, when he entered Eni. He taught and lectured at the University of Florence, the Overseas Studies Program of Stanford University and many others international academic institutions. He regularly contributed to many European and American think tanks and research centers specialized in international relations. He is member of the board of the European Council on Foreign Relations (ECFR) and of the Istituto Affari Internazionali (IAI), and member of the WE – World of Energy editorial committee. He also collaborates with Limes and Aspenia magazines. He’s Chairman of OME (Observatoire Mediterranéen de l’Energie et du Climat).

Stefano Speroni was born in Milano in 1962. He was appointed Director Legal Affairs and Commercial Negotiations of Eni on July 1, 2020. He has accumulated vast experience in over 30 years of professional activity in the field of corporate affairs, mergers and acquisitions, private equity operations and capital markets. He has given professional support to Italian and International listed companies (in a wide range of sectors including aerospace and defence, oil & gas, telecommunications, transport and infrastructure) in strategic corporate affairs, in share trading, joint ventures and commercial agreements. From January 2016 to December 2018, he was a Managing Partner for Corporate M&A in Dentons’ Italian practice. He joined Eni in January 2019 and he was appointed Senior Executive Vice President of Legal Affairs. In 2012, he was one of the founders of the Grimaldi Legal Studio, after having previously been managing partner of Dewey Ballantine’s Rome practice which involved managing its Italian activities for around 10 years. He was also a partner in Studio Gianni, Origoni, Grippo Capelli & Partners (2001 – 2003), in the Simmons and Simmons Italian practice (1991 – 2001), and manager of the European Corporate Department and member of the World-wide Remuneration Committee. He is a member of the scientific committee and contributor to SDA Bocconi’s Private Equity Laboratory and was awarded “Best Lawyer of the Year” 2018 by the Best Lawyers international directory. He graduated in Law at Università degli Studi in Milan and is a registered member of the Italian Bar Association in Milan.

Roberto Ulissi was born in Rome in 1962. Since 2006, he has been Head (now called Director) of Corporate Affairs and Governance, reporting directly to the Chief Executive Officer. He is a Board member and Vice Chairman of Banor SIM. He is a lawyer. After a number of years spent as a lawyer at the Bank of Italy, in 1998 he was appointed General Manager at the Ministry of the Economy and Finance head of the Banking and Financial System and Legal Affairs Department. He was a Board member of Telecom Italia (and Chairman of the Audit Committee), Ferrovie dello Stato, Alitalia, Fincantieri and a government representative on the Governing Council of the Bank of Italy. He was also a member of numerous Italian and European committees representing the Ministry of the Economy including, at a national level, the Commission for the Reform of Corporate Law (“Vietti” Commission) and, at EU level, the Financial Services Policy Group, the Banking Advisory Committee, the European Banking Committee, the European Securities Committee, and the Financial Services Committee. He was also special professor of Banking Law at the University of Cassino. He is “Grande Ufficiale della Repubblica Italiana”. Until December 2020, he was Eni’s Company Secretary (Board Secretary and Corporate Governance Counsel) and was a Board Member of Eni International BV. From 2018 to 2021 he was the Coordinator of the Corporate Governance Forum of Company Secretaries.

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Fiorillo Lorenzo was born in Vibo Valentia in 1974. He is appointed as Director Technology, R&D & Digital of Eni since May 2024. After graduating in Chemical Engineering in Pisa in 1998, in January 1999 he joined Eni as a Production Optimization Technician at San Donato Milanese headquarters. Later on an initial experience in the field on reservoir studies and in the Italian operating districts, in 2004 he held the role of Technical Manager at Enimed company in Gela, subsequently increasing his responsibilities, both in Sicily and in Tunisia, until being appointed in January 2010 as President and CEO of Enimed. Between 2012 and 2018 he was in Congo holding the role of Directeur General of the Eni Congo company with the responsibility of managing Eni's business in the country, working on the development of long-term activities, in particular through the strategy of valorising gas reserves. Following his experience in Congo, he held a similar role in Nigeria in the Nigerian Agip Oil Company until July 2020, also assuming the Presidency of the OPTS (Oil Producers Trade Section). He subsequently held the position of Head of the Upstream West Africa Region and in April 2021 he took the responsibility for the entire Sub-Saharan Africa Region. Starting from June 2022 he is appointed Operations & Energy Efficiency Manager in the Natural Resources General Department, with responsibility for production, maintenance, drilling, logistics and decommissioning activities. Since 2023 he has been a member of the Confindustria Technical Group.

Compensation

The information concerning compensation is provided in the Remuneration Report prepared in accordance to Italian listing standards, which is incorporated herein by reference. See the Exhibit 15. a (i).

As of December 31, 2025, the total amount accrued to the reserve for employee termination indemnities with respect to Chief Executive Officer, Chief Operating Officers, and other Managers with strategic responsibilities (with reference to the employed ones in service, who, during the course of the 2025 period, filled said roles, even if only for a fraction of the year), was €854 thousand.

Name |  |  |  | (€ thousand) |
Descalzi Claudio |  | CEO and General Manager of Eni |  | 445 |
Brusco Guido |  | Chief Operating Officer Global Natural Resources |  | 6 |
Gattei Francesco |  | Chief Operating Officer Chief Transition & Financial Officer |  | 34 |
Senior managers (a) |  |  |  | 369 |
|  |  |  | 854 |

(a) No. 8 managers.

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Board practices 7

Corporate G o vernance

The Corporate Governance structure of Eni follows the Italian traditional management and control model, whereby corporate management is the responsibility of the Board of Directors, which is the core of the organizational system, while supervisory functions are allocated to the Board of Statutory Auditors. The Company’s accounts are independently audited by an accredited Audit Firm appointed by the Shareholders’ Meeting. On December 23, 2020 Eni adopted the Corporate Governance Code approved by the Italian Corporate Governance Committee on January 2020 (hereinafter “Code”), effective from January 1, 2021.

The names of Eni’s Directors, their positions, the year in which each of them was initially appointed as a Director and their ages are reported in the relevant table above.

Boa r d of Directors’ duties and responsibilities

The Board of Directors has the fullest powers for the ordinary and extraordinary management of the Company in relation to its purpose. In a resolution dated May 11, 2023, the Board, while exclusively reserving to itself the most important strategic, operational and organizational powers, appointed Claudio Descalzi as CEO and General Manager, entrusting him with the fullest powers for the ordinary and extraordinary management of the Company, with the exception of those powers that cannot be delegated under current law and those retained by the Board.

In the same resolution, the Board of Directors resolved to confer to the Chairman a major role in internal controls and non- operational functions. In particular, with reference to Internal Audit, the Board of Directors resolved that, in accordance with the Corporate Governance Code in force at that time, the Head of the Internal Audit Department reports to the Board, and on its behalf, to the Chairman, without prejudice to its functional reporting to the Control and Risk Committee and the Chief Executive Officer, as the director in charge of the internal control and risk management system. The Chairman is also involved in the appointment of the primary Eni officers in charge of internal controls and risk management, as well as in approving internal rules governing the Internal Audit process. In addition, the Chairman carries out his statutory functions as legal representative, managing institutional relationships in Italy, together with the Chief Executive Officer.

On the same date (May 11, 2023), the Board of Directors appointed the Secretary of the Board of Directors and Board Counsel, who reports hierarchically and functionally to the Board and, on its behalf, to the Chairman. He provides assistance and independent (from the management) legal advice to the Board and the Directors.

With resolution dated May 11, 2023, as last amended by resolution of January 29, 2026, the Board of Directors updated the specific responsibilities reserved to itself, which are fully reported below. Accordingly, the Board, in addition to powers that may not be delegated by law and by By-laws, has the following exclusive powers:

7 The information contained in this chapter is updated to December 31, 2025 and for specific aspects, expressly indicated, up to the date of approval of this Report.

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the Board:

• | Defines the system and rules of corporate governance for the Company, evaluating and promoting, where necessary, the appropriate amendments, submitting the same, when appropriate, to the Shareholders' meeting. Defines the structure of the Group it leads. Approves the Report on corporate governance and ownership, with the support of the Control and Risk Committee with regard to the internal control and risk management system. Approves, having received the opinion of the Control and Risk Committee, the guidelines for the internal regulatory system and the policies on Ethics, Compliance & Governance. Having received the favourable opinion of the Control and Risk Committee, adopts rules ensuring the transparency and the substantive and procedural fairness of transactions with related parties and those in which a Director or a Statutory Auditor holds a personal interest or an interest on behalf of third parties, assessing on an annual basis whether any revision is needed. Upon proposal of the Chairman, in consultation with the CEO, it also adopts a procedure for the internal handling and the disclosure of Company documents and information, with particular reference to inside information.
• | Defines its operational rules and procedures, including the procedures for providing information to directors. Establishes setting out their duties and rules of procedures, the Board’s internal Committees, with preliminary, propositional and consultative functions, defines their composition appointing and revoking their members and Chairmen, favouring the competence and experience of their members and avoiding an excessive concentration of offices and determines upon proposal of the Remuneration Committee and following consultation with the Board of Statutory Auditors, their compensation. Acting upon proposal of the same committees, approves their annual budgets and establishes the terms and conditions on which committees can use external consultants.
• | Upon their appointment and on annual basis, as well as at the occurrence of relevant circumstances, based on the information provided by the interested party or available to the Company and following the preliminary investigation of the Nomination Committee, assesses the independence and integrity of its members, as well as the non-existence of reasons for ineligibility and incompatibility. Defines ex ante the quantitative and qualitative criteria for assessing the significance of commercial, financial or professional relations, as well as of any remuneration other than the fixed remuneration that may compromise or appear to compromise independence. Carries out the assessments vested in it by law in relation to the requirements applicable to Statutory Auditors. Acting upon a proposal of the Nomination Committee, it expresses its policy on the maximum number of director or statutory auditor positions that can be held by its members in any other listed company, whether Italian or foreign, or in financial, banking or insurance companies or in companies of significant size that are compatible with the effective performance of their role as director, taking into account the time commitment required by the role, and periodically verifies their compliance, at least on an annual basis. Every year carries out an assessment on the specific functioning of the Board itself and of its committees, as well as on their size and composition, using at least once every three years an external independent consultant, appointed upon proposal of the Nomination Committee, also considering the role it has played in defining strategies and monitoring management and the adequacy of the internal control and risk management system. The Chairman ensures, with the help of the Board Secretary, the adequacy and transparency of the self-assessment process of the administrative body, with the support of the Nomination Committee. The Nomination Committee upon request of the Board, provides assistance in the self- assessment activities of the Board and its Committees. Taking into account the outcomes of such assessment, with the support of the Nomination Committee, the Board defines the optimal composition of the Board itself and of its committees, issuing its advice for shareholders on the size and composition of the new Board before its appointment. With the assistance of the Nomination Committee, identifies candidates for the office of Director in case of co-optation and, where possible and appropriate, prepares and submits its own slate for the renewal of the body. Requires to whoever submits a slate with a number of candidates that is higher than half the number of members to be elected to provide adequate information, in the documentation presented for filing the slate, on the compliance of the slate with the advice expressed by the Board, and also with reference to diversity criteria envisaged by the law and by the Corporate Governance Code, and to indicate the candidate for the office of Chairman of the Board.
• | Where applicable, appoints and revokes an independent director as “lead independent director”.
• | Delegates and revokes powers to/from the Chief Executive Officer and the Chairman, establishing the limits and methods for exercising these powers and, after examining the proposals of the Remuneration Committee and following consultation with the Board of Statutory Auditors, determining the remuneration connected with these duties. The Board may impart directives to the delegated bodies and itself undertake any operations falling within the delegated powers. Prepares, updates and implements, with the support of the Nomination Committee, a succession plan for the Chief Executive Officer identifying at least the procedures to be followed in the event of early termination of office. It also ascertains the existence of adequate procedures for the succession of top management.

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• | Taking into account the obligations established by current legislation on the matter: (i) establishes the basic guidelines for the organizational, administrative and accounting structure, including the internal control and risk management system, of the Company, of subsidiaries with strategic importance and of the Group; (ii) it evaluates the adequacy of the organizational, administrative and accounting structure of the Company, of the subsidiaries with strategic importance and of the Group, with particular reference to the internal control and risk management system, put in place by the Chief Executive Officer.
• | With the support of the Control and Risk Committee and following consultation with the Chairman in regard of the internal audit activities, establishes the general guidelines for the internal control and risk management system, in line with the Company's strategies. With reference to the multy-year Strategic Plan, defines the nature and level of risk compatible with the strategic objectives of the company, on the basis of an estimate of the probability and impact of the risks issued (and, if necessary, updated during the year) by the Integrated Risk Management function, including in its assessments all the risks that may be relevant in terms of sustainable success of the Company. Upon proposal of the Chief Executive Officer and in agreement with the Control and Risk Committee and the Board of Statutory, defines the principles concerning the coordination and information flows between the various subjects involved in the internal control and risk management system. Approves the guidelines on the internal audit activity, upon proposal of the Chairman, in agreement with the Chief Executive Officer and having consulted the Control and Risk Committee. Defines the guidelines for the management and control of financial risks, after having heard the opinion of the Control and Risk Committee, and defines the financial risk limits for the Company and its subsidiaries. With the support of the Control and Risk Committee (i) examines the main Company risks, identified by the Chief Executive Officer, taking into account the nature of the business of the Company and of its subsidiaries, as reported by the Chief Executive Officer to the Board at least once every three months and (ii) every six months, based on the reports prepared by the Officer in charge of preparing financial reports of Eni SpA, as well as the reports by the Control and Risk Committee, the Risk Report and, annually, also on the basis of the Report on compliance with financial risk limits and the Integrated Compliance Report, evaluates the adequacy of the internal control and risk management system with regard to the nature of the business and its risk profile, as well as its effectiveness. It also evaluates the adequacy of powers and means given to the Officer in charge of preparing financial reports, and the actual compliance with the administrative and accounting procedures prepared by said Officer; (iii) assesses on an annual basis the adequacy of the organizational structure of the internal control and risk management system with respect to the characteristics of the company and its risk profile as well as its effectiveness, except for amendments that could make a six-monthly revision necessary, taking this into account also for the purposes of the evaluation on the adequacy of the internal controls and risk management system under point ii). Approves the Management, Supervision and Control Model of the risks on Health, Safety and Environment, Security and Public Safety of the Company, and its substantial amendments.
• | At least annually, approves the Audit Plan prepared by the Head of the Internal Audit Department, with the support of the Control and Risk Committee and following consultation with the Chairman, the Chief Executive Officer and the Board of Statutory Auditors. Evaluates, with the support of the Control and Risk Committee and following consultation with the Board of Statutory Auditors, the findings contained in the recommendation letter, if any, of the audit firm and in its additional report, together with any comments of the Board of Statutory Auditors, informing the Board of Directors on the results of the auditing.
• | Defines, upon proposal of the Chief Executive Officer, the strategic guidelines and objectives of the Company and of the Group, pursuing its sustainable success and monitoring its implementation. Examines and approves the multy-year Strategic Plan and the medium-long term plans of the Company and of the Group and related budgets, also on the basis of the analysis of the issues relevant to the generation of long-term value, periodically monitoring their implementation. Examines and approves the plan for the Company’s non-profit activities, after the assessment of the Sustainability and Scenarios Committee; it also approves operations not included in the non-profit plan whose cost exceeds € 1 million, provided that reports on operations not included in the plan and not subject to Board approval are periodically submitted to the Board, in accordance with paragraph below.

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• | Examines and approves, with the support of the Board Committees to the extent applicable, the Annual Financial Report, which includes the draft of Eni Financial Statements, the Consolidated Financial Statements and the Sustainability Statement, the annual voluntary Sustainability Report and the half-year financial report. It also examines and approves any periodic information relating to quarterly financial reports and preliminary reports, the annual Report on Payments to Governments and any additional periodic statements or reports in accordance with applicable regulations.
• | Receives from Directors with delegated powers at the Board meetings, on at least a bi- monthly basis, reports on actions taken in exercising their delegated powers, as well as on Group activities and on atypical or unusual transactions that have not been submitted to the Board for examination and approval, as well as on the execution of transactions with related parties and those in which the Directors and Statutory Auditors hold an interest in accordance with the relevant internal procedures. It also receives prior information: (i) on the closure of significant industrial sites in the refining and chemical sector, when the closure does not follow the liquidation of a company and (ii) on exiting countries where the Company operates, when entry was authorized by the Board.
• | Receives periodic reports from the Chairman, on the implementation of Board resolutions. At each Board meeting, receives information from the Board’s internal Committees on the most relevant issues examined during their meetings and, on an annual basis, a report on their activities with the exception of the reports of the Control and Risk Committee, including the opinion on the adequacy of the internal control and risk management system, presented on the occasion of the approval of the Annual Financial Report and the Half-Year Financial Report. .
• | Assesses general trends in the operations of the Company and of the group on the basis of information received from Directors with delegated powers, paying particular attention to conflicts of interest and comparing, normally on a quarterly basis, results – as reported in the annual financial statements and interim financial reports – with budget forecasts.
• | Examines and approves, with the support of the competent board committees, transactions by the Company and by its subsidiaries with related parties as provided for in the relative procedure approved by the Board, as well as transactions in which the Chief Executive Officer holds an interest pursuant to art. 2391, first paragraph, of the Italian Civil Code, that fall under the responsibility of the Chief Executive Officer.
• | Evaluates and approves any transaction executed by the Company and by its subsidiaries (excluding the joint- control companies), that has a significant impact on the Company's strategy, performance or financial position.

The Board ensures compliance with the principles of good corporate governance and management of the subsidiaries, protecting their operational autonomy with specific regard to listed companies and companies for which law or regulations require it. It also ensures the confidentiality of transactions between said subsidiaries and Eni or third parties for the protection of the subsidiaries' interests. Without prejudice to any of the provisions mentioned below, transactions with a significant impact include the following:

a) acquisitions and disposals of equity investments, companies or business units, property rights, leases active and passive of companies or business units, transfers of assets, mergers, demergers and liquidations of companies exceeding €200 million in the upstream oil&gas sector and €150 million in other business sectors, with the exception of intra-group transactions and without prejudice to the powers reserved to the Shareholders’ Meeting and to the Board of directors, under Civil Code and the Company’s By-laws;

b) acquisitions and disposals (also as part of “unification” agreements) of exploration mining rights exceeding €150 million and productive mining rights exceeding €200 million;

c) capital increases (i) of subsidiaries: for amounts exceeding €1 billion, (ii) of associate companies: for amounts exceeding €500 million, if proportionate to the interest held, and of any amount, if not proportional to the interest held;

d) investments in fixed assets exceeding €500 million in the upstream oil&gas sector, and €300 million in other sectors;

e) transactions that imply: (i) entry into new countries, with a significant operational presence or with initiatives that present a particular risk and/or (ii) significant entry into new business sectors;

f) real estate leases, purchase and sale of goods and contracts for the provision of work or services (other than those intended for investment and gas supplies), with the exclusion of contracts with and between subsidiaries, at a total price exceeding €1 billion or, if the total price exceeds €500 million, with a duration of more than 20 years, with the exception of crude oil purchase and sale contracts falling within the scope of ordinary oil trading activities;

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g) gas and LNG purchase and supply contracts, of at least 3 billion cubic meters per year and ten-year duration or changes to gas purchase and supply contracts involving increases in commitments of at least 3 billion cubic meters per year and increases in duration, inclusive of the residual duration of the contract, exceeding 10 years, with the exception of modifications made in execution of contractual clauses already included in the original agreement;

h) loans to subjects other than subsidiaries: (i) if in favour of associate companies: for an amount exceeding €300 million, if in proportion to interest held; and for an amount exceeding €10 million if not proportional to interest held; (ii) if in favour of non- associate companies: of any amount; (iii) changes in the loans referred to in points (i) and (ii), which determine a worsening in the approved contractual terms.

The following transactions do not require the approval of the Board:

a. financial commitments assumed in a non-proportional amount to interest held (so-called "carry agreement") within contracts relating to the exploration and development phase of hydrocarbons, provided that the following conditions are jointly warranted: (i) the obligations are assumed in favour of the host state or an oil company directly or indirectly wholly-owned by the host state; (ii) the obligations are distributed in proportion to the interest held in the reference asset by subjects other than the State or the State oil company (referred to in point i) at the time the financial commitment is made; (iii) with relation only to carry agreements for the development phase, the risk of repayment of the loan is guaranteed by any future financial or production flows of the underlying mining investment. The carry agreements, or amendments thereof, stipulated after the conclusion of the above contracts, are subject to the approval of the Board if they determine a non-proportional increase in the exposure and for amounts exceeding €200 million;

b. the signing and application of default clauses contained in the contracts regulating the mining activity between partners of a joint venture;

i) issuing of unsecured and secured guarantees to entities other than subsidiaries: (i) for amounts exceeding €500 million, if in the interest of the Company or of Eni subsidiaries; (ii) for amounts exceeding €300 million, if in the interest of non-controlled associated companies; (iii) in any case, for amounts exceeding €10 million if the guarantee is not proportionate to the interest held in the obligations underlying the guarantee (with the exception of the case in which the non-proportionality is due to the presence of a carry agreement within the limits indicated in letter h) above or to the presence, in the share capital of subsidiaries included in the consolidation area of Eni S.p.A., of minority shareholders who act exclusively as financial investors); (iv) if in the interest of entities belonging to "Temporary Business Groupings" for participation in tenders for which Eni or its subsidiaries act as agents, for an amount exceeding €50 million, or for any amount if there is no provision for the issue of a counter-guarantee by the entities participating in the "Temporary Business Grouping"; (v) for any amount, if in the interest of third parties; (vi) for an indeterminate amount, in the interest of any person; (vii) changes to the guarantees referred to in the previous points, which determine a worsening in guarantees already issued;

j) waiver of rights with a value equal to the thresholds set out in the preceding letters for the acquisition or transfer of the same rights;

k) Eni S.p.A. intermediation agreements, understood as contracts in which the Company, in relation to a specific business initiative, appoints an entity for the exclusive purpose of putting the Company in contact with third parties, promoting the interests of the Company with the aforementioned subjects and facilitating the stipulation/execution of contracts with them.

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• | Appoints and revokes – acting upon proposal of the Chief Executive Officer in agreement with the Chairman and following consultation with the Nomination Committee – the Chief Operating Officers, defining the content and limits of their powers as well as the provisions for exercising them. In the case of appointment of the Chief Executive Officer as General Manager, the proposal is made by the Chairman. At the time of the appointment and periodically, the Board assesses compliance with the integrity requirements provided for by current legislation for General managers.
• | Upon proposal of the Chairman, appoints and revokes the Board Secretary and Board Counsel, which reports hierarchically and operationally to the Board and by means of it to the Chairman, and determines the remuneration, the charter and the annual budget.
• | After assessing his compliance with professional and integrity requirements, appoints and removes the Officer in charge of preparing financial reports – acting upon a proposal of the Chief Executive Officer and in agreement with the Chairman, following consultation with the Nomination Committee, and having received the favourable opinion of the Board of Statutory Auditors; also, following the opinion of the Control and Risk Committee, ensures that he has adequate powers and means to carry out his statutory duties and monitors compliance with the administrative and accounting procedures established by the abovementioned officer. The Board periodically assesses the possession of the integrity requirements provided for by current legislation for the Officer in charge of preparing financial reports.
• | Acting upon proposal of the Chairman, in agreement with the Chief Executive Officer, with the support of the Control and Risk Committee, and following consultation with the Board of Statutory Auditors, it (i) appoints and removes the Head of Internal Audit Department, with the support of the Nomination Committee (ii) it approves the Internal Audit budget, ensuring that the Head of Internal Audit Department has adequate resources to carry out his duties: (iii) establishes his remuneration structure in accordance with the Company’s remuneration policies. The Head of Internal Audit Department reports hierarchically to the Board and, on its behalf, to the Chairman, without prejudice to its operational dependence on the Control and Risk Committee and on the Chief Executive Officer.
• | Approves the Company’s Code of Ethics and the General Part of Model 231 in the manner and within the terms established by the aforementioned documents. With the support of the Control and Risk Committee, determines also the attribution of supervisory functions and the composition criteria of the supervisory body pursuant to Legislative Decree 231/2001 and, on the proposal of the Chief Executive Officer, in agreement with the Chairman: (i) having heard the Nomination Committee and, for external members, also the opinion of the Board of Statutory Auditors, it appoints and removes the members of the Supervisory Body referred to in Legislative Decree no. 231 of 2001, determining its composition and (ii) having heard the Remuneration Committee, establishing the remuneration of its members. Upon proposal of the Supervisory Body, approves the related annual "budget".
• | Evaluates, with the support of the Control and Risk Committee, the adoption of measures to guarantee the effectiveness and impartiality of judgment of the Integrated Risk Management and Integrated Compliance functions and of any other functions involved in controls, verifying that they are equipped with adequate skills and resources.
• | Promotes, in the most appropriate way, dialogue with shareholders and other relevant stakeholders for the company. Upon the proposal of the Chairman, in agreement with the Chief Executive Officer, adopts and describes, in the corporate governance report, a policy for managing dialogue with the generality of shareholders. The Chairman ensures, within the terms established by said policy, that the Board receives, by the first useful meeting and in any case within the terms established by the policy, information on the development and significant contents of the dialogue taking place with all the shareholders.

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• | Defines, with the assistance of the Remuneration Committee, the policy for the remuneration of directors, managers with strategic responsibilities and, without prejudice to the provisions of art. 2402 of the Italian civil code, of members of the control body; it approves, on the proposal of the same Committee, the Report on the remuneration policy and compensation paid to be presented to the Shareholders' Meeting called to approve the financial statements. Furthermore, in implementing the Remuneration Policy, approved in the Shareholders' Meeting, following a proposal from the Remuneration Committee: (i) defines, having heard the opinion of the Board of Statutory Auditors, the remuneration of Directors with delegated powers and those with particular offices; (ii) establishes the objectives, and verifies their final achievement, connected to the variable remuneration of Directors with delegated powers and the incentive plans; (iii) implements the remuneration plans based on shares or financial instruments approved by the Shareholders' Meeting; (iv) ensures that the remuneration paid and accrued is consistent with the principles and criteria defined in the policy, in light of the results achieved and other relevant circumstances for its implementation. Upon termination of office and/or of the relationship with the Chief Executive Officer or a Chief Operating Officer, based on the outcome of the internal processes leading to the attribution or recognition of any indemnity and/or other benefits, approves the press release to be disseminated to the market with the information required by the Corporate Governance Code and/or by any applicable regulations.
• | Decides – acting upon a proposal of the Chief Executive Officer – on the exercise of voting rights and, in consultation with the Nomination Committee, on the appointment of members of corporate bodies of the subsidiaries with strategic importance and Saipem S.p.A. In the case of listed companies, the Board must guarantee compliance with the provisions of the Corporate Governance Code that fall under the competence of the Shareholders' Meeting.
• | Formulates proposals to submit to the Shareholders' Meeting and, through the Chairman and the Chief Executive Officer, reports to the Shareholders' Meeting on the activities carried out and planned, working to ensure that shareholders receive adequate information about the elements they need to take the decisions pertaining to them, with knowledge of the facts.
• | Examines and decides on other issues that Directors with delegated powers believe should be presented to the Board due to their particular importance or sensitivity.

In accordance with art. 23.2 of the By-laws, the Board also decides upon: mergers and proportional spin-offs of companies in which the Company’s shareholding is at least 90%; the establishment and closing of secondary offices; and the amendment of the By-laws to comply with regulatory provisions. For the purposes of the above-mentioned resolution and the Corporate Governance Code, to which Eni S.p.A. adheres, "subsidiaries with strategic importance" means the following companies: Eni International BV, Eni Plenitude S.p.A. Società Benefit and Versalis S.p.A

According to this resolution, the Chief Executive Officer is also in charge of establishing and maintaining the internal control and risk management system. The Board authorizes the Chief Executive Officer to modify investment transactions previously approved by the Board, in ways that do not involve a substantial reconfiguration of the underlying industrial project. The Board receives annual information on these modifications in the event of: (i) an increase in the whole life cost of more than 30% compared to the authorized amount and/or (ii) a reduction in profitability below the hurdle rate or of the adjusted WACC, for projects authorized on the basis of these parameters.

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Directors’ independence

On the basis of statements made by the Directors and other information available to the Company, the Board of Directors after its appointment, in its meeting of May 11, 2023:

- first, defined the criteria for assessing independence, pursuant to the Code, confirming the criteria already identified by the former Board of Directors, relating to the identification of additional remuneration and significance of relationships that could compromise independence;

- and then assessed that the Chairman and Directors Baroncini, Belcredi, Dittmeier, Seganti, Sgubin and Vermeir meet the independence requirements provided for by law and by the Code. At the assessments carried out in February 2024, February 2025 and February 2026, the Board of Directors, after preliminary assessment by the Nomination Committee, confirmed the previous assessment of independence pursuant to law and to the Code of the Chairman of the Board of Directors Zafarana and Directors Baroncini, Belcredi, Dittmeier, Seganti, Sgubin and Vermeir. In addiction, at the assessment carried out in February 2026, based on provisions of Decree Law no. 95/2025, converted into Law no. 118/2025, and on the statement made by Director Ciciani, the Board of Directors, after preliminary assessment by the Nomination Committee, also assessed the independence pursuant to law of Director Ciciani.

The outcome of the assessments of independence of directors is disclosed to the market immediately after the appointment through a specific press release and, later, in the annual Corporate Governance Report, available on Eni website.

The relationships were evaluated on the basis of statements made by the Directors and other information available to the Company.

The Board of Statutory Auditors verified the proper application of criteria and procedures adopted by the Board of Directors in assessing the independence of its members.

Such independence criteria may be not equivalent to the independence criteria set forth in the NYSE listing standards applicable to a U.S. domestic company.

On May 11, 2023, the Board of Directors of Eni confirmed Raphael Louis L. Vermeir Lead Independent Director. Pursuant to Italian Corporate Governance Code, the Lead Independent Director collects and coordinates the requests and contributions of non-executive directors and, in particular, of independent ones and coordinates the meetings of the independent directors.

Boa r d Committees

The Board of Directors has established four internal Committees to provide it with recommendations and advice: (a) the Control and Risk Committee; (b) the Remuneration Committee; (c) the Nomination Committee; and (d) the Sustainability and Scenarios Committee. Committees under letters (a), (b) and (c) are recommended by the Code. The composition, duties and operational procedures of these committees are governed by their own rules, which are approved by the Board, in compliance with the criteria outlined in the Code.

The Committees recommended by the Code are composed of no fewer than three members and, in any case, less than a majority of members of the Board. The composition is described in the following sections pertaining each Committee.

All Board Committees report to the Board of Directors, at least once every six months, on activities carried out. Starting from 2026, the reports will be issued annually accordingly with the new “Rules of the Board of Directors and its Committees”, adopted by the Board itself on January 29, 2026. In addition, the Chairmen of the Committees report to the Board at each meeting of the Board on the key issues examined by the Committees in their previous meetings.

In the exercise of their functions, the Committees have the right to access any information and Company functions necessary to perform their duties. They are also provided with adequate financial resources, in accordance with the terms established by the Board of Directors and can avail themselves of external advisers.

The Chairman of the Board of Statutory Auditors or a Statutory Auditor designated by her, participates in Control and Risk Committee. Members of the Board of Statutory Auditors may also attend other Committee’s meetings. Upon invitation of the Chairman of the Committee, the Chairman of the Board of Directors and/or the Chief Executive Officer may attend specific meetings 8 as well as other Directors, after having heard the Chairman of the Board. Moreover, upon invitation of the Chairman of the Committee, and having informed the Chief Executive Officer, other members of the Company structure, for their own competence, may be invited to participate in the meeting on specific items of the agenda.

8 Except for meetings of the Remuneration Committee examining proposals regarding their remuneration. Rules of the Remuneration Committee establish that “no Director and, in particular, no Director with delegated powers may take part in meetings of the Committee during which Board proposals regarding his or her remuneration are being discussed, unless such proposals regard all the members of the Committees established within the Board of Directors.”

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The Board Secretary and Board Counsel coordinates the secretaries of the Board Committees, receiving for this purpose information on the calendar of the meetings and the items in the Committees’ agendas, the notices of the meetings, as well as their signed minutes.

Minutes of all Committee meetings are usually drafted by their respective secretaries. The current members of the Control and Risk Committee, Remuneration Committee, Nomination Committee and Sustainability and Scenarios Committee were appointed by the Board of Directors on May 11, 2023.

Set forth below is a detailed description of the Committees’ duties, as established by the regulations in force as of December 31, 2025, in relation to which the regulation adopted on January 29, 2026, introduced no substantive amendments.

Remuneration Committee

Members: Massimo Belcredi (Chairman), Cristina Sgubin, Raphael Louis L. Vermeir.

The Remuneration Committee is made up of three non-executive Directors, all of whom independent.

The members of the Committee shall have expertise that is consistent with the duties they are required to perform, to be evaluated by the Board of Directors at the time of the appointment.

In particular, at their appointment, the Directors Belcredi and Vermeir have been identified by the Board as members "with adequate knowledge and experience in financial matters or remuneration policies", as recommended by the Corporate Governance Code.

In accordance with the By-laws and the Corporate Governance Code, the Committee assists the Board of Directors with preparatory, consultative and advisory functions on remuneration issues. More specifically, the Committee:

| a) | submits to the Board of Directors for its approval the “Report on remuneration policy and remuneration paid” and, in particular, the remuneration policy for members of corporate bodies, General Managers and managers with strategic responsibilities, without prejudice to provisions of Art. 2402 of Italian Civil Code, to be presented to the Shareholders’ Meeting called to approve the financial statements, as provided for by the applicable law;
| b) | presents proposals and expresses opinions for the remuneration of the Chairman of the Board of Directors and the Chief Executive Officer, covering the various forms of compensation and benefits awarded;
| c) | presents proposals and expresses opinions for the remuneration of the members of the Board’s internal committees;
| d) | examines the CEO’s indications and presents proposals for:
|  | i. | general criteria for the remuneration of managers with strategic responsibilities;
|  | ii. | annual and long-term incentive plans, including equity-based plans;
|  | iii. | establishing performance targets and assessing results for performance plans in connection with the determination of the variable portion of the remuneration for Directors with delegated powers and with the implementation of incentive plans;
| e) | periodically evaluates the adequacy, overall consistency and actual implementation of the adopted policy, as described in letter a) above and assesses, in particular, the actual achievement of the performance objectives, formulating proposals on the matter to the Board;
| f) | performs the tasks required under the Company’s procedures for handling related party transactions;
| g) | examines and monitors the results of engagement activities carried out in support of the Eni Remuneration Policy, within the terms set forth in the engagement policy approved by the Board.

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Control and Risk Committee

Members: Raphael Louis L. Vermeir (Chairman), Carolyn Adele Dittmeier, Federica Seganti and Cristina Sgubin.

The Control and Risk Committee supports the Board of Directors’ assessments and decisions relating to the Internal Control and Risk Management System (ICRMS) and the approval of periodical financial and non-financial reports. The Committee supports the Board with preparatory work, following which it formulates assessments and/or opinions to the Board.

The Control and Risk Committee comprises four non-executive independent directors.9

In particular, the Directors Vermeir, Dittmeier and Seganti have been identified by the Board as members "with adequate knowledge and experience in accounting, finance or risk management", required by the Code of Corporate Governance (Recommendation 35)10. The Chairman of the Committee was elected from the minority list presented by Italian and foreign institutional investors.

The Committee supports the Board of Directors with preparatory work, following which it formulates assessments and/or opinions, in particular with regard to:

a) the guidelines for the internal control and risk management system (ICRMS) consistently with the Company’s strategies, so that the main risks that affect the Company and its subsidiaries can be correctly identified and appropriately measured, managed and monitored, expressing in this regard the opinion required by internal regulations on the matter; it also supports the Board of Directors in determining the degree of compatibility of such risks with the management of the Company in a manner consistent with its stated strategic objectives and preliminary examining the main company risks, taking into account the characteristics of the activities carried out by the company or its subsidiaries. In the course of 2025, the Committee contributed to the design of the Eni Risk and Internal Control Holistic Framework Policy (Enrich), which integrates established practices to effectively identify, measure, manage and monitor key risks, driving the development of adaptive control systems for the specific contexts in which we operate with a view of better adapting to the Company’s ongoing transformation and supporting achievement of Company’s goals and strategy execution;

b) the definition, within the Strategic Plan, of the annual guidelines of the internal control and risk management system ("Annual plan for the integrated management of strategic risks"), proposed by the Chief Executive Officer, in line with the strategies of the company, as well as the annual assessment of the implementation of these guidelines, based on the Report prepared for this purpose by the Chief Executive Officer;

c) the evaluation performed at least every six months, of the adequacy of the internal control and risk management system, taking account of the characteristics of the Company and its risk profile, as well as its effectiveness. To this end, it reports to the Board of Directors, on the occasion of the approval of the annual and semi-annual financial reports, on its activities and on the adequacy of the ICRMS;

d) the fundamental guidelines of the Regulatory System, the regulatory instruments to be approved by the Board of Directors, their amendment or update, and, upon request by the CEO, on specific aspects in relation to the instruments implementing the fundamental guidelines, expressing in this regard the opinion required by internal regulations on the matter;

e) the guidelines for the management and control of financial risks, expressing in this regard the opinion required by internal regulations on the matter;

9 In accordance with the rules of the Control and Risk Committee, the Committee is made up of three to four non-executive Directors, all of whom are independent. Alternatively, the Committee may be made up of non-executive Directors, the majority of whom shall be independent. In the latter case, the Chairman of the Committee shall be chosen from among the independent Directors. In any case, the number of members shall be fewer than the number representing a majority on the Board.
10 The Governance system put in place by Eni establishes that the Committee as a whole possesses adequate expertise in the sector of activity in which the Company operates, as necessary to assess the related risks, and must in any case have adequate skills in relation to the tasks it is called upon to perform, as assessed by the Board of Directors upon the appointment; two members of the Committee if there are such members on the Board, or in any case at least one member of the Committee or in any case at least one member of the Committee must possess adequate experience in financial and accounting matters or in risk management, as assessed by the Board of Directors at the time of their appointment.

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f) the proposals concerning the appointment, the removal and, consistent with the Company’s policies, the structure of the fixed and variable compensation of the Internal Audit Director, as well as on the adequacy of the resources provided to the latter to perform his duties, expressing the opinion required by internal regulations on the matter;

g) at least once a year, the Audit Plan prepared by the Internal Audit Director, expressing the opinion required by internal regulations on the subject (guidelines on Internal Audit activity - Internal Audit Charter);

h) the assessment of opportunities to adopt measures to ensure the effectiveness and impartiality of judgment of the Integrated Risk Management and Integrated Compliance units and of any other functions involved in the controls identified by the Board of Directors, as well as the annual verification that they are equipped with adequate professionalism and resources;

i) the choice relating to the attribution of supervisory functions pursuant to Legislative Decree no. 231/2001 and the composition criteria of the Watch structure pursuant to Legislative Decree no. 231/2001 which is reported in the Corporate Governance Report;

j) the exam of reports on the ICRMS, also following periodic meetings with the relevant structures of the Company;

k) investigations and examinations carried out by third parties regarding the internal control and risk management system; findings reported by the Audit Firm in any management letter it may issue and in the latter’s additional report which includes any opinions of the Board of Statutory Auditors. The additional report includes any opinions of the Board of Statutory Auditors;

l) the illustration, in the annual Corporate Governance Report, of the main features of the internal control and risk management system, and how the different subjects involved therein are coordinated, providing an indication of benchmark models as well as national and international best practices, and an evaluation of the overall adequacy of the system itself;

m) the adoption and amendment of the rules for the transparency and substantial and procedural correctness of transactions with related parties and those in which a Director or Statutory Auditor holds an interest, on his own or on behalf of third parties, expressing the opinion required by regulations, including internal ones, on the subject and carrying out the additional tasks assigned to it by the Board of Directors, also with reference to the examination and issue of an opinion on certain types of transactions, except for those relating to remuneration;

n) the proposal of the Chief Executive Officer for the definition of the principles concerning the coordination and information flows between the various parties involved in the ICRMS.

In addition, the Committee, in assisting the Board of Directors: a) evaluates, together with the Officer in charge of preparing financial reports and after having consulted the Audit Firm and the Board of Statutory Auditors, the proper application of accounting standards and their consistency in preparing the consolidated financial statements, issuing an opinion prior to their approval by the Board of Directors; b) examines and evaluates Reports prepared by the Officer in charge of preparing financial reports through which it shall give its opinion to the Board of Directors on the appropriateness of the powers and resources assigned to the Officer himself and on the proper application of accounting and administrative procedures, enabling the Board to exercise its tasks of supervision required by law; c) assesses whether the periodic non-financial information is suitable to correctly represent the Company’s business model, its strategies, the impact of its business and the performance achieved, expressing an opinion to the Board in coordination with the Sustainability and Scenarios Committee; d) examines the content of the periodic non-financial information relevant to the ICRMS; e) expresses opinions to the Board of Directors on specific aspects relating to the identification of the main corporate risks; f) on request of the Board, it supports, with adequate preliminary activities, the Board of Directors’ assessments and resolutions on the management of risks arising from detrimental facts which the Board may have become aware of and g) monitors the independence, adequacy, efficiency and effectiveness of the Internal Audit Department and oversees its activities with respect to the duties of the Board of Directors and the Chairman of the Board on its behalf, in this area, ensuring that they are performed with the necessary independence and required level of objectivity, competence and professional diligence, in accordance with the Code of Ethics of Eni SpA and international standards, as well as with the terms provided by the guidelines on Internal Audit activities (Internal Audit Charter).

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In particular, the Committee also: a) examines and evaluates, on the occasion of his/her appointment, whether the Internal Audit Director meets the integrity, professionalism, competence and experience requirements and, on an annual basis, assesses their fulfilment; b) examines the results of the audit activities performed by the Internal Audit Department and the periodic reports prepared by it containing adequate information on the activities carried out, on the manner in which risk management is conducted and on compliance with risk containment plans, as well as assessment of the appropriateness of the ICRMS . It also examines the reports promptly prepared by the Internal Audit Department on events of particular importance; c) examines the information received from the Internal Audit Department and promptly reports its assessment to the Board of Directors in the case of: (i) significant deficiencies in the system for preventing irregularities and fraudulent acts, and irregularities or fraudulent acts committed by management personnel or by employees who perform important roles in the design or operation of the ICRMS; and (ii) circumstances which may affect the maintenance of the independence of the Internal Audit Department and of auditing activities and d) may ask the Internal Audit Department to perform audits of specific operational areas, providing simultaneous notice to the Chairman of the Board of Directors, the CEO and the Chairman of the Board of Statutory Auditors, unless there are conflicts of interest.

The Committee also examines and assesses: a) communications and information received from the Board of Statutory Auditors and its members regarding the ICRMS, including those concerning the findings of enquiries conducted by the Internal Audit Department in connection with reports received (whistleblowing), including anonymous reports and b) half yearly reports issued by Eni’s Watch Structure, as well as the timely updates provided by the Structure, after the updates have been given to the Chairman of the Board and to the CEO, about any particular materiality or significant situation detected in the execution of its duty.

Furthermore, in case of judicial inquiries and proceedings, carried out in Italy and/or abroad, involving the CEO and/or the Chairman of Eni SpA and/or a member of the Board of Directors and/or an Executive reporting directly to the CEO, even if no longer in office, in relation to crimes against the Public Administration and/or corporate crimes and/ or environmental crimes, related to their duties and their scope of responsibility, in which the Board of Directors determines that the CEO may have an interest, pursuant to Article 2391 of the Civil Code, in order to ensure the independence of judgment of the Legal Department of the Company, in the interest of the same, the Board provides the Legal Department with the necessary information on its activities, with the support of the Committee. In particular, the Board avails itself of the Committee in order to ascertain the legal classification of the facts under investigation and proceedings, to acquire all necessary information on said investigations and proceedings from the legal department, to verify their completeness and accuracy, to be informed of the performance of such investigations and proceedings and to receive guidance to be provided to the legal department.

Nomination Committee

Members: Carolyn Adele Dittmeier (Chairman), Elisa Baroncini and Massimo Belcredi.

The Nomination Committee is made up of three non-executive Directors, all of whom independent.

In accordance with the By-laws and the Corporate Governance Code, the Committee assists the Board of Directors with preparatory, consultative and advisory functions on appointment and succession plans issues. More specifically, the Committee:

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a) assists the Board of Directors in formulating any criteria for the appointment of persons indicated in letter b) below, and of the members of the other boards and bodies of Eni’s associated companies;

b) provides evaluations to the Board of Directors on the appointment of executives and members of the boards and bodies of the Company and of its subsidiaries, proposed by the Chief Executive Officer and/or the Chairman of the Board of Directors, whose appointment falls under the Board’s responsibilities and oversees the associated succession plans. It supports the Board in the elaboration, update and implementation of the Chief Executive succession plan, by identifying, at least, the procedures to be followed in the event of an early termination of office;

c) upon a proposal of the Chief Executive Officer, examines and evaluates criteria governing the succession planning for the Company’s managers with strategic responsibilities;

d) assists the Board in the identification of candidates to serve as Directors in the event one or more positions need to be filled during the course of the year (Article 2386, first paragraph, of the Italian Civil Code), ensuring compliance with the requirements regarding the minimum number of independent Directors and the percentage reserved for the less represented gender, as well the representation of non-controlling interests;

e) proposes to the Board of Directors candidates for the position of Director to be submitted to the Shareholders’ Meeting of the Company, in the absence of proposals submitted by the shareholders, in the event it is not possible to draw the required number of Directors from the slates presented by shareholders;

f) with reference to the annual evaluation program on the performance of the Board of Directors and its Committees, in compliance with the Corporate Governance Code, it assists the Chairman of the Board of Directors in the activity attributed to it, of ensuring the adequacy and transparency of the self-assessment process of the Board; assists the Board in the preparatory work for the appointment of an external consultant and in the evaluation of the outcomes of the process. On the basis of the results of the self-assessment, the Committee supports the Board of Directors regarding the size and composition of the Board or its Committees, as well as, the skills and managerial and professional qualifications it feels should be represented within the same Board and Committees also in light of the industrial characteristics of the Company, taking into account the diversity criteria and the Board of Directors guidelines on the maximum number of positions a Director can hold in other companies, so that the Board itself can issue its guidelines to the shareholders prior to the appointment of the new Board;

g) assists the outgoing Board in the proposition of the slate of candidates for the position of Director to be submitted to the Shareholders’ Meeting if the Board decides to opt for the process envisaged in Article 17.3 (1) of the By-laws, ensuring the transparency of the process leading to the slate’s structure and proposition;

h) in compliance with the Corporate Governance Code, proposes to the Board of Directors guidelines regarding the maximum number of positions of Director or Statutory Auditor that a Company Director may hold and performs the preliminary activity for the associated periodic checks and evaluations for submission to the Board;

i) periodically verifies that the Directors satisfy the independence and integrity requirements, and ascertains the absence of circumstances that would render them incompatible or ineligible, at least on an annual basis and upon the occurrence of circumstances relevant to independence;

j) provides its opinion to the Board of Directors on any activities carried out by the Directors, which are in competition with the Company.

The preliminary examination of corporate affairs or governance issues is carried out jointly with the Director Corporate Affairs and Governance, who, in this case, participates in the Committee meetings.

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Sustainability and Scenarios Committee

Members: Federica Seganti (Chairman), Elisa Baroncini and Roberto Ciciani.

The Sustainability and Scenarios Committee is made up of three non-executive Directors, a majority of whom are independent pursuant to Corporate Governance Code; all Directors are independent pursuant to law.

The Committee assists the Board of Directors with preparatory, consultative and advisory functions on scenarios and sustainability issues, i.e. the processes, projects and activities aimed at ensuring the Company’s commitment to sustainable development along the value chain, particularly with regard to: climate transition and technological innovation; access to energy, energy sustainability; environment and energy efficiency; local development, particularly economic diversification, health, well- being and safety of people and communities; respect and protection of rights, particularly of the human rights; integrity and transparency; diversity and inclusion.

More specifically, in its preparatory, consultative and advisory function towards the Board of Directors, the Committee:

a. examines scenarios for the preparation of the Strategic Plan, giving its opinion to the Board of Directors;

b. examines and evaluates climate transition issues, i.e. decarbonisation at both operational and product portfolio level, technological innovation, green chemistry and circular economy, aimed at ensuring the creation of value over time for shareholders and all other stakeholders;

c. examines and evaluates other aspects of the sustainability policy, in accordance with the principles of sustainable development, as well as sustainability strategies and objectives;

d. monitors the Company’s position in terms of sustainability with regard to financial markets, particularly with regard to annual reporting on new sustainable finance tools, as well as the Company’s inclusion in the leading sustainability indexes;

e. examines and evaluates the sustainability report submitted annually to the Board of Directors;

f. monitors international sustainability projects as part of global governance processes and the Company’s participation in such projects, designed to strengthen the Company’s international leadership;

g. examines and assesses local sustainability initiatives, including in relation to individual projects, provided for in agreements with producer countries, submitted by the CEO for presentation to the Board;

h. examines how the local sustainability policy is implemented in business initiatives, on the basis of indications provided by the Board of Directors;

i. examines the Company’s non-profit strategy and its implementation, including in relation to individual projects, through the non-profit plan submitted each year to the Board, as well as non-profit initiatives submitted to the Board;

j. at the request of the Board, gives its opinion on other sustainability issues;

k. in agreement with the Chief Executive Officer, evaluates the opportunity of organizing open Committee meetings, possibly including other directors, with institutional stakeholders, to listen to their point of view with reference to the issues falling within the competence of the Committee;

l. coordinates with the Control and Risk Committee in assessing the suitability of periodic non-financial information, to correctly represent the business model, the strategies of the company, the impact of its activity and the performance achieved.

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Boa r d of Statutory Auditors

Name |  | Position |  | Year first appointed to Board of Statutory Auditors
Rosalba Casiraghi |  | Chairman |  | 2017
Enrico Maria Bignami |  | Auditor |  | 2017
Marcella Caradonna |  | Auditor |  | 2021
Giulio Palazzo |  | Auditor |  | 2023
Andrea Parolini(1) |  | Auditor |  | 2023
Giulia De Martino |  | Alternate |  | 2023
Giovanna Villa |  | Alternate |  | 2023

(1) Andrea Parolini was also Standing Auditor of Eni SpA from April 13, 2017 to May 13, 2020.

The current Eni’s Board of Statutory Auditors, composed of five standing members and two substitute members, was appointed by the shareholders on May 10, 2023 for three years, until the date of the Ordinary Shareholders’ Meeting convened for approval of financial statements for the year ending December 31, 2025. The Standing Statutory Auditors Marcella Caradonna, Giulio Palazzo, Andrea Parolini and the Alternate Auditor, Giulia De Martino were elected from the slate submitted by the Ministry of Economy and Finance (the “majority slate”); Rosalba Casiraghi, appointed Chairman of the Board of Statutory Auditors, the Standing Statutory Auditor, Enrico Maria Bignami and the Alternate Auditor, Giovanna Villa were elected from the slate presented by non-controlling shareholders (the “minority slate”).

The Auditors are appointed by means of a slate voting system: the minimum holding required to submit a slate for the election of the Statutory Auditors was equal (in 2023) to 0.5% of share capital. Two standing Statutory Auditors and one Alternate Auditor are selected from among the candidates of the non-controlling shareholders. The Chairman of the Board of Statutory Auditors is appointed by the Shareholders’ Meeting from among the Auditors chosen by the non-controlling shareholders.

In accordance with the provisions designed to ensure gender balance, two Statutory Auditors were drawn from the less represented gender.

The Auditors must satisfy the independence, professional and integrity requirements established by Italian regulations. Article 28 of the By-laws specifies that the professionalism requirements may be fulfilled by having at least three years’ experience in: (i) professional or teaching activities pertaining to commercial law, business economics and corporate finance, or (ii) experience in executive positions in the fields of engineering and geology. U.S. regulations for Audit Committees require that at least one member of the Board of Statutory Auditors be a financial expert and have adequate knowledge of the functions of the Audit Committee and experience in the analysis and application of generally accepted accounting standards, the preparation and auditing of Financial Statements and internal control processes. The Board of Statutory Auditors, acting as the Internal Control and Financial Auditing Committee pursuant to Legislative Decree no. 39/2010 (Consolidate Law on Statutory Audits of annual accounts and consolidated accounts), must satisfy the requirement imposed by Art. 19 of that law, providing that “the members of the internal control and financial auditing committee, as a body, are competent in the sector in which the company being audited operates”. In addition, the Corporate Governance Code Eni has adopted, also recommends that all members of the Board of Statutory Auditor possess the independence requirements envisaged for Directors. Compliance with those criteria is verified by the Board of Statutory Auditors itself.

Pursuant to the Consolidated Law on Financial Intermediation, the Board of Statutory Auditors monitors: (i) compliance with the law and the Company’s By-laws; (ii) observance of the principles of sound administration; (iii) the appropriateness of the Company’s organizational structure for matters within the scope of the Board’s Authority, the adequacy of the internal control system and the administrative and accounting system and the reliability of the latter in accurately representing the Company’s transactions; (iv) the procedures for implementing the Corporate Governance rules provided for in the Corporate Governance Code, which the Company has adopted; and (v) the adequacy of the instructions imparted by the Company to its subsidiaries, in order to guarantee full compliance with legal reporting requirements.

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In addition, pursuant to Article 19 of Legislative Decree No. 39/2010, in its role as the “internal control and financial auditing committee” the Board of Statutory Auditors: a) informs the Board of Directors of the conclusion of the statutory audit and the outcome of the sustainability reporting certification activity and transmits to the Board the “additional report” of the audit firm adding proper evaluation if deemed necessary; b) oversees the financial reporting process and the corporate sustainability reporting as well as presents recommendations to ensure its integrity; c) controls the effectiveness of internal quality control system and Risk Management, the effectiveness of internal audit, with reference to the financial reporting process and to the corporate sustainability reporting, without violating its independence; d) oversees the statutory audit of annual accounts and consolidated accounts and the sustainability reporting certification activity, also considering results of quality control of the audit activity performed by the public authority responsible for regulating the Italian financial markets; e) verifies and monitors the independence of the audit Firm and of the Firm that carries out the certification activity of sustainability reporting with particular reference to non-audit services; f) is responsible of the procedure to select the audit Firm, making a recommendation to the Shareholders’ Meeting for the appointment of the audit Firm.

The responsibilities assigned under the Legislative Decree No. 39/2010 to the “internal control and financial auditing committee”, with reference to the statutory auditing, are consistent and substantively in line with the duties already assigned to the Board of Statutory Auditors of Eni, with specific consideration of its role as Audit Committee pursuant to the “Sarbanes-Oxley Act” (discussed in greater detail below).In accordance with law, the Board of Statutory Auditors presents the results of its supervisory activity in a report to the Shareholders Meeting. This report is made available in its entirety to the public within the time limits applicable to the Financial Statements.

On March 22, 2005, the Board of Directors, electing the exemption granted by the SEC applicable to foreign issuers listed on the regulated U.S. markets, designated the Board of Statutory Auditors as the body that, as of June 1, 2005, would perform, to the extent permitted under Italian regulations, the functions attributed to the Audit Committee of foreign issuers by the Sarbanes-Oxley Act and SEC rules. On June 15, 2005, the Board of Statutory Auditors approved the internal rules, later updated, concerning its performance of the duties assigned to it under that U.S. legislation, the text of which is available on Eni’s website. The key functions performed by the Board of Statutory Auditors acting as an audit committee as provided for by the SEC include:

● | evaluating the offers submitted by external Auditors for their engagement and providing a reasoned recommendation to the Shareholders’ Meeting concerning the engagement or removal of the external Auditor;
● | overseeing the work of the external Auditor engaged to audit the accounts or perform other audit, review or certification services;
● | examining the periodical reports from the external auditor relating to: a) all critical accounting policies and practices to be used; b) all alternative treatments of financial information within generally accepted accounting principles that have been discussed with management officials of the Company, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor; and c) other material written communication between the external auditor and management;
● | making recommendations to the Board of Directors on the resolution of disagreements between management and the auditor regarding financial reporting.

In addition the Board of statutory auditor:

● | approves the procedures for: a) the receipt, retention, and treatment of complaints received by the Company regarding accounting, internal accounting controls, or auditing matters; and b) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters;
● | examines reports from the CEO and the Head of Eni’s Accounting and Financial Statements concerning: i) any significant deficiency in the design or operation of internal controls which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information and any material weakness in internal controls; and ii) any fraud that involves management or other employees who have a significant role in the Company’s internal controls.

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The Board of Statutory Auditors, in the performance of its duties, is supported by the Company’s departments, in particular the Internal Audit Department and the Administrative and Financial Statement Department.

231 Supervisory Body and Model 231

In accordance with the Italian regulations concerning the “administrative liability of legal entities deriving from criminal offences”, contained in Legislative Decree No. 231 of June 8, 2001 (henceforth, “Legislative Decree No. 231/2001”), legal entities, including corporations, may be held liable – and consequently fined or subject to prohibitions – in relation to certain crimes attempted or committed in Italy or abroad in the interest or for the benefit of the Company by individuals in high-ranking positions and/or persons managed or supervised by an individual in a high ranking position. The companies may, in any case, adopt organizational, management and control models designed to prevent these crimes. With respect to this issue, Eni Board of Directors – in its Meetings of December 15, 2003 and January 28, 2004 – approved an organizational, management and control model pursuant to Legislative Decree No. 231 of 2001 (Model 231) and created the 231 Supervisory Body. Moreover, as a result of changes in the Italian legislation governing the matter and in the Company’s organizational structure, on March 14, 2008, the Board of Directors updated Model 231 and adopted Eni’s Code of Ethics – replacing the previous version of the Eni Code of Conduct of 1998 – which represents a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all business activities are conducted in compliance with laws, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all stakeholders with which Eni interacts on an ongoing basis. These include shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the countries where Eni operates. Since its first adoption, Model 231 has been updated very frequently, in most cases in response to new provisions of law coming into force as well as to organizational changes in the company’s structure. Most recently, the Board of Directors, in its meeting of June 26, 2025 approved the updating of General Part of Model 231.

Italian Legislative decree no. 231/2001 has established companies’ liability for crimes committed by their managers and employees in performing their job tasks, because allegedly committed on behalf of a company. Companies are not liable in case they prove that they have adopted effective internal control systems designed to prevent wrongdoing by their managers and employees. The rule covers several types of offences, including offences against the public administration, corruption, environmental crimes, human rights violations, money laundering, data privacy violation and cybersecurity crimes, misleading financial statements, organized crimes, and crimes related to terrorism and insurgency.

Furthermore, the Board of Directors, in its meeting of March 18, 2020, approved the new version of Eni’s Code of Ethics; the new Code sets out the fundamental principles of Eni’s Model 231 which is one of the pillars of Eni “regulatory system” and inspires it.

At present, the 231 Supervisory Body is composed of three external members, one of which with the role of Chairman as well as by the Chairman of the Board of Statutory Auditors and the Director of Internal Audit, as internal members. External members are independent professionals, experts in law and/or economic matters.

Audit Firm

The auditing of the Company’s accounts is entrusted, in accordance with the law, to an independent Audit Firm appointed by the Shareholders’ Meeting on the basis of a reasoned recommendation of the Board of Statutory Auditors.

In addition to the obligations set forth in national auditing regulations, Eni’s listing on the New York Stock Exchange requires that the Audit Firm issues a report on the Annual Report on Form 20-F, in compliance with the auditing principles generally accepted in the United States. Moreover, the Audit Firm is required to issue an opinion on the efficacy of the internal control system applied to financial reporting. The financial statements of Eni’s subsidiaries generally are subject to auditing by Eni’s Audit Firm. Acting on the Board of Statutory Auditors’ reasoned proposal, the Shareholders’ Meeting of May 10, 2018 approved the engagement of PricewaterhouseCoopers SpA to perform the external statutory audit of the accounts of the Company and the audit of the internal control system over financial reporting, pursuant to U.S. law, for the period 2019 – 2027.

Court of Auditors (Corte dei Conti)

The financial management of Eni is subject to the control of the Italian Court of Auditors in order to preserve the integrity of the public finances. This task has been carried out by the Magistrate of the Court of Auditors, Giovanni Coppola, on the basis of the resolution approved in November 7-8, 2023, by the Presidential Council of the Court of Auditors.

The Magistrate of the Court of Auditors attends the meetings of the Board of Directors and of the Board of Statutory Auditors.

Empl oy ees

As of December 31, 2025, Eni had a total of 32,349 empl o yee s, with a decrease of 143 empl o yee s (-0.4% compared to December 31, 2024), which mainly reflects a decrease of 94 employees working in Italy and 49 employees working abroad.

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The overall 2025 headcount remains substantially aligned with the end 2024 figures mainly due to divestments activities outside Italy following the portfolio optimizations, partly offset by a slightly positive balance between hirings and terminations.

| 2025 |  | 2024 |  | 2023
|  |  | (number) |  |
Exploration & Production | 9,141 |  | 9,188 |  | 9,840
Global Gas & LNG Portfolio and Power | 1,077 |  | 1,151 |  | 1,130
Enilive and Plenitude | 6,064 |  | 5,899 |  | 5,759
Refining and Chemicals | 10,117 |  | 10,060 |  | 10,449
Corporate and Other activities | 5,950 |  | 6,194 |  | 5,964
| 32,349 |  | 32,492 |  | 33,142

The table below sets forth Eni’s employees’ distribution as of December 31, 2023, 2024 and 2025 in Italy and outside Italy:

|  | 2025 |  | 2024 |  | 2023
|  |  |  | (number) |  |
Exploration & Production | Italy | 4,040 |  | 4,017 |  | 3,913
| Outside Italy | 5,101 |  | 5,171 |  | 5,927
|  | 9,141 |  | 9,188 |  | 9,840
Global Gas & LNG Portfolio and Power | Italy | 741 |  | 765 |  | 740
| Outside Italy | 336 |  | 386 |  | 390
|  | 1,077 |  | 1,151 |  | 1,130
Enilive and Plenitude | Italy | 3,937 |  | 3,827 |  | 3,656
| Outside Italy | 2,127 |  | 2,072 |  | 2,103
|  | 6,064 |  | 5,899 |  | 5,759
Refining and Chemicals | Italy | 7,617 |  | 7,559 |  | 7,702
| Outside Italy | 2,500 |  | 2,501 |  | 2,747
|  | 10,117 |  | 10,060 |  | 10,449
Corporate and other activities | Italy | 5,671 |  | 5,932 |  | 5,738
| Outside Italy | 279 |  | 262 |  | 226
|  | 5,950 |  | 6,194 |  | 5,964
Total | Italy | 22,006 |  | 22,100 |  | 21,749
| Outside Italy | 10,343 |  | 10,392 |  | 11,393
|  | 32,349 |  | 32,492 |  | 33,142
of which senior managers |  | 896 |  | 945 |  | 960

We seek to maintain constructive relationship with labor unions.

Share ownership

As of February 25, 2026, the cumulative number of shares owned by Eni’s Directors, Statutory Auditors and Senior Managers was 1,674,249 less than 0.1% of Eni’s share capital outstanding as of the same date. Eni issues only ordinary shares, each bearing the right to one-vote; therefore shares held by those persons have no different voting rights. The breakdown of share ownership for each of those persons is provided below.

Name | Position | Number of shares owned |
Board of Directors |  |  |
Claudio Descalzi | CEO | 647,621 |
Senior Managers (a) |  | 1,026,628 | (1)

(a) Members of the Management Committee at December 31, 2025.
(1) No. 16,823 shares owned by spouses not legally separated and by underage children.

Employees’ involvement in the capital of the Company In 2024, based on a Shareholders’ resolution of May 15, 2024, Eni has adopted an Employee Stock Ownership Plan 2024-2026, which has been initially implemented for employees in Italy and is expected to be gradually extended to foreign subsidiaries, with the aim of strengthening employees’ retention to the Company and their participation in the growth of corporate value, in line with the interests of the shareholders.

Under the Plan granting two annual award (in 2024 and 2025) of free for no consideration with an annual individual monetary value of €2,000, with a three-year lock-up period, a total of 3,289,345 and 3,102,700 shares were issued respectively in November 27, 2025 and November 27, 2024. In 2026, a co-investment model will be implemented whereby, upon the employee's purchase of shares, free shares will be granted equal to 50% of the shares purchased, up to a maximum value of €1,000.

At the grant date (November 27, 2024), a total of 3,102,700 shares were issued.

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Item 7. MAJOR SHAREHOLDERS AND RELATED P A R TY TRANSACTIONS

Major Shareholders

The Ministry of Economy and Finance controls Eni as a result of the shares directly owned and those indirectly owned through Cassa Depositi e Prestiti SpA (CDP), in which the Ministry of Economy and Finance holds a 82.77% stake.

As of March 11, 2026, the total amount of Eni’s voting securities owned, either directly or indirectly, by persons that have notified that their holding exceeds the threshold of 3%11 pursuant to Article 120 of the Legislative Decree No. 58/1998 and to the Consob Regulation No. 11971/1999 and, in any case, by controlling shareholders, was:

Title of class |  | Number of shares owned |  | Percent of class
Ministry of Economy and Finance |  | 65,586,402 |  | 2,166
Cassa Depositi e Prestiti SpA |  | 936,179,478 |  | 30,918
Romano Minozzi 12 |  | 97,351,116 |  | 3,215
BlackRock, Inc.13 |  | 150,878,955 |  | 4,983

As of March 11, 2026, the percentage of Eni’s treasury shares was equal to 2.87% of the share capital 14.

In relation to the Italian legislation g o verning the special powers of the Italian State see “Item 10 – A d dition a l information – Limitations on changes in cont r ol of the Company (Special Powers of the Italian State)”.

As of March 11, 2026, there were 25,216,014 ADRs outstanding, each representing two Eni ordinary shares, corresponding to approximately 1.7% of Eni’s share capital. See “Item 9 – The offer and the listing”.

Related parties transactions

In the ordinary course of its business, Eni enters into transactions concerning the exchange of goods, provision of services and financing with associates, joint ventures, joint operations or other affiliates, as well as other companies owned or controlled by the Italian Government. All such transactions are conducted in the interest of Eni Group companies 15.

Amounts and types of trade and financial transactions with related parties and their impact on consolidated earnings and cash flow, and on the Group’s assets and financial condition are reported in “Item 18 – Note 36 to the Consolidated Financial Statements”.

11 Major holdings pursuant to Article 120 of the Legislative Decree No. 58/1998 are updated also on the basis of communication made by intermediaries pursuant to Article 83-novies of the Legislative Decree No. 58/1998 in order to exercise the corporate rights.
12 It refers to the notification pursuant to Article 120 of the Legislative Decree No. 58/1998 made by Mr. Minozzi on May 7, 2025. The percentage in the table has been updated in consideration of the change in Eni shares representative of the share capital due to the cancellation of no. 118,782,928 treasury shares executed on March 4, 2026 in accordance to the resolution of the Shareholders’ Meeting of May 14, 2025.
13 It refers to the notification pursuant to Article 120 of the Legislative Decree No. 58/1998 made by Blackrock, Inc. on March 11, 2026. On December 22, 2025, BlackRock, Inc. notified to the Company and Consob, pursuant to Article 119, paragraphs 1 and 2 of the Consob Regulation No. 11971/1999 regarding holdings of financial instruments and aggregate holdings, the following holdings through 17 controlled management companies: holding of voting shares: 4.798%; potential holding: 0.159%; other long positions with cash settlement: 0.046%. 14 Eni's Board of Directors approved the start of the buy-back program for 2025 in execution of the authorization granted by the Shareholders Meeting held on May 14, 2025. Purchases started on May 20, 2025 and terminated on February 18, 2026. Following the purchases made until the termination of the buy-back program for the year 2025, considering the treasury shares already held and the free of charge shares granted to Eni’s employees (as provided by the “Long-Term Incentive Plan 2020-2022” approved by Shareholders’ Meeting of May 13, 2020, and by the “Employee Stock Ownership Plan” approved by Eni’s Shareholders’ Meeting of 15 May 2024), Eni held n. 205,610,942 shares equal to 6.53% of the share capital. Following the cancellation of no. 118,782,928 treasury shares made on the basis of the authorization granted by the Shareholders’ Meeting held on May 14, 2025 and executed on March 4, 2026, Eni holds no. 86,828,014 treasury shares. 15 For more details on internal rules on related parties transactions, please refer to Item 10, paragraph “Interests in Company’s transactions”.

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Item 8. FINANCIAL INFORMATION

Consolidated Statements and other financial information

See “Item 18 – Financial Statements”.

Legal proceedings

Eni is a party in a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business. Based on information available to date, and taking into account existing risk provisions and that in some instances it is not possible to make a reliable estimate of any contingency losses, Eni believes that these legal proceedings will likely not have a material adverse effect on the Group Consolidated Financial Statements.

A description of the most significant proceedings currently pending is provided in “Item 18 – Note 28 to the Consolidated Financial Statements”. Generally, and unless otherwise indicated, these legal proceedings have not been provisioned because Eni believes that an unfavorable outcome is unlikely or because the amount of the provision cannot be estimated reliably.

Dividends and remuneration policy

Management is committed to delivering on a progressive and competitive shareholder remuneration policy, that is reflective of the expected improvement in underlying earnings and cash flows on a constant scenario basis and of the increased resiliency of the business to cyclical fluctuations. In setting the level of shareholders’ remuneration, management is also considering its assumptions about future trends in crude oil prices and in other market variables.

As part of that framework, management is planning to return shareholders an amount of cash representing a portion in a range of 35 to 45% of the expected cash flow from operations before working capital requirements “adjusted cash flow”. That portion is higher than the previous range of 35-40% to take into account a perceived solid financial structure of the Company, lower expected expenditures than in the past and a growing contribution of dividends from equity-accounted entities to the cash flow. In 2025, management gauged this adjusted cash flow measure at around €12.5 billion and cash returns to shareholders came in close to the upper limit of that range as we returned €5 billion of cash to shareholders comprising the 2025 dividend of €1.05 per share (equal to €3.15 billion, with the third and fourth instalments to be distributed in the first half 2026) and the 2025 buy-back program of €1.8 billion, which was completed in February 2026.

Going forward, distributions will continue contemplating a combination of dividends and share repurchases. We expect to gradually increase the dividend in future years in line with the expected improvement in the Group underlying financial performance, and to enhance the dividend resilience to the scenario. Share repurchases will complement the dividend and are intended as a flexible tool to distribute raising amount of cash generated by the business in case of upside in the scenario variables, a better than budgeted company’s performance or other factors. For the full year 2026, we expect to distribute shareholders an amount equal to 40% of the adjusted cash flow which will be earned by the Company under the assumption of 70 $/bbl of Brent crude oil (nominal terms) through dividends and share repurchases.

According to our financial framework, in case the Group results of operations are trending higher than management’s plans due to a better pricing environment than management expectations (i.e. a Brent crude oil price higher than 70 $/bbl) and/or an improved business underlying performance, management intends to distribute up to 60% of the incremental cash flows through share repurchases (in line with the past), until management’s expected Brent crude oil price for the full year reaches 90 $/bbl on average. In case management’s forecast of the Brent crude oil price exceeds 90 $/bbl for 2026 full year, the Company intends to distribute shareholders 100% of the incremental adjusted cash flow at a Brent price higher than 90 $/bbl and/or other scenario variables 50% above planned levels (namely spot natural gas prices and refining margins) as extraordinary dividend.

In case the commodity scenario underperforms management’s expectations, the Company plans to leverage on its financial flexibility as well as on possible revisions of the capital expenditure plans considering the proportion of uncommitted projects in our development portfolio, to preserve shareholders’ returns.

For 2026, having assessed the progress of the Company in executing its strategy, based on a sound financial position and management scenario assumptions, management is planning to increase the yearly dividend to €1.10 per share, up 4.8% from 2025. This dividend is expected to be paid in four equal quarterly instalments in September 2026, November 2026, March 2027, and May 2027. Therefore, the expected cash out for dividend payments in 2026 will include two instalments of the 2025 dividend of €0.26 per share each, and two instalments of the planned 2026 dividend of €0.27 per share each.

Consistently with its remuneration policy, for 2026 Eni plans to execute a share buyback program of at least €1.5 billion assuming a Brent scenario of 70 $/bbl and that the Company delivers its planned adjusted cash flow for the year. Execution of this buyback program is subject to shareholders’ approval at the Annual General Meeting scheduled for May 2026. In case of a better oil price environment and/or better business underlying performance, the buyback is expected to be increased to an upper limit of €4 billion.

Significant changes

See “Item 5 – Recent developments and Management’s expectations of operations” for a discussion of significant subsequent business developments and transactions occurred after the closing date up to the latest practicable d a te.

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Item 9. THE OFFER AND THE LISTING

Offer and listing details

The principal trading market for the ordinary shares of the Company (the “Shares”) is the Euronext Milan (“EXM”). EXM, which is the principal trading market for shares in Italy, is a regulated market organized and managed by Borsa Italiana SpA (“Borsa Italiana”).

Eni’s American Depositary Receipts (“ADRs, and each an “ADR”), each representing two Shares, are listed on the New York Stock Exchange, under the trading symbol “E”. Since June 27, 2017, Citibank N.A. (the “Depositary”) acts as the company’s depositary bank issuing ADRs pursuant to a deposit agreement (the “Deposit Agreement”) entered into among Eni, the Depositary, some beneficial owners (the “Beneficial Owners”) and registered holders from time to time of the ADRs issued hereunder.

As of March 4, 2026, there were 25,216,014 ADRs outstanding, representing 50,432,028 ordinary shares or approximately 1.67% of all Eni’s share capital, held by 110 holders of record (including the Depository Trust Company) in the United States, all of which are U.S. residents. Since a number of ADRs are held by nominees, the number of holders may not be representative of the number of Beneficial Owners in the United States or elsewhere.

In Italy, the Shares are included in the FTSE MIB Index (the “FTSE MIB”), the primary benchmark index for the Italian Stock Exchange. Capturing approximately 80% of the domestic market capitalization, the FTSE MIB measures the performance of 40 highly liquid, leading companies across leading industries listed on EXM and the Euronext MIV Milan (“MIV”) and seeks to replicate the broad sector weights of the Italian Stock Exchange. The FTSE MIB is market cap-weighted after adjusting constituents for free float.

A two-day rolling cash settlement applies to all trades of equity securities on Borsa Italiana.

Borsa Italiana reports daily market data and news for each listed security, including volume traded and high and low prices. For the purposes of the automatic control of the regularity of trading, the regulations of Borsa Italiana define certain price variation limits (established in the “Guide to the Parameters” for trading on the regulated markets organized and managed by Borsa Italiana and available on its website). Where the price of a contract that is being concluded exceeds one of those limits, trading in that security will be automatically suspended and a reservation phase begun.

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Markets

Consob is the public authority responsible for regulating and supervising the Italian financial markets to, inter alia, ensure the transparency and regularity of the dealings and protect the investing public. Borsa Italiana, which is part of Euronext, following the acquisition effective April 29, 2021, is a joint stock company authorized by Consob to operate, among the others, regulated markets in Italy. It is responsible for the organization and management of the Italian Stock Exchange. One of the fundamental characteristics of the financial market organization in Italy is the separation of the supervisory tasks (to be performed by Consob and the Bank of Italy) from the tasks relating to market management (to be performed by Borsa Italiana). The main responsibilities of Borsa Italiana are the admission, exclusion and suspension of financial instruments and intermediaries to and from trading as well as the surveillance of the markets.

According to Consob regulations, Borsa Italiana has issued rules governing the organization and management of the Italian Regulated Markets it is responsible for. Such regulated markets are, by way of example, EXM (shares, convertible bonds, pre-emptive rights, warrants), ETFplus (Exchange Traded Funds, Exchange Traded Commodities, Exchange Traded Notes, Structured ETFs and Actively managed ETFs), IDEM (futures and options contracts whose underlying assets are financial instruments, interest rates, foreign currencies, goods or related indexes), MOT (bond market) and MIV (market for investment vehicles), as well as the admission to listing on and trading on these markets.

According to the regulatory framework introduced by: (i) Markets in Financial Instruments Directive No. 2014/65/EU as amended from time to time (“MiFID II”) and as implemented in Italy, (ii) Regulation (EU) No. 600/2014 (“MiFIR”), applicable from January 3, 2018 as amended from time to time, as well as (iii) Consob regulations, orders can be routed not only to Regulated Markets but also to either Multilateral Trading Facilities (MTFs) or Systematic Internalisers. A MTF is a multilateral system, operated by an investment firm or a market operator, which brings together multiple third-party buying and selling interests in financial instruments — in the system and in accordance with non-discretionary rules — in a way that results in a contract. A Systematic Internaliser is an investment firm which, on an organized, frequent, systematic and substantial basis, deals on own account when executing client orders outside a Regulated Market, an MTF or an Organized Trading Facility (“OTF”) without operating a multilateral system. Following the transposition in Italy of MiFID II and the application of MiFIR, OTFs are now included among the “trading venues” that are subject to regulation.

An OTF is a multilateral system which is not a Regulated Market or an MTF and in which multiple third-party buying and selling interests in bonds, structured finance products, emission allowances or derivatives are able to interact in the system in a way that results in a contract.

According to Italian Legislative Decree No. 58 of February 24, 1998, as amended from time to time (“Decree No. 58”, the Consolidated Law on Financial Intermediation), the provision of investment services and activities to the public on a professional basis is, inter alia, reserved to investment firms, EU investment companies, Italian banks, EU banks and companies of non-EU countries authorized to operate in Italy (“Authorized Persons”). The Bank of Italy and Consob shall exercise supervisory powers over authorized persons. They shall each supervise the observance of regulatory and legislative provisions according to their respective responsibilities. In particular, in connection with the pursuance of the safeguarding of faith in the financial system, the protection of investors, the stability and correct operation of the financial system, the competitiveness of the financial system and the observance of financial provisions, the Bank of Italy shall be responsible for risk containment, asset stability and the sound and prudent management of intermediaries whilst Consob shall be responsible for the transparency and correctness of conduct. Besides, for the purposes of the application of certain provisions of MiFIR, the Bank of Italy and Consob are the Italian competent authorities. In particular, Consob, as far as the protection of the investors is concerned, is competent for the orderly functioning and soundness of the financial markets or of the commodity markets whereas the Bank of Italy is competent for the stability of the whole (or part of) the financial system.

The Bank of Italy and Consob also regulate the functioning of the clearing and settlement service for transactions involving financial instruments as well as the performance of central securities depository services, in line with the European framework — in particular, Regulation (EU) No. 648/2012 as amended by Regulation EU n. 2019/834, as amended from time to time, (“EMIR REFIT”) and the Regulation (EU) No. 909/2014, as amended from time to time, (“Central Securities Depositories Regulation”). The regulations and measures of general application adopted by Consob and the Bank of Italy are respectively available on the website of Consob or Bank of Italy.

The regulations adopted by Borsa Italiana are available on its website.

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Item 10. ADDITIONAL INFORMATION

Memorandum and Articles of Association

Company register

“Eni SpA” is the company resulting from the privatization of Ente Nazionale Idrocarburi, a public agency, established by Law No. 136 of February 10, 1953, and it is registered in the Rome Companies Register, with identification number (and tax number) 00484960588, and VAT number 00905811006. The Company’s registered office is in Rome, Italy, and the Company has two offices in San Donato Milanese (Milan).

The full text of Eni’s By-laws is attached as an exhibit to this Annual Report (“Exhibit 1”).

Company objects and purpose

In accordance with Article 4 of Eni’s By-laws, the Company’s purpose includes the direct and/or indirect exercise, through equity holdings in companies or other entities of: activities in the field of hydrocarbons and natural gases, in compliance with the terms of concessions provided for by law; activities in the field of chemicals, nuclear fuels, geothermal energy, renewable energy sources and energy in general, including the sale of electricity, in the design and construction of industrial plants, in the mining industry, in the metallurgy industry, in the textile machinery industry, in the water sector, including water diversion, potabilization, purification, distribution and reuse; in the environmental protection sector and in the treatment and disposal of waste, as well as any other economic activity that is instrumental, ancillary or complementary to the aforementioned activities. The Company performs and manages the technical and financial coordination of subsidiaries and associated companies and provides financial assistance to them. Moreover, the Company may acquire equity holdings and interests in other companies or enterprises with corporate purposes that are similar, related or complementary to its own or those of companies in which it has equity holdings, either in Italy or abroad, and it may provide secured and/or unsecured guarantees for its own and others’ obligations, including, in particular, sureties.

Directors’ issues

Eni’s Board of Directors is invested with the fullest powers for the ordinary and extraordinary management of the Company and, in particular, the Board has the power to perform all acts it deems advisable for the implementation and achievement of the corporate purpose, with the sole exception of acts that the law or Eni’s By-laws reserve to the Shareholders’ Meeting. If the Shareholders’ Meeting has not appointed a Chairman of the Board, the Board shall elect one from among its members.

The Board of Directors appoints a Chief Executive Officer and delegates to him all necessary powers for the management of the Company, with the exception of those powers that cannot be delegated in accordance with current legislation and those retained exclusively by the Board of Directors on matters regarding major strategic, operational and organizational decisions. According to Eni’s By-laws, the Board of Directors may delegate powers to the Chairman to identify and promote integrated projects and international agreements of strategic importance.

The Board of Directors may at any time revoke the powers delegated, proceeding, in the case of revocation of the powers delegated to the Chief Executive Officer, to appoint another Chief Executive Officer at the same time.

The Board of Directors, acting upon a proposal of the Chairman and in agreement with the Chief Executive Officer, may confer powers for individual acts or categories of acts on other members of the Board of Directors.

In accordance with Eni’s By-laws, for a Board meeting to be valid, a majority of serving Directors must be present. Resolutions shall be approved by a majority of the votes of the Directors present; in the event of a tie, the person who chairs the meeting shall have a casting vote.

For further information on Directors’ duties and responsibilities and, in particular, the role of the Chairman see “Item 6 — Board of Directors’ duties and responsibilities”.

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Interests in Company’s transactions

As provided by the Italian Civil Code, when a Director retains a personal interest or an interest on behalf of third parties in Company transactions, he shall disclose it to the Board of Directors and to the Board of Statutory Auditors, specifying the nature, terms, origin and extent of such interest. Based on this provision and in compliance with the Consob (“Commissione Nazionale per le Società e la Borsa” is the public authority responsible for regulating the Italian financial markets) regulation on transactions with related parties (the “Consob Regulation”), the Board of Directors — on November 18, 2010 — unanimously approved the internal rules on “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties”, which has been in effect from January 1, 2011 15 to ensure the transparency and substantial and procedural fairness of transactions with related parties and with parties that are of interest to Eni’s Directors and Statutory Auditors, carried out by Eni itself or its subsidiaries. These rules, lastly approved by the Board of Directors on November 16, 2023 16 - mainly in order to adapt them to the principles of the new Eni Regulatory System (assuming the format of a Policy) and to take into account the application experience and from a risk-based perspective - received the preliminary favorable opinion, expressed unanimously, of the Control and Risk Committee, composed entirely of independent Directors as per the requirements set out in the Corporate Governance Code, which Eni has adopted, and in accordance with the Consob Regulation. The Policy sets out monitoring and evaluation requirements for the preliminary phase and for carrying out a transaction with a party in which a Director or Statutory Auditor has an interest. In this regard, both in the preliminary and deliberation phase, a thorough, documented examination of the reasons for the transaction, highlighting the Company’s interest in carrying it out and the soundness and fairness of the underlying terms, is required. Directors involved in matters subject to Board resolution normally shall not participate in the relevant discussion and decision and shall leave the room during these procedures. If the person involved is the Chief Executive Officer and the transaction falls under his duties, he shall in any case abstain from taking part in the transaction and shall entrust the matter to the Board of Directors (as provided by Article 2391 of the Italian Civil Code). In any case, if the transaction is under the responsibility of the Board of Directors of Eni, a non-binding opinion from the Control and Risk Committee is required.

Moreover, to ensure compliance with the procedures envisaged by the above mentioned Policy, Directors and Statutory Auditors issue a periodically declaration, upon their appointment and every six months (normally in January and in July provided that at least 3 months have passed since the appointment) and/or when there is any change, in which they state their potential interests related to Eni and its subsidiaries. In any case the Directors and the Statutory Auditors report in good time the single transactions that Eni intends to carry out in which they have an interest. Directors report the interest to the Chief Executive officer (or the Chairman, in the case of interests of the Chief Executive Officer), who will in turn notify the other Directors and the Board of Statutory Auditors. Statutory Auditors report the interest to the other Statutory Auditors and the Chairman of the Eni SpA Board of Directors.

Compensation

Directors’ compensation shall be determined by the Shareholders’ Meeting, as required by Italian law, while the compensation of Directors with delegated powers in accordance with the By-laws (such as the Board Chairman and the CEO), or that participate in Board Committees, shall be determined by the Board of Directors, upon the proposal of the Remuneration Committee, after examining the opinion of the Board of Statutory Auditors (for more details about the compensation policy in 2025, see the Remuneration Report 2025 incorporated herein by reference as section 2 of the Report on the 2025 Remuneration Policy and remuneration paid 2024).

Borrowing powers

The power to borrow is included in the Company purpose. Moreover, in accordance with Article 11 of the By-laws, the Company may issue bonds, including convertibles bonds and warrants, in compliance with the law.

Retirement and shareholdings

There are no provisions in the By-laws relating to either retirement based on age-limit requirements and the number of shares required for a Director to qualify.

15 These internal rules replaced the previous regulation issued by the Board of Directors on the matter on February 12, 2009. The provisions regarding information to be provided to the public, under both the Consob Regulation and the internal rules, have been applied since December 1, 2010.
16 The rules have been updated, with reference to the implementation procedures, on March 2025.

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Company’s shares

In accordance with Article 5 of the By-laws, the Company’s share capital amounts to €4,005,358,876.00, fully paid, and is represented by 3,027,982,186 17 ordinary registered shares without indication of par value as of March 4, 2026. As required by the Italian law on the dematerialization of financial instruments, Eni’s shares (the “Shares”) must be held with “Monte Titoli SpA” (the Italian Central Securities Depository) and their beneficial owners may exercise their rights through special deposit accounts opened with intermediaries, such as banks, brokers and securities dealers. Shares are indivisible and each share is entitled to one vote. Shareholders are allowed to vote at ordinary and extraordinary Shareholders’ Meeting, including by proxy or by mail or, if envisaged in the notice calling the Meeting, by electronic means. Moreover, in accordance with Article 9 of the By-laws, the Shareholders’ Meeting may resolve to increase the Company share capital by issuing shares, including shares of different classes, to be granted for no consideration to Eni employees, pursuant to Article 2349 of the Italian Civil Code. This power has not been exercised.

In 1995, Eni established a sponsored American Depositary Receipts program directed at U.S. investors. Each Eni ADR is equal to two Eni ordinary shares; Eni ADRs are listed on the NYSE.

Dividend rights

Shareholders have the right to participate in profits and any other rights as provided by the law and subject to any applicable legal limitations. Specifically, the ordinary Shareholders’ Meeting called to approve the annual Financial Statements may allocate the net income resulting after allotment to the legal reserve to the payment of a final dividend per share. In addition, during the course of the financial year, the Board of Directors may distribute, as allowed by the By-laws, interim dividends to the shareholders. Entitlement to dividends not collected within five years of the day on which they become payable shall lapse in favor of the Company and such dividends shall be allocated to reserves.

Voting rights

The general provisions on share “voting rights” are described at the paragraph “Shareholders’ Meeting” below. In relation to the appointment of the Board of Directors (Eni’s Board is not a “staggered board”) and the Board of Statutory Auditors (see “Item 6”), Eni’s By-laws provide for a slate voting system. In particular, pursuant to Article 17 of the By-laws and in accordance with applicable law, slates may be presented by shareholders, either severally or jointly, representing at least 1% of the share capital, or any other threshold established by Consob in its regulation (lastly, on January 27, 2026, Consob confirmed a threshold of 0.5% for Eni, given its market capitalization). Each shareholder may, severally or jointly, submit and vote for a single slate only. There are no provisions in Eni’s By-laws relating to: rights to share in Company profits; redemption provisions; sinking fund provisions; liability to further capital calls by the Company.

Liquidation rights

In the event the Company is wound up, the Shareholders’ Meeting shall decide the manner of its liquidation and appoint one or more liquidators, establishing their powers and remuneration. In accordance with Italian law, shareholders would be entitled to the distribution of the remaining liquidated assets of the Company in proportion to their shareholdings, only after payment of all the Company’s liabilities and satisfaction of all other creditors.

Change in shareholders’ rights

A shareholders’ resolution is required to make changes in shareholders’ rights. Italian law gives shareholders the right to withdraw in the event of an amendment of the provisions of the By-laws relating to, among other matters, voting and dividend rights, approved by resolution of the Shareholders’ Meeting with the attendance and decision making quorum established by law for extraordinary meetings.

Shareholders’ Meeting

The Shareholders’ Meeting resolves on the issues set forth by applicable law and Eni’s By-laws, in “ordinary” or “extraordinary” form. The ordinary and the extraordinary Shareholders’ Meetings are normally held after a single call, with the majorities required by law in this case. The Board of Directors may, if deemed necessary, establish that both the ordinary and the extraordinary Shareholders’ Meetings shall be held after more than one call; their resolutions at first, second or third call must be passed with the majorities required by law in each case. Shareholders’ Meetings shall normally be held at the Company’s registered office, unless otherwise decided by the Board of Directors, provided however they are held in Italy.

17 The Shareholders’ Meeting, held on May 14, 2025, resolved to authorise the Board of Directors with the option of delegation to the Chief Executive Officer and sub-delegation by the same, to cancel up to a maximum of 315,000,000 treasury shares, purchased on the basis of the authorisation of the Shareholders' Meeting, held on the same day, without any impact on the Company’s share capital. The cancellation of 118,782,928 treasury shares made on the basis of the above mentioned authorisation was executed on March 4, 2026.

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The Shareholders’ Meeting shall be called by way of a notice published on the Company website, as well as in accordance with the procedures specified in Consob regulations, by the statutory deadlines and in accordance with applicable law. The notice calling the meeting, the content of which is defined by the law and Eni’s By-laws, contains all the information for attending and voting at the meeting, including information on proxy voting and voting by mail (the information is also available on the Company’s website) and, if envisaged, it may include instructions for participating in the Shareholders’ Meeting by means of telecommunication systems, as well as exercising the right to vote by electronic means. The Board of Directors shall make a report on each of the items on the agenda available to the public at the Company’s registered office, on the Company’s website and by other means envisaged by Consob regulations by the same date of the publication of the notice calling the Shareholders’ Meeting for each of the items on the agenda. Specific legal provisions may require other terms of publication of the Board of Directors report (i.e. in case of extraordinary transactions). An ordinary Shareholders’ Meeting shall be called at least once a year, within 180 days of the end of the Company’s financial year (on December 31), to approve the financial statements, since the Company is required to draw up Consolidated Financial Statements.

The right to attend and cast a vote at the Shareholders’ Meeting shall be certified by a statement submitted by an authorized intermediary on the basis of its accounting records to the Company on behalf of the person entitled to vote. The statement shall be issued by the intermediary on the basis of the balances on the accounts recorded at the end of the seventh trading day prior to the date of the Shareholders’ Meeting. Credit and debit records entered on the authorized intermediaries’ accounts after this deadline shall not be considered for the purpose of determining entitlement to exercise voting rights at the Shareholders’ Meeting. The statement, issued by the authorized intermediary, must reach the Company by the end of the third trading day prior to the date of the Shareholders’ Meeting, or by any other deadline established by Consob regulations issued in agreement with the Bank of Italy. Shareholders shall nevertheless be entitled to attend the Meeting and cast a vote if the statements are received by the Company after the deadlines indicated above, provided they are received before the start of proceedings of the given call. For the purposes of these provisions, reference is made to the date of first call, provided that the dates of any subsequent calls are indicated in the notice calling the Meeting; otherwise, the date of each call is deemed the reference date.

Those persons who are entitled to vote may appoint a party to represent themselves at the Shareholders’ Meeting by means of a written proxy or in electronic form in the manner set forth by current law. Electronic notification of the proxy may be made through a special section of the Company website as indicated in the notice calling the Meeting. In order to simplify proxy voting by shareholders who are employees of the Company or of its subsidiaries and belong to shareholders’ associations that meet applicable statutory requirements, locations for communications and collection of proxies shall be made available in accordance with the terms and conditions agreed from time to time with the legal representatives of said associations.

The right to vote may also be exercised by mail in accordance with the applicable laws and regulations. If provided for in the notice calling the meeting, those persons entitled to vote may participate in the Shareholders’ Meeting by means of telecommunication systems and exercise their right to vote by electronic means in accordance with the provisions of the law, applicable regulations and the Shareholders’ Meeting Rules.

The Company may designate a person for each Shareholders’ Meeting to whom the shareholders may confer a proxy with voting instructions on all or some of the items on the agenda, as provided for by applicable laws and regulations, by the end of the second trading day preceding the date set for the Shareholders’ Meeting including for calls subsequent to the first. Such proxy shall not be valid for items in respect of which no voting instructions have been provided.

The Chairman of the meeting shall verify the validity of proxies and, in general, entitlement to participate in the Meeting.

The Shareholders’ Meetings are governed by the Shareholders’ Meeting Rules as approved by resolution of the ordinary Shareholders’ Meeting on December 4, 1998, in order to guarantee an efficient conduct of meetings and the right of each shareholder to express his or her opinion on the items on the agenda. The Shareholders' Meetings held on May 11, 2022 has approved an update of such Rules.

During Shareholders’ Meetings, the Board of Directors provides broad disclosure on items examined and shareholders can request information on issues in the agenda. Information is provided taking into account applicable rules on inside information.

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In accordance with Article 3, paragraph 14-sexies of Decree Law No. 202 of December 27, 2024 , ratified with amendments by Law No. 15 of February 21, 2025, which extended the effectiveness of the measures contained in the Article 106, paragraph 4, second sentence, of Decree Law No. 18 of March 17, 2020, ratified with amendments by Law No. 27 of April 24, 2020 also to the Shareholders’ Meeting to be held by December 31, 2025, the participation in the Shareholders’ Meeting of May 14, 2025 was permitted solely through the Shareholders’ representative designated by the Company pursuant to Article 135-undecies of Consolidated Law on Financial Intermediation. Decree Law No. 200 of December 31, 2025, ratified with amendments by Law No. 26 of February 27, 2026, extended the effectiveness of the above-mentioned measures also to the Shareholders’ Meeting to be held by September 30, 2026.

Stock ownership limitation and voting rights restrictions

Without prejudice to any specific regulations regarding international sanctions, there are no limitations imposed by Italian law or by Eni’s By-laws on the rights of non-residents in Italy or foreign persons to hold shares or vote other than the limitations described below (which are equally applicable to both residents and non-residents of Italy). In accordance with Article 6 of the By-laws, and in application of the special rules pursuant to Article 3 18 of Decree Law No. 332 of May 31, 1994, ratified with amendments by Law No. 474 of July 30, 1994 (Law No. 474/1994), no shareholder may hold, in any capacity, directly or indirectly, more than 3% of the Company’s share capital. Any voting rights and any other non-financial rights attached to shares held in excess of the maximum limit indicated above may not be exercised and the voting rights of each shareholder to whom such limit applies shall be reduced in proportion, unless otherwise jointly specified in advance by the parties involved.

Pursuant to Article 32 of the By-laws and the above mentioned provision of law, shareholdings owned by the Ministry of the Economy and Finance, public entities or organizations controlled by them are exempt from this ban. Finally, this special rule provides that the clause regarding shareholding limits will lose effect if the limit is exceeded as a result of a take-over bid, provided that, as a result of the takeover, the bidder will own a shareholding of at least 75% of the share capital with the right to vote on resolutions concerning the appointment or dismissal of Directors.

Limitation on changes in control of the Company (Special Powers of the Italian State)

Decree Law No. 21 of March 15, 2012 (so called “Golden Power Decree”), ratified with amendments by Law No. 56 of May 11, 2012 (Law No. 56/2012), modified Italian legislation governing the special powers of the Italian State to comply with European rules.

The special powers apply, among others, to company assets in the energy sector, as defined by the regulations which implement the relevant law.

The special powers include: a) veto power (or the power of imposing conditions or requirements) over certain transactions or resolutions involving strategic assets (identified by Decrees of the President of the Council of Ministers no. 179 and 180 of 2020) or companies that hold such assets and which give rise to an extra-ordinary situation, not regulated by national and European sector regulations including sector-specific regulation regarding the prudential assessments of acquisitions of qualifying holdings in the financial sector and merger control, of a threat of a serious prejudice to public interests relating to the safety and operation of networks and facilities and the continuity of supplies and b) power of attaching conditions or opposing the acquisition by an entity of shareholdings that determine the control of a company that holds, directly or indirectly, strategic assets and the acquisition, by an entity outside of the EU, of shareholdings in such company equal to at least 10% and the total value of the investment exceeds one million euros, or the acquisitions result in the 15%, 20%, 25%, 50% thresholds being exceeded, if the purchase entails a threat of a serious prejudice to the essential interests of the State or a danger to public security or public order, including the national economic and financial security to the extent that the protection of the essential interests of the State is not adequately guaranteed by the existence of sector-specific regulation.

Companies that hold strategic assets or carry out activities of strategic importance, or entities that intend to acquire certain shareholdings in such companies, are required to notify the Prime Minister’s Office with a full disclosure of the resolution, act or transaction, or of the acquisition of the shareholdings. The notification obligation extends also to the incorporation of companies that carry out activities of strategic importance or hold strategic assets if one or more shareholders, external to the EU, hold a share of voting rights or capital equal to at least 10%.

18 This provision has been modified by the Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012. For more details see the paragraph “Limitation on changes in control of the Company (Special Powers of the Italian State)” below.

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With particular reference to the power referred to in letter b), until the notification and thereafter, up to the expiration of the term for the possible exercise of such power, the voting rights and any other non-financial right related to the significant shareholding may not be exercised.

In the case of non-fulfillment of imposed conditions, throughout the relevant period, the voting rights and any other non- financial right related to the significant shareholding may not be exercised. The resolutions adopted with the decisive vote of such shareholding, or otherwise the resolutions or acts adopted in breach or default of the imposed conditions are void. In addition, unless the fact constitutes a crime, failure to comply with imposed conditions entails for the purchaser a fine.

In case of opposition, the buyer may not exercise the voting rights and any other non-financial right related to the significant shareholding, which must be sold within a year. In case of non-compliance, at the request of the Government, the Court will order the sale of the significant shareholding. Shareholders’ Meeting resolutions adopted with the decisive vote of such participation shall be void.

The legislation provides for a general rule that the acquisition, for any reason, by an entity outside of the EU of stock in a company that holds strategic assets will be allowed on condition of reciprocity, in compliance with international agreements signed by Italy or the EU.

These powers are exercised exclusively on the basis of objective and non-discriminatory criteria.

Decree-Law No. 104/2023, converted into Law No. 136/2023, amended the Golden Power Decree by providing that the special powers can also be exercised on transactions, resolutions or deeds within a corporate group involving assets covered by intellectual property rights relating to artificial intelligence, machinery for the production of semiconductors, cybersecurity, aerospace, energy storage, quantum and nuclear technologies, food production technologies and concern one or more non-EU parties (subject to verification of the conditions for the exercise of the special powers).

Albeit with some amendments, the provisions regarding the stock ownership limitations and voting rights restrictions pursuant to Article 3 of Law No. 474/1994 are still in force.

In order to “promote privatization and the spread of investment in shares” of companies in which the Italian State has a significant shareholding, Article 1, paragraphs 381 to 384 of Law No. 266 of 2005 (2006 Financial Law) introduced the power to add provisions to the By-laws of privatized companies primarily controlled by the Italian State, like Eni, which allow shares or participating financial instruments to be issued that grant the special meeting of its holders the right to request that new shares, even at par value, or new financial instruments be issued to them with the right to vote in ordinary and extraordinary Shareholders’ Meetings. Making this amendment to the By-laws would lead to the shareholding limit referred to in Article 6.1 of the By-laws being removed. At the present time, however, Eni’s By-laws do not contain any such provisions.

Shareholder ownership thresholds

There are no By-law provisions governing the disclosure of the ownership threshold because the matter is regulated by Italian law. Pursuant to the Consolidated Law on Financial Intermediation 19 and the Consob Regulation 20, any direct or indirect holding in the voting shares of an Italian listed company in excess of 3%21, 5%, 10%, 15%, 20%, 25%, 30%, 50%, 66.6% and 90% must be notified to the investee company and to Consob. The same disclosure requirements refer to holdings that drop below one of the specified thresholds.

Such disclosures shall be made — using the forms contained in Annex 4A to the above Regulation — without delay and, in any case, within four trading days of the transaction, starting from the day on which the subject gains knowledge of the transaction that can lead to the obligation, regardless of the date of execution, or from the date on which the subject obliged to make the disclosure gains knowledge of the event that leads to changes in the share capital as contemplated in the Consob Regulation.

19 Legislative Decree No. 58 of February 24, 1998, with specific reference to Articles 120-122.
20 Article 117 of Consob Decision No. 11971/1999 and subsequent amendments.
21 If the company is not a SME (small or medium enterprise). Moreover, Consob may, by means of measures justified by the need to protect investors, as well as corporate control market and capital market efficiency and transparency, envisage — for a limited period of time — lower thresholds by its decree for companies with particularly extensive shareholding structure.

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For the purpose of the above disclosure obligations, the Consob Regulation establishes investment calculation criteria 22. The obligation to notify also applies to any direct or indirect holding owned through ADRs.

Specific disclosure requirements (with partially different thresholds) are connected to investments in financial instruments and for aggregate investments 23.

Under the above mentioned Consolidated Law on Financial Intermediation, as amended by Decree Law No. 148/2017, in the case of the purchase of a stake in listed issuers equal or above the thresholds of 10%, 20% and 25% of the relevant share capital in listed companies, the investor shall state the objectives it intends to pursue in the following six months 24. The declaration shall state under the responsibility of the declarant: a) the means of financing the acquisition; b) whether acting alone or in concert; c) whether it intends to stop or continue its purchases, and whether it intends to acquire control of the issuer or anyway have an influence on the management of the company and, in such cases, the strategy it intends to adopt and the transactions to be carried out; d) its intentions as to any agreements and shareholders’ agreements to which it is party; e) whether it intends to propose the integration or revocation of the issuer’s administrative or control bodies. Consob can identify, with its own regulation, the cases where the aforementioned declaration is not due, taking into account the characteristics of the entity making the declaration or of the company whose shares have been purchased.

The declaration shall be transmitted to the company whose shares have been purchased and to Consob and shall be subject to public disclosure in accordance with the terms and conditions established by Consob Regulation.

Voting rights attached to listed shares which have not been notified pursuant to the above mentioned disclosure requirements may not be exercised. Any resolution or act adopted in violation of such limitation, with the contribution of those undisclosed shares, could be voided if challenged in court, under the Italian Civil Code.

According to the Italian Civil Code (Article 2359-bis), a subsidiary may acquire shares of the parent company only within the limits of distributable profits and available reserves as resulting from the last approved balance sheet. Only fully-paid shares can be purchased. The purchase must be approved by the Shareholders’ Meeting and, in any case, the nominal value of shares purchased may not exceed one-fifth of the capital of the parent company — if the latter is a listed company — taking into account for this purpose the shares held by the same parent company or its subsidiaries.

The Consolidated Law on Financial Intermediation provides rules governing cross-holdings. In particular, except for the cases contemplated by the above mentioned Article 2359-bis of the Italian Civil Code, in case of a reciprocal participation exceeding the limit of 3% of the shares, the company that exceeds the limit successively cannot exercise its right to vote relative to the shares held in excess of such threshold and must sell such shares within the following 12 months. In the event of failure to dispose of the shares by such time limit, the voting rights shall be suspended with respect to the entire shareholding. Where it is not possible to ascertain which of the two companies was the last to exceed the limit, the suspension of voting rights and the disposal requirement shall apply to both unless they have agreed otherwise. In the event of non-compliance, any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code.

The above mentioned limit is increased to 5% (or to 10% if the issuer is a small or medium enterprise as per Article 1, letter w-quater.1 of the Consolidated Law on Financial Intermediation) if the threshold is exceeded by both companies subsequent to an agreement authorized in advance by the ordinary shareholders’ meetings of the companies concerned.

If a person holds an interest exceeding the aforementioned threshold of a listed company, such listed company or any person controlling such listed company may not acquire an interest exceeding such a limit in a listed company controlled by the former. In the event of non-compliance, the voting rights attached to the shares in excess of the limit specified shall be suspended. Where it is not possible to ascertain which of the two persons was the last to exceed the limit, the suspension shall apply to both unless they have agreed otherwise. In the event of non-compliance, any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code.

22 Article 118 of Consob Decision No. 11971/1999 and subsequent amendments.
23 Article 119 of Consob Decision No. 11971/1999 and subsequent amendments.
24 Consob may, with a provision reasoned by investor protection needs as well as efficiency and transparency of the corporate control market and of the capital market, introduce, for a limited period of time, in addition to the thresholds above indicated, a threshold of 5 percent for companies with a particularly widespread shareholder base.

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The limitations described above are not applicable in the case of a takeover bid or exchange tender offer to acquire at least 60% of the ordinary shares of a listed company.

Under the Consolidated Law on Financial Intermediation, any agreement, in any form, regarding the exercise of voting rights in a listed company or in its parent company, must be, within five days of stipulation: (i) notified to Consob; (ii) published in abstract form, in the Italian daily press; (iii) filed with the Register of Companies in which the listed company is registered; and (iv) notified to the company with listed shares. In the event of non-compliance with these requirements, the agreements shall be null and void and the voting rights attached to the relevant shares may not be exercised and any resolution or act adopted with the contribution of such shares may be challenged under the Italian Civil Code.

The same provisions also apply to agreements, in any form, that: (a) create obligations of consultation prior to the exercise of voting rights in a listed company and in its controlling companies; (b) set limits on the transfer of the related shares or of other financial instruments that entitle holders to buy or subscribe them; (c) provide for the purchase of the shares or of the above mentioned financial instruments; (d) have as their object or effect the exercise, jointly or otherwise, of dominant influence on such companies; and (d-bis) which aim to encourage or frustrate a takeover bid or an exchange tender offer, including commitments relating to non-participation in a takeover bid.

Finally, pursuant to Law No. 287 of October 10, 1990, any merger or acquisition of (legal or factual) sole or joint control over a company or any change of control over a company is subject to the prior authorization by the Italian Antitrust Authority 25 if the companies involved exceed given turnover thresholds. If the said merger, acquisition or change of control were to significantly affect competition, in particular because they create or strengthen a dominant position, the Italian Antitrust Authority can either prohibit the transaction or make it subject to remedies preventing a restriction of competition. Moreover, if the transaction or the companies involved exceed other quantitative or qualitative thresholds set by European or other jurisdictions’ legislations (e.g. other turnover thresholds or thresholds referred to transaction’s value, market shares of the parties or the potential competitiveness of the target), the transaction can also be subject to the prior authorization by competition authorities of such other jurisdictions. Finally, pursuant to new rules enacted in 2022, in some circumstances both the Italian Antitrust Authority and the European Commission might require that specific mergers, acquisitions or changes of control be made subject to their approval, even if they are below said thresholds.

Changes in share capital

Eni’s By-laws do not provide for more stringent conditions than those required by law. Share capital increases are resolved by a shareholders’ resolution at an extraordinary Shareholders’ Meeting. Under Italian law, shareholders have a pre-emptive right to subscribe newly issued shares and corporate bonds convertible into shares in proportion to their respective shareholdings. If the Company’s interest so requires, the pre-emptive right may be waived or limited by the shareholders’ resolution authorizing the share capital increase. The shareholders’ pre-emptive right is also waived if the shareholders’ resolution authorizing the share capital increase provides for the subscription of new issues of shares in the form of contributions in-kind.

Material contracts

None.

Exchange controls

Under current Italian exchange control regulations, no limits exist on the amount of payments that Eni may remit to residents of the United States. Laws and regulations concerning foreign exchange controls do require, however, that an accredited intermediary must handle all payments or transfer of funds made by an Italian resident to a non-resident.

Taxation

The information set forth below is only a summary; Italian, the United States and other tax laws may change from time to time. Holders of shares and ADRs should consult with their professional advisors as to the tax consequences of their ownership and disposition of the shares and ADRs, including, in particular, the effect of tax laws of any other jurisdiction.

25 Autorità garante della concorrenza e del mercato (AGCM).

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Italian taxation

The following is a summary of the material Italian tax consequences of the ownership and disposition of shares or ADRs as at the date hereof and does not purport to be a complete analysis of all potential tax effects relevant to the ownership or disposition of shares or ADRs.

Income tax

Dividends regarding income of financial years 2023 onwards, received by Italian resident individuals holding the shares or ADRs otherwise than in connection with entrepreneurial activity, are subject to a substitute tax of 26% withheld at the source by the dividend paying agent. This being the case, the dividend is not to be included in the individual’s tax return.

Subject to certain limitations and requirements (including a minimum holding period), dividends received by Italian resident individuals holding the shares not in connection with an entrepreneurial activity or social security entities pursuant to Legislative Decree No. 509 of June 30, 1994 and Legislative Decree No. 103 of February 10, 1996 may be exempt from taxation if the shares are included in a long-term individual savings account (piano individuale di risparmio a lungo termine) that meets the requirements set forth by Italian law as amended and supplemented from time to time.

Dividends received by Italian investment funds and società di investimento a capitale variabile (“SICAV”) are not subject to substitute tax but are included in the aggregate income of the investment fund or SICAV. The investment fund or SICAV will not be subject to tax on the dividends. A withholding tax of 26% may apply on income of the investment fund or SICAV derived by unitholders or shareholders through distribution and/or upon redemption or disposal of the units and shares.

Dividends received by real estate funds to which the provisions of Law Decree No. 351 of September 25, 2001, as subsequently amended, apply, are not subject to any substitute tax nor to any other income tax in the hands of the fund. The income of the real estate fund is subject to tax, in the hands of the unitholder, depending on status and percentage of participation, or, when earned by the fund, through distribution and/or upon redemption or disposal of the units.

Dividends received by a pension fund (subject to the regime provided for by Article 17 of the Italian Legislative Decree No. 252 of December 5, 2005) and deposited with an authorized intermediary, will not be subject to substitute tax, but must be included in the result of the relevant portfolio accrued at the end of the tax period, to be subject to a 20% substitute tax. Subject to certain limitations and requirements (including a minimum holding period), shares received by Italian resident pension funds may be excluded from the taxable base of the substitute tax, if the shares are included in a long-term individual savings account (piano individuale di risparmio a lungo termine) that meets the requirements set forth by Italian law as amended and supplemented from time to time.

Dividends paid to non-Italian residents are subject to substitute tax levied at source by the dividend paying agent at the rate of 26%, provided that the interest is not connected to an Italian permanent establishment.

The above-mentioned 26% substitute tax will not be applied in the event of dividends distributed in favor of foreign undertakings for collective investment which comply with European Directive 2009/65/EC of the European Parliament and of the Council of July 13, 2009 (UCITS Directive), and to undertakings for collective investment which do not comply with the aforesaid Directive 2009/65/EC, whose manager is subject to regulatory supervision in the foreign country in which it is established in accordance with European Directive 2011/61/EU of the European Parliament and of the Council of June 8, 2011 (AIFM Directive), established in an EU Member States or a European Economic Area (“EEA”) State included in the list of States and territories allowing an adequate exchange of information with the Italian tax authorities according to the Ministerial Decree of September 4, 1996 (“White List”).

Dividends are subject to a 1.20% substitute tax introduced by the Financial Bill for 2008 where the conditions in Article 27, paragraph 3-ter, Presidential Decree No. 600 of 1973 are met, i.e. dividends are paid to non-Italian companies and entities that (i) are resident in an EU Member State or EEA State included in the White List (ii) are subject to a corporate income tax in their country of residence. With reference to distributions of profit and/or retained earning which have been resolved as of 1 January 2026, the 1.20% substitute tax applies if, in addition to the conditions above, the non-Italian companies and entities receiving the dividends (i) have a participation in the Company equal to or greater than 5%, or (ii) the participation held has a tax value equal to or greater than €500,000.

The substitute tax may also be reduced under the Tax Treaty in force between Italy and the country of residence of the Beneficial Owner of the dividend. Italy has executed income Tax Treaties with approximately 100 foreign countries, including all EU Member States, Argentina, Australia, Brazil, Canada, Japan, New Zealand, Norway, Switzerland, the United States and some countries in Africa, the Middle East and the Far East. Generally speaking, it should be noted that Tax Treaties are not applicable where the holder is a tax-exempt entity or, with few exceptions, a partnership or a trust.

In order to obtain the Treaty benefit of a reduced substitute tax rate at the same time of payment, the Beneficial Owner must file an application to the dividend paying agent chosen by the Depositary stating the existence of the conditions for the applicability of the Treaty benefit, together with a certification issued by the foreign tax authorities stating that the shareholder is a resident of that country for Treaty purposes.

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Under the Tax Treaty between the United States and Italy (the “Italy U.S. Tax Treaty”), dividends derived and beneficially owned by a U.S. resident who holds less than 25% of the Company’s voting stock are subject to an Italian withholding or substitute tax at a reduced rate of 15%, provided that the interest is not effectively connected with a permanent establishment in Italy through which the U.S. resident carries on a business or a fixed base in Italy through which such U.S. resident performs independent personal services (for further details please refer to the relevant provisions set forth in the Italy U.S. Tax Treaty). In the absence of such conditions, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 26%. Based on the certification procedure required by the Italian Tax Authorities, to benefit from the direct application of the 15% substitute tax the U.S. shareholder must provide the dividend paying agent with a certificate obtained from the U.S. Internal Revenue Service (the “IRS”) with respect to each dividend payment. The request for this certificate must include a statement, signed under penalty of perjury, attesting that the shareholder is a U.S. resident individual or corporation, and does not maintain a permanent establishment in Italy, and must set forth other required information. The normal time for processing requests for certification by the IRS is normally about six to eight weeks.

Where the Beneficial Owner has not provided the above-mentioned documentation, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 26%. The U.S. recipient will then be entitled to claim from the Italian Tax Authorities the difference (treaty refund) between the domestic rate and the Treaty one by filing specific forms (certificate) with the Italian Tax Authorities.

As reflected in the Deposit Agreement, if any tax or other governmental charge shall become payable by or on behalf of the Custodian or the Depositary with respect to an ADR, any Deposited Securities represented by the American Depositary Shares (“ADSs”), such tax or other governmental charge shall be paid by the Holder hereof to the Depositary.

The Depositary may refuse to effect any registration, registration of transfer, split-up or combination hereof or any withdrawal of such Deposited Securities until such payment is made. The Depositary may also deduct from any distributions on or in respect of Deposited Securities, or may sell by public or private sale for the account of the Holder hereof any part or all of such Deposited Securities (after attempting by reasonable means to notify the Holder hereof prior to such sale), and may apply such deduction or the proceeds of any such sale in payment of such tax or other governmental charge, the Holder hereof remaining liable for any deficiency, and shall reduce the number of ADSs to reflect any such sales of shares. Pursuant to the Deposit Agreement, the Depositary and the Custodian may make and maintain arrangements to enable persons that are considered United States residents for purposes of applicable law to receive any tax rebates (pursuant to an applicable Treaty or otherwise) or other tax related benefits relating to distributions on the ADSs to which such persons are entitled. Notwithstanding any other terms of the Deposit Agreement or the ADR, absent the gross negligence or bad faith of, respectively, the Depositary and the Company, the Depositary and the Company assume no obligation, and shall not be subject to any liability, for the failure of any Holder or Beneficial Owner, or its agent or agents, to receive any tax benefit under applicable law or Tax Treaties. The Depositary shall not be liable for any acts or omissions of any other party in connection with any attempts to obtain any such benefit, and Holders and Beneficial Owners hereby agree that each of them shall be conclusively bound by any deadline established by the Depositary in connection therewith.

Capital gains tax

This paragraph concerns and applies to capital gains out of the scope of a business activity carried out in Italy. Profits gained by Italian resident individuals, not in connection with entrepreneurial activity, in financial year 2025, are subject to substitute tax for 26%. Two different systems may be applied at the option of the shareholder as an alternative to the so-called “tax return regime” (regime della dichiarazione – it is the default regime for taxation of capital gains, according to which capital gains are reported in the taxpayer's tax return and paid within the deadline for the payment of the balance income taxes due on the basis of the relevant tax return):

| ● | the so-called “administered savings” tax regime (risparmio amministrato), based on which intermediaries acting as shares depositaries shall apply a substitute tax (26%) on each gain, on a cash basis. If the sale of shares generated a loss, said loss may be carried forward up to the fourth following year; and
| ● | the so-called “portfolio management” tax regime (risparmio gestito) which is applicable when the shares form part of a portfolio managed by an Italian asset management company. The accrued net profit of the portfolio is subject to a 26% substitute tax to be applied by the portfolio.

Subject to certain limitations and requirements (including a minimum holding period), gains realized upon sale, transfer or redemption by Italian resident individuals holding the shares not in connection with an entrepreneurial activity or social security entities pursuant to Legislative Decree No. 509 of June 30, 1994 and Legislative Decree No. 103 of February 10, 1996 may be exempt from taxation, if the shares are included in a long-term individual savings account (piano individuale di risparmio a lungo termine) that meets the requirements set forth by Italian law as amended and supplemented from time to time.

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Gains realized by non-residents from non-substantial interest in listed companies are deemed not to be realized in Italy and consequently are not subject to the capital gains tax. On the contrary, gains realized by non-residents from substantial interests even in listed companies are deemed to be realized in Italy and consequently are subject to tax on capital gains.

Any gains realized by a holder of the shares who is an Italian pension fund (subject to the regime provided for by article 17 of the Italian Legislative Decree No. 252) will be included in the result of the relevant portfolio accrued at the end of the tax period, to be subject to a to a 20% annual substitute tax. Subject to certain limitations and requirements (including a minimum holding period), capital gains realized by Italian pension funds may be excluded from the taxable base of the substitute tax, if the shares are included in a long-term individual savings account (piano individuale di risparmio a lungo termine) that meets the requirements set forth by Italian law as amended and supplemented from time to time.

Gains realized by undertakings for collective investment which comply with European Directive 2009/65/EC of the European Parliament and of the Council of July, 13, 2009 (UCITS Directive), and by undertakings for collective investment, established in an EU Member States or a EEA State included in the White List, which do not comply with the aforesaid Directive 2009/65/EC, whose manager is subject to regulatory supervision in the foreign country in which it is established in accordance with European Directive 2011/61/EU of the European Parliament and of the Council of June 8, 2011 (AIFM Directive), will not be applied.

However, double taxation treaties may eliminate the capital gains tax. Under the Italy U.S. Tax Treaty, a U.S. resident will not be subject to the capital gains tax unless the shares or ADRs form part of the business property of a permanent establishment of the holder in Italy or pertain to a fixed establishment available to a shareholder in Italy for the purposes of performing independent personal services. U.S. residents who sell shares may be required to produce appropriate documentation establishing that the above mentioned-conditions of non taxability pursuant to the Italy U.S. Tax Treaty have been satisfied.

Financial Transactions Tax

Italian Law No. 228 of December 24, 2012 has introduced a Financial Transactions Tax which applies to the transfer of shares, ADR and other financial instruments issued by companies resident in Italy. As to transfers occurring from 1 January 2026, the tax rate applicable is 0.20% for ADR negotiated in regulated markets (like the NYSE).

Non-Italian intermediaries, involved in the transactions of Eni ADR, must withhold and pay the Financial Transactions Tax. For this purpose, non-Italian intermediaries can appoint an Italian Tax Representative, according to the Italian tax law.

Inheritance and gift tax

Pursuant to Law Decree No. 262 of October 3, 2006, converted with amendments by Law No. 286 of November 24, 2006, effective from November 29, 2006, and Law No. 296 of December 27, 2006, the transfers of any valuable assets (including shares) as a result of death or donation (or other transfers for no consideration) and the creation of liens on such assets for a specific purpose are taxed as follows:

(a) 4 per cent: if the transfer is made to spouses and direct descendants or ancestors; in this case, the transfer is subject to tax on the value exceeding €1,000,000 (per beneficiary);

(b) 6 per cent: if the transfer is made to brothers and sisters; in this case, the transfer is subject to the tax on the value exceeding €100,000 (per beneficiary);

(c) 6 per cent: if the transfer is made to relatives up to the fourth degree, to persons related by direct affinity, as well as to persons related by collateral affinity up to the third degree; and

(d) 8 per cent: in all other cases.

If the transfer is made in favor of persons with severe disabilities, the tax applies on the value exceeding €1,500,000. Moreover, an anti-avoidance rule is provided for by Law No. 383 of October 18, 2001 for any gift of assets (including shares) which, if sold for consideration, would give rise to capital gains subject to a substitute tax (imposta sostitutiva) provided for by Decree No. 461 of November 21, 1997. In particular, if the donee sells the shares for consideration within five years from the receipt thereof as a gift, the donee is required to pay a relevant substitute tax on capital gains as if the gift had never taken place.

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United States taxation

The following is a summary of certain U.S. federal income tax consequences to U.S. Holders (as defined below) of the ownership and disposition of Shares or ADSs. This summary is addressed to U.S. Holders that hold Shares or ADSs as capital assets, and does not discuss all material tax consequences of the ownership of Shares or ADSs, including tax consequences arising under the Medicare contribution tax on net investment income or the alternative minimum tax. The summary does not address special classes of investors, such as tax-exempt entities, dealers in securities, traders in securities that elect to mark-to- market, certain insurance companies, broker-dealers, investors that actually or constructively own 10% or more of the combined voting power of Eni SpA’s voting stock or of the total value of Eni SpA’s stock, a person that purchases or sells Shares or ADSs as part of a wash sale for U.S. federal income tax purposes, investors that hold Shares or ADSs as part of a straddle or a hedging or conversion transaction and investors whose “functional currency” is not the U.S. dollar.

This summary is based on the tax laws of the United States (including the Internal Revenue Code of 1986, as amended, its legislative history, existing and proposed regulations thereunder, published rulings and court decisions) as in effect on the date hereof and the Italy U.S. Tax Treaty. These authorities are subject to change (or changes in interpretation), possibly with retroactive effect. The summary is based in part on representations of the Depositary and assumes that each obligation in the Deposit Agreement and any related agreement will be performed in accordance with its terms. U.S. Holders should consult their own tax advisors to determine the U.S. federal, state and local and foreign tax consequences to them of the ownership and disposition of Shares or ADSs.

If an entity or arrangement that is treated as a partnership for U.S. federal income tax purposes holds Shares or ADSs, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment of the partnership. A partner in a partnership holding Shares or ADSs should consult its tax advisor with regard to the U.S. federal income tax treatment of an investment in the Shares or ADSs.

As used in this section, the term “U.S. Holder” means a beneficial owner of Shares or ADSs that is:

(i) a citizen or resident of the United States; (ii) a domestic corporation; (iii) an estate the income of which is subject to the U.S. federal income tax without regard to its source; or (iv) a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust.

The discussion does not address any aspects of U.S. taxation other than U.S. federal income taxation. In particular, U.S. Holders are urged to confirm their eligibility for benefits under the Italy U.S. Tax Treaty with their advisors and to discuss with their advisors any possible consequences of their failure to qualify for such benefits. In general, and taking into account the earlier assumptions, for U.S. federal income tax purposes, U.S. Holders who own ADRs evidencing ADSs will be treated as owners of the underlying Shares. Exchanges of Shares for ADRs and ADRs for Shares generally will not be subject to U.S. federal income tax.

Distributions

Subject to the passive foreign investment company (“PFIC”) rules discussed below, distributions paid on the Shares or ADSs will generally be treated as dividends for U.S. federal income tax purposes to the extent paid out of Eni SpA’s current or accumulated earnings and profits as determined for U.S. federal income tax purposes, but will not be eligible for the dividends- received deduction generally allowed to U.S. corporations. To the extent that a distribution exceeds Eni SpA’s earnings and profits, it will be treated, first, as a non-taxable return of capital to the extent of the U.S. Holder’s tax basis in the Shares or ADSs, and thereafter as capital gain. A U.S. Holder will be subject to U.S. federal taxation, on the date of actual or constructive receipt by the U.S. Holder (in the case of Shares) or by the Depositary (in the case of ADSs) with respect to the gross amount of any dividends, including any Italian tax withheld therefrom, without regard to whether any portion of such tax may be refunded to the U.S. Holder by the Italian Tax Authorities.

For non-corporate U.S. Holders, dividends that constitute qualified dividend income will be taxable at the preferential rates applicable to long-term capital gains provided that such person holds the Shares or ADSs for more than 60 days during the 121 day period beginning 60 days before the ex-dividend date and meet other holding period requirements. Dividends paid by Eni SpA that are received with respect to the ADSs will generally be qualified dividend income if the ADSs are readily tradable on an established securities market in the United States. Eni SpA’s ADSs are listed on the New York Stock Exchange and Eni SpA therefore expects that dividends with respect to the ADSs will be qualified dividend income. Dividends paid by Eni SpA with respect to the Shares will generally be qualified dividend income provided that, in the year that you receive the dividend, Eni SpA is eligible for the benefits of the Italy U.S. Tax Treaty. Eni SpA believes that it is currently eligible for the benefits of the Italy U.S. Tax Treaty and Eni SpA therefore expects that dividends on the Shares will also be qualified dividend income, but there can be no assurance that Eni SpA will continue to be eligible for the benefits of the Italy U.S. Tax Treaty.

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The amount of the dividend distribution that must be included in the income of a U.S. Holder will be the U.S. dollar value of the euro payments made, determined at the spot EUR/USD rate on the date the dividend is distributed, regardless of whether the payment is in fact converted into U.S. dollars. Generally, any gain or loss resulting from currency exchange fluctuations during the period from the date the dividend is distributed to the date the U.S. Holder converts the payment into U.S. dollars will be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualified dividend income. The gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes.

Subject to certain conditions and limitations, Italian tax withheld from dividends will be treated as a foreign income tax eligible for credit against the U.S. Holder’s U.S. federal income tax liability. Special rules apply in determining the foreign tax credit limitation with respect to dividends that are subject to the preferential rates. To the extent a reduction or refund of the tax withheld is available to a U.S. Holder under Italian law or under the Italy U.S. Tax Treaty, the amount of tax withheld that could have been reduced or that is refundable will not be eligible for credit against his or her U.S. federal income tax liability. See “Italian taxation — Income tax” above, for the procedures for obtaining a tax refund. For foreign tax credit purposes, dividends paid on the Shares or ADSs will generally be income from sources outside the United States and will, generally be “passive” income for purposes of computing the foreign tax credit allowable to you. However, if (a) Eni SpA is 50% or more owned, by vote or value, by United States persons and (b) at least 10% of Eni SpA’s earnings and profits are attributable to sources within the United States, then for foreign tax credit purposes, a portion of Eni SpA’s dividends would be treated as derived from sources within the United States. With respect to any dividend paid for any taxable year, the United States source ratio of Eni SpA’s dividends for foreign tax credit purposes would be equal to the portion of Eni SpA’s earnings and profits from sources within the United States for such taxable year, divided by the total amount of our earnings and profits for such taxable year. Eni SpA does not expect to be 50% or more owned, by vote or value, by United States persons, and therefore does not expect that any portion of Eni SpA’s dividends will be treated as derived from sources within the United States.

Sale or exchange of Shares

Subject to the PFIC rules discussed below, a U.S. Holder generally will recognize gain or loss for U.S. federal income tax purposes on the sale or exchange of Shares or ADSs equal to the difference between the U.S. Holder’s adjusted basis in the Shares or ADSs (determined in U.S. dollars), as the case may be, and the amount realized on the sale or exchange (or if the amount realized is denominated in a foreign currency, its U.S. dollar equivalent). The amount realized will generally be reduced by any Italian Financial Transaction Tax paid in respect of such transfer, and a U.S. Holder will not be entitled to claim a foreign tax credit in respect of the payment of the Italian Financial Transaction Tax. Generally, such gain or loss will be treated as capital gain or loss if the Shares or ADSs are held as capital assets and will be a long-term capital gain or loss if the Shares or ADSs have been held for more than one year on the date of such sale or exchange. Long-term capital gain of a non-corporate U.S. Holder is generally taxed at preferential rates. In addition, any such gain or loss realized by a U.S. Holder generally will be treated as U.S. source income or loss for U.S. foreign tax credit purposes.

PFIC rules

Eni SpA believes that Shares and ADSs should not currently be treated as stock of a PFIC for U.S. federal income tax purposes and Eni SpA does not expect to become a PFIC in the foreseeable future. However, this conclusion is a factual determination that is made annually and thus may be subject to change. If Eni SpA were to be treated as a PFIC, gain realized on the sale or other disposition of your Shares or ADSs would in general not be treated as capital gain. Instead, unless a U.S. Holder elects to be taxed annually on a mark-to-market basis with respect to the Shares or ADSs, the U.S. Holder would be treated as having realized such gains and certain “excess distributions” ratably over the holding period for the Shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain or distribution was allocated, together with an interest charge in respect of the tax attributable to each such year. With certain exceptions, a U.S. Holder’s Shares or ADSs will be treated as stock in a PFIC if Eni SpA were a PFIC at any time during the period the Shares or ADSs were held. Dividends received from Eni SpA will not be eligible for the preferential tax rates applicable to qualified dividend income if Eni SpA is treated as a PFIC with respect to the U.S. Holders either in the taxable year of the distribution or the preceding taxable year, but instead will be taxable at rates applicable to ordinary income.

Documents on display

Eni’s Annual Report and Accounts and any other document concerning the Company are also available online on the Company’s website. The Company is subject to the information requirements of the Security Exchange Act of 1934 applicable to foreign private issuers. In accordance with these requirements, Eni files its Annual Report on Form 20-F and other related documents with the U.S. SEC. It’s possible to read and copy documents that have been filed with the U.S. via commercial document retrieval services, and from the SEC website (www.sec.gov).

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Item 11. Q U ANTI TA TIVE AND Q U ALI TA TIVE DISC L OSURES ABOUT MARKET RISK

Market risk is the possibility that the exposure to fluctuations in commodity prices, currency exchange rates, interest rates or other market benchmarks will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. Eni’s financial performance is particularly sensitive to changes in the price of crude oil and movements in the EUR/USD exchange rate. Overall, a rise in the price of crude oil has a positive effect on Eni’s results from operations and liquidity due to increased revenues from oil&gas production. Conversely, a decline in crude oil prices reduces Eni’s results from operations and liquidity.

The impact of changes in crude oil prices on the Company’s refining and marketing and petrochemical businesses depends upon the speed at which the prices of finished products adjust to reflect changes in crude oil prices. In addition, the Group’s activities are, to various degrees, sensitive to fluctuations in the EUR/USD exchange rate as commodities are generally priced internationally in U.S. dollars or linked to dollar denominated products. Overall, an appreciation of the euro against the dollar reduces the Group’s results from operations and liquidity, and vice versa.

As part of its financing and cash management activities, the Company uses derivative instruments to manage its exposure to changes in interest rates and foreign exchange rates. These instruments are principally interest rate and currency swaps. The Company also enters into commodity derivatives as part of its ordinary commercial, optimization and risk management activities, as well as exceptionally to hedge the exposure to variability in future cash flows due to movements in commodity prices, in view of pursuing acquisitions of oil&gas reserves as part of the Company’s ordinary asset portfolio management or other strategic initiatives or in case of extraordinary market conditions.

The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of undertaking finance, treasury and risk management operations based on the Company’s departments of operational finance: the parent company’s (Eni SpA) finance department and its subsidiarie Banque Eni, which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk, and Eni Trade & Biofuels SpA and Eni Global Energy Markets (from January 1, 2021, together formerly Eni Trading & Shipping) that are in charge to execute certain activities relating to commodity derivatives. In particular, Eni SpA manage the Group subsidiaries’ financing requirements covering funding requirements and using available surpluses. All transactions concerning currencies and derivative contracts on interest rates and currencies are managed by the parent company. With respect to the commodity risk, Eni Trade & Biofuels and Eni Global Energy Markets centralize the negotiation of financial instruments on the markets.

In 2021, the above mentioned centralized model for the execution of financial instruments has been updated in light of the relevant changes in the main financial regulations (Mifid II/EMIR/Dodd Frank act). Eni’s activities comply with the regulatory requirements for the execution of financial instruments on European and non-European Regulated Markets, on Multilateral Trading Facilities, on Organized Trading Facilities or bilaterally with OTC counterparties.

In addition to the reinforcement of the centralized execution model, as required by the financial regulation, all derivative transactions are classified and segregated in accordance with the EMIR requirements of “risk reducing” and “non-risk reducing” derivative contracts. The Company’s activities in financial instruments were thus classified in order to clearly: a) segregate ex ante non-risk reducing activities; b) define before inception the types of derivative contracts included in the hedging portfolios and the eligibility criteria, and stating that the derivative transactions included in the hedging portfolios are limited to covering risks directly related to commercial or treasury financing activities; and c) provide for a sufficiently disaggregated view of the hedging portfolios in terms of for example asset classes, products and time horizons, in order to establish the direct link between the portfolio of hedging transactions and the risks that this portfolio seeks to hedge. A financial instrument can be qualified as risk reducing when, by itself or in combination with other derivative contracts (so-called macro or portfolio hedging) it:

| (i) | directly or through closely correlated instruments (so-called proxy hedging) covers the risks arising from potential changes in the value of different assets under Eni control or that Eni will have under its control in the normal course of business driven by fluctuation of interest rates, inflation rates, foreign exchange rates or credit risk; or
| (ii) | qualifies as a hedge pursuant to IFRS.

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Use of financial instruments (in euro or currencies different from euro) is allowed with the following risk reducing purposes:

• | Back-to-back: includes market risk-free instruments that are negotiated in accordance with an execution criteria and normally settled with an intermediation fee. They normally comply with hedge accounting requirements or own use exemption. These are transaction-based activities characterized by a substantial absence of market risk. A hedging instrument can be considered back to back when the financial derivative is structured as to match as much as possible asset class, size and maturity of the hedged position. As a result, the combination of the hedged item, normally a single asset/contract, and the hedging instrument, i.e. the financial derivative, is substantially market risk free or is exposed only to a basic risk related to the ineffective portion of the hedging item. In addition, the hedging item may entail counterparty risk and operational risk. These derivatives are normally accounted for as hedges for financial statement purposes.
• | Flow hedging: flow hedging seeks to optimize Group hedging requirements by pooling different positions retained by the business units and then by entering derivative instruments to hedge net exposures, according to a portfolio basis. A central department processes a continuous flow of orders from the Group’s various business units and then acts as a single broker on financial markets. Flow hedging is characterized by the lack of direct control by the central broker entity on the received orders, which are normally related to assets managed by the business units. The central broker entity can normally rely on a continuous flow of hedging orders that can be predictable to a large extent, on the basis of the regular hedging programs made by the Group’s business units. The central entity is therefore in the position to net opposite orders, by retaining the level of risk necessary to cover timing, volume and asset class mismatch among orders. The benefits are the maximization of integration across the whole of the Group assets portfolio and the related netting potential, avoiding unnecessary derivatives, thus reducing costs and aggregated notional amounts of hedging programs. Flow hedging is managed on a portfolio basis and is dynamic by nature, since resulting net position is normally adjusted in order to take into account new orders received and maximum allowed exposure, related to timing, volume and asset classes mismatch. Those derivatives are recorded in profit and loss as the hedging of net exposures does not qualify as hedges under IFRS.
• | Asset-backed hedging: is a portfolio-based activity performed to enhance assets extrinsic value which is the fair value that a third party would potentially pay to buy the flexibility associated with assets available to the Group. It is normally characterized by a maximum level of market risk related to the size of managed assets and the volatility of underlying commodities. The more flexible the asset, the higher its extrinsic value that can be normally quantified as an option premium, linked to the price of an underlying commodity, volatility, time, interest rate. To enhance the value of asset flexibility, a business unit may transfer to a central entity part or the whole of an asset flexibility or a portfolio of flexibilities and the central entity will hedge such flexibility on financial markets so to lock its value by monetizing it via derivatives. Hedging strategies adopted for asset-backed hedging are normally portfolio based, very dynamic and entail large use of proxies. Depending on the optimization model such strategies are continuously adjusting relevant hedging ratios buying and selling the same financial products several times, since the underlying asset flexibility to be hedged is changing depending on price level, price volatility, time to delivery, etc. These derivatives may lead to gains as well as losses which in each case may be significant and are accounted through profit and loss as they lack the hedge requirements provided by IFRS. However, we believe that the risks associated with those derivatives are mitigated by the natural hedge granted by the asset availability.
• | Portfolio management: is a portfolio based activity performed on a combination of underlying positions, such as physical assets (production plants, transmission infrastructures, storages, etc.), commercial assets (spot and forward short/medium/long term supply and sale contracts with physical delivery) and related financial derivatives. Normally, the target of a portfolio management activity is to optimize managed assets’ base by running quantitative models which, given production/consumption forecasts, price scenarios and logistic flexibility/constraints, determine the optimal configuration in terms of volume, price and flexibility for physical and commercial assets in the portfolio. Financial derivatives are then used in the portfolio management activity in order to manage the overall risk level associated with such optimal configuration within a set tolerance or to balance the combined risk-reward profile of the portfolio in line with the Company’s targets. Market risk associated with portfolio management is proportional to assets size and maturity and volatility/correlation of underlying markets. Financial derivatives are normally used to hedge the resulting net position, but they might hedge also single physical/commercial assets included in the portfolio. The activity is dynamic by nature, since optimization models are run periodically, even on a daily and infra-daily timescale, in order to rebalance optimal configuration in view of actual or forecast changes in volumes, prices and flexibility. As a consequence, financial derivatives are also managed dynamically, with a continuous adjustment that might lead to buy and sell the same financial product several times in a given time frame. These derivatives may lead to gains, as well as losses which in each case may be significant and are accounted through profit as they lack the hedge requirements provided by IFRS.

Pursuant to internal policy, all derivatives transactions concerning interest rates and foreign currencies are executed for risk reducing purposes, as described above. Only commodity derivatives can also be executed in the context of non-risk reducing operations and be consequently classified as Proprietary Trading, which is an ancillary activity not related to industrial assets that makes use of financial derivatives which are entered into with the objective to obtain an uncertain profit, if favorable market expectations occur.

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Eni monitors on a daily basis that every activity involving derivatives is correctly classified according to the risk reducing taxonomy (i.e. back to back, flow hedging, asset-backed hedging or portfolio management), is directly or indirectly related to the hedged industrial assets and effectively optimizes the risk profile to which Eni is, or could be, exposed. When some derivatives fail to prove their risk reducing purpose, they are reclassified as Proprietary Trading. Provided that Proprietary Trading is segregated ex ante from other activities, its resulting market risk exposure is subject to specific limits expressed in terms of Stop Loss, VaR and notional amounts. The aggregated notional amounts of non-risk reducing derivatives at Group/Entity level are constantly benchmarked with the thresholds required by relevant international financial regulations.

Please refer to “Item 18 — Note 28 of the Notes on Consolidated Financial Statements” for a qualitative and quantitative discussion of the Company’s exposure to market risks.

Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Item 12A. Debt securities

Not a pplica b le.

Item 12B. Warrants and rights

Not a pplica b le.

Item 12C. Other securities

Not a pplica b le.

Item 12D. American Depositary Shares

In the United States, Eni’s securities are traded in the form of American Depositary Shares (ADSs) which are listed on the NYSE. ADSs are evidenced by American Depositary Receipts (ADRs), and each ADR represents two Eni ordinary shares.

Pursuant to the Deposit Agreement dated June 27, 2017 (the “Deposit Agreement”) between Eni, Citibank N.A. and the holders and beneficial owners ADSs, Citibank N.A. serves as the Depositary for Eni’s ADR Program, and Citibank N.A. Milan Branch serves as Custodian.

Computershare is the transfer agent for the Eni’s ADR Program.

Fees and charges payable by ADR holders

Pursuant to the Deposit Agreement, ADR holders may be required to pay various fees to the Depositary, and the Depositary may refuse to provide any service for which a fee is assessed until the applicable fee has been paid.

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The f ollo wing ADS fees ar e pa y ab le under the terms of the Deposit Agreement:

| Service |  | Rate |  | By Whom Paid
(1) | Issuance of ADSs (e.g., an issuance upon a deposit of Shares, upon a change in the ADS(s)-to-Share(s) ratio, or for any other reason), excluding issuances as a result of distributions described in paragraph (4) below. |  | Up to U.S. $5.00 per 100 ADSs (or fraction thereof) issued. |  | Person receiving ADSs.
(2) | Cancellation of ADSs (e.g., a cancellation of ADSs for delivery of deposited Shares, upon a change in the ADS(s)-to-Share(s) ratio, or for any other reason). |  | Up to U.S. $5.00 per 100 ADSs (or fraction thereof) cancelled. |  | Person whose ADSs are being cancelled.
(3) | Distribution of cash dividends or other cash distributions (e.g., upon a sale of rights and other entitlements). |  | Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held. |  | Person to whom the distribution is made.
(4) | Distribution of ADSs pursuant to (i) stock dividends or other free stock distributions, or (ii) an exercise of rights to purchase additional ADSs. |  | Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held. |  | Person to whom the distribution is made.
(5) | Distribution of securities other than ADSs or rights to purchase additional ADSs (e.g., spin-off shares). |  | Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held. |  | Person to whom the distribution is made.
(6) | ADS Services. |  | Up to U.S. $5.00 per 100 ADSs (or fraction thereof) held on the applicable record date(s) established by the Depositary. |  | Person holding ADSs on the applicable record date(s) established by the Depositary.

Direct and indirect payments b y the Depositary

The Depositary has agreed to reimburse certain company expenses related to the ADR Program and incurred in connection with the Program and the listing of Eni’s ADSs on the NYSE. These expenses are mainly related to legal and accounting fees incurred in connection with the preparation of regulatory filings and other documentation related to ongoing SEC compliance, NYSE listing fees, listing and custodian bank fees, advertising, certain investor relationship programs or special investor relations activities.

For the year 2025, the Depositary reimbursed to Eni $ 3,123,079.19 in connection with the above mentioned expenditures.

The Depositary has a lso a g r eed to w a ive certain standard fees associated with the administration of the ADR Pro g ram.

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P ART II

Item 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.

Item 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

None.

Item 15. CONTROLS AND PROCEDURES

Dis c losu r e cont r ols and p r ocedu r es

In designing and evaluating the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)), the Company’s management, including the Chief Executive Officer and the Head of Eni’s Accounting and Financial Statements department in his capacity as Officer in Charge of the Preparation of Corporate Accounts (“Dirigente Preposto alla redazione dei documenti contabili societari” pursuant to the Italian Consolidated Financial Law — Legislative Decree No. 58 of February 24, 1998), recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and the Company’s management necessarily was required to apply its judgment in evaluating the cost benefit relationship of possible controls and procedures. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected.

It should be noted that the Company has investments in certain non-consolidated entities. As the Company does not control or manage these entities, its disclosure controls and procedures with respect to such entities are necessarily more limited than those it maintains with respect to its consolidated subsidiaries.

The Company’s management, with the participation of the Chief Executive Officer and the Head of Eni’s Accounting and Financial Statements department, has evaluated the effectiveness of the design and operation of its disclosure controls and procedures pursuant to Rule 13a-14(c) under the Exchange Act as of the end of the period covered by this Annual Report on Form 20-F. Based on that evaluation, the Chief Executive Officer and the Head of Eni’s Accounting and Financial Statements department have concluded that these disclosure controls and procedures are effective.

Mana g ement’s Annual R epo r t on Internal Cont r ol o v er Financial R epo r ting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rules 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of an internal control system may change over time.

Management has excluded 58 entities from its assessment of internal control over financial reporting as of December 31, 2025 because they were acquired by the Company in several purchase business combinations during 2025. These entities, which are wholly- owned, comprised, in the aggregate, total assets and total revenues excluded from management's assessment of internal control over financial reporting of approximately 1% of consolidated total assets and a null value in terms of consolidated total revenues as of and for the year ended December 31, 2025.

The Internal Control Committee assists the Board of Directors in setting out the main principles for the internal control system so as to appropriately identify and adequately evaluate, manage, and monitor the main risks related to the Company and its subsidiaries, by laying down the compatibility criteria between said risks and sound corporate management. In addition, this Committee assesses, at least annually, the adequacy, effectiveness, and actual operations of the internal control system.

The Company’s management, including the Chief Executive Officer and the Head of Eni’s Accounting and Financial Statements department, conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (CoSO) in 2013. Based on the results of this evaluation, the Group’s management concluded that its internal control over financial reporting was effective as of December 31, 2025.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2025, has been audited by PricewaterhouseCoopers SpA, an independent registered public accounting firm, as stated in its report that is included on page F-1 of this Annual Report on Form 20-F.

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Chan g es in Internal Cont r ol o v er Financial R epo r ting

There have not been changes in the Company’s Internal Control over Financial Reporting that occurred during the period covered by this Form 20-F that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 16. [RESE R VED]

Item 16A. Boa r d of Statutory A uditors f inancial e xpert

Eni’s Board of Statutory Auditors has determined that the five members of Eni’s Board of Statutory Auditors are “audit committee financial expert”: Rosalba Casiraghi, who is the Chairman of the Board, Enrico Maria Bignami, Marcella Caradonna, Giulio Palazzo and Andrea Parolini. All members are independent.

Item 16 B. Code of Ethics

Eni adopted a Code of Ethics that applies to all Eni’s employees, including Executive Officers, principal Financial and Accounting Officers, Directors and Statutory Auditors. Eni published its Code of Ethics on Eni’s website. It is accessible at www.eni.com, under the section Governance. A copy of this Code of Ethics is included as an exhibit to this Annual Report on Form 20-F. Information on our website is not incorporated by reference into this report.

Eni’s Code of Ethics contains ethical guidelines, describes corporate values and requires standards of business conduct and moral integrity. The ethical guidelines are designed to deter wrongdoing and to promote honest and ethical conduct, compliance with applicable laws and regulations and internal reporting of violations of the guidelines. The code affirms the principles of accounting transparency and internal control and endorses human rights and the issue of the sustainability of the business model.

Item 16 C. Principal accountant fees and services

PricewaterhouseCoopers SpA (PwC SpA) served as Eni’s principal independent registered public accounting firm for fiscal year 2025, for which audited Consolidated Financial Statements have been included in this Annual Report on Form 20-F. PwC SpA, as the main external auditor, is wholly in charge of the auditing activities of the Consolidated Financial Statements.

The following table reports total fees for services rendered to Eni by PwC SpA and member firms of its network for the years ended December 31, 2025 and 2024.

|  | Year ended December 31,
|  | 2025 |  |  | 2024
|  | (€ thousand)
Audit fees |  | 31,071 |  |  | 30,098
Audit -related fees (a) |  | 2,663 |  |  | 1,739
Tax fees |  | - |  |  | -
All other fees |  | - |  |  | -
Total |  | 33,734 |  |  | 31,837

(a) Audit related services provided by PwC SpA and the member firms of its network mainly relate to services for the issue of comfort letters, financial and tax vendor due diligence related to the sale of a minority stake in Eni Plenitude Spa Società Benefit, services related to the report prepared by Eni SpA on payments to governments and agreed verification procedures on cost recharge rates.

Audit fees include professional services rendered by the principal accountant for the audit of the registrant’s annual financial statements or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements, including the audit on the Company’s internal control over financial reporting.

Audit-related fees include assurance and related services by the principal accountant that are reasonably related to the performance of the audit or review of the registrant’s financial statements and are not reported as Audit fees in this Item. The fees disclosed in this category mainly include, merger and acquisition due diligence, audit, certification services not required for by law and regulations and consultations concerning financial accounting and reporting standards.

Tax fees include professional services rendered by the principal accountant for tax compliance, tax advice, and tax planning.

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All other fees include products and services provided by the principal accountant, other than the services reported in Audit fees, Audit-related fees and Tax fees of this Item and consists primarily of fees billed for consultancy services related to IT and secretarial services that are permissible under applicable rules and regulations.

P r e-app r o v al policies and p r ocedu r es of the Internal Cont r ol Committee

The Board of Statutory Auditors has adopted a pre-approval policy for audit and non-audit services that set forth the procedures and the conditions pursuant to which services proposed to be performed by the principal auditors may be pre-approved. Such policy is applied to entities controlled (directly or indirectly) by Eni SpA as well as to jointly controlled entities that are material to the Eni Group. According to this policy, permissible services within the other audit services category are pre-approved by the Board of Statutory Auditors. The Board of Statutory Auditors approval is required on a case-by-case basis for those requests regarding: (i) audit-related services; and (ii) non-audit services to be performed by the external auditors which are permissible under applicable rules and regulations. In such cases, the Company’s Internal Audit Department is charged with performing an initial assessment of each request to be submitted to the Board of Statutory Auditors for approval. The Internal Audit Department periodically reports to Eni’s Board of Statutory Auditors on the status of both pre-approved services and services approved on a case-by-case basis rendered by the external auditors.

During 2025 and 2024, no audit-related fees, tax fees or other non-audit fees were approved by the Board of Statutory Auditors pursuant to the de minimis exception to the pre-approval requirement provided by paragraph (c)(7)(i) (C) of Rule 2-01 of Regulation S-X.

Item 16 D. E x emptions f r om the Listing Standa r ds f or A udit Committees

Making use of the exemption provided by Rule 10A-3(c)(3) for foreign private issuers, Eni has identified the Board of Statutory Auditors as the body that, starting from June 1, 2005, performs the functions required by the U.S. SEC rules and the Sarbanes-Oxley Act to be carried out by the audit committees of non-U.S. companies listed on the NYSE (see “Item 6 — Board of Statutory Auditors” above).

Item 16E. Pu r chases of equity securities by the issuer and af f iliated pu r chasers

Eni’s Board of Directors, in execution of the authorization granted by the Eni Shareholders’ Meeting of May 14, 2025 directed the management to carry out a share buy-back program of the Eni's common shares for a total maximum of €3.5 billion through April 2026. As a part of the Board mandate, the management resolved to repurchase €1.8 billion worth of Eni’s shares. The purchases started on May 20, 2025 and ended on February 18, 2026 for a total amount of €1.8 billion.

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Period |  | Total number of shares purchased |  | Average weighted price paid per share |  | Total number of shares purchased as part of publicly announced plans or programs |  | Total purchase cost |  | Approximate € value of Shares that may yet be purchased under the plans or programs
|  |  |  | € per share |  |  |  | (€ million) |  | (€ million)
2025 |  |  |  |  |  |  |  |  |  |
2 January - 31 January |  | 16,089,680 |  | 13.67 |  | 16,089,680 |  | 220 |  | 141
3 February - 20 February |  | 10,108,091 |  | 13.91 |  | 10,108,091 |  | 141 |  | 0
Total as of February 20, 2025 (a) |  | 26,197,771 |  | 13.79 |  | 26,197,771 |  | 361 |  |
Start of the program May 20 - May 30, 2025 |  | 6,939,908 |  | 12.97 |  | 6,939,908 |  | 90 |  | 1,710
2 June - 30 June |  | 15,296,352 |  | 13.73 |  | 15,296,352 |  | 210 |  | 1,500
1 July - 31 July |  | 16,150,368 |  | 14.26 |  | 16,150,368 |  | 230 |  | 1,270
1 August - 29 August |  | 12,666,009 |  | 14.98 |  | 12,666,009 |  | 190 |  | 1,080
1 September - 30 September |  | 9,091,390 |  | 14.99 |  | 9,091,390 |  | 136 |  | 944
1 October - 31 October |  | 14,670,175 |  | 15.25 |  | 14,670,175 |  | 224 |  | 720
3 November - 28 November |  | 9,321,703 |  | 16.09 |  | 9,321,703 |  | 150 |  | 570
1 December - 30 December |  | 18,119,850 |  | 16.00 |  | 18,119,850 |  | 290 |  | 280
2026 |  |  |  |  |  |  |  |  |  |
2 January - 30 January |  | 10,821,022 |  | 16.48 |  | 10,821,022 |  | 178 |  | 102
2 February - 18 February |  | 5,706,151 |  | 17.82 |  | 5,706,151 |  | 102 |  | 0
Total as of February 18, 2026 |  | 118,782,928 |  | 15.15 |  | 118,782,928 |  | 1,800 |  |
(a) Share buy-back program of € 2 billion authorized by Eni's Shareholders’ Meeting of May 15, 2024 started on May 27, 2024 and ended on February 20, 2025.

Item 16 F. Change in R egist r ant’s Certifying Accountant

Not Applicable

Item 16 G. Signi f icant diffe r ences in Corpo r ate G o v e r nance p r actices as per Section 303A.11 of the N e w Y ork Stock E x change Listed Compa n y Manual

Corporate Governance. Eni’s Governance structure follows the traditional model as defined by the Italian Civil Code which provides for two main separate corporate bodies, the Board of Directors and the Board of Statutory Auditors to whom management and monitoring duties are respectively entrusted. This model differs from the U.S. one-tier model in which the Board of Directors is the sole corporate body responsible for management, with an Audit Committee established within the Board performing monitoring activities. The following offers a description of the most significant differences between corporate governance practices adopted by U.S. domestic companies under the NYSE standards and those followed by Eni, including with reference to Corporate Governance Code approved by the Italian Corporate Governance Committee in January 2020 effective from January 1, 2021, which Eni has adopted on December 23, 2020 (the “Code”).

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Independent Directors

NYSE standards. In accordance with NYSE standards, the majority of the members on the Boards of Directors of U.S. companies must be independent. A Director qualifies as independent when the Board affirmatively determines that such Director does not have a material relationship with the listed company (and its subsidiaries), either directly, or indirectly. In particular, a Director may not be deemed independent if he or she or an immediate family member has a certain specific relationship with the issuer, its auditors or companies that have material business relationships with the issuer (e.g. he or she is an employee of the issuer or a partner of the Auditor). In addition, a Director cannot be considered independent in the three-year “cooling-off” period following the termination of any relationship that compromised a Director’s independence.

Eni standards. In Italy, the Consolidated Law on Financial Intermediation states that at least one of the Directors or two, if the Board is composed of more than seven members, must meet the independence requirements for Statutory Auditors of listed companies. In particular, a Director may not be deemed independent if he/she or an immediate family member has a relationship with the issuer, with its Directors or with the companies that control the issuer or are controlled by the issuer or are under the common control with the issuer that could influence the independence of judgment. For the purposes of such provisions, Decree-Law no. 95/2025, converted into Law no. 118/2025, stated that “companies” means exclusively entities, other than the State and public administrations, that hold shareholdings as part of their own business activity or for economic or financial purposes.

Eni’s By-laws require that at least one Director — if the Board has no more than five members — or at least three Directors — if the Board is composed of more than five members — must satisfy the independence requirements. The Corporate Governance Code provides for additional independence requirements, recommending that a significant number of non-executive directors is independent. In particular, in large companies other than those with concentrated ownership, like Eni, independent directors should account for at least half of the board. Independence is defined as not having currently or recently entered into, nor recently had, even indirectly, relations with the company or with subjects related to the latter, such as to condition their current autonomy of judgment. The Corporate Governance Code identifies the circumstances that jeopardise, or appear to jeopardise, the independence of a director. Immediately after the appointment of a Director who qualifies as independent and subsequently, upon the occurrence of circumstances that concern the independence and in any case at least once a year, the Board of Directors assesses the independence of the Director. The Board of Statutory Auditors verifies the correct application of the criteria and procedures adopted by the Board of Directors to evaluate the independence of its members. The Board of Directors shall disclose to the market the outcome of its assessment, immediately after the appointment, through a specific press release and, later, in the Annual Corporate Governance Report. In accordance with Eni’s By-laws, if a Director, who qualifies as independent, does not or no longer satisfies the independence requirements established by law, the Board declares the Director disqualified and provides for their substitution. Directors shall notify the Company if they should no longer satisfy the independence and integrity requirements or if cause for ineligibility or incompatibility should arise.

Meetings of non-ex ecut i v e Di r ectors

NYSE standards. Non-executive Directors, including those who are not independent, must meet on a regular basis without the executive Directors. In addition, if the group of non-executive Directors includes Directors who are not independent, independent Directors should meet separately at least once a year.

Eni standards. Pursuant to Corporate Governance Code, independent Directors shall meet at least once a year in the absence of the other Directors.

On May 11, 2023, the Board of Directors of Eni confirmed Raphael Louis L. Vermeir Lead Independent Director. Pursuant to Italian Corporate Governance Code, the Lead Independent Director collects and coordinates the requests and contributions of non-executive directors and, in particular, of independent ones and coordinates the meetings of the independent directors.

During 2025, the independent Directors, coordinated by the Lead Independent Director, met on September 15 and, taking into account the frequency of board meetings, had further informal meeting opportunities on these occasions to exchange views, pursuant to the Corporate Governance Code recommendations.

A udit Committee

N Y SE standa r ds. Listed U.S. companies must have an Audit Committee that satisfies the requirements of Rule 10A-3 under the Securities Exchange Act of 1934 and that complies with the provisions of the Sarbanes-Oxley Act and of Section 303A.07 of the NYSE Listed Company Manual.

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Eni standa r ds. At its Meeting of March 22, 2005, the Board of Directors, as permitted by the rules of SEC applicable to foreign issuers listed on regulated U.S. markets, assigned to the Board of Statutory Auditors, effective from June 1, 2005 and within the limits set by Italian law, the functions specified and the responsibilities assigned to the Audit Committee of such foreign issuers by the Sarbanes-Oxley Act and the SEC rules (see “Item 6 — Board of Statutory Auditors” earlier). Under Section 303A.07 of the NYSE Listed Company Manual, audit committees of U.S. companies have additional functions and duties which are not mandatory for non-U.S. private issuers and which are therefore not included in the list of functions reported in “Item 6 — Board of Statutory Auditors”.

Nominating/Corpo r ate G o v e r nance Committee

NYSE standards. U.S. listed companies must have a Nominating/Corporate Governance Committee (or equivalent body) composed entirely of independent Directors whose functions include, but are not limited to, selecting qualified candidates for the office of Director for submission to the Shareholders’ Meeting, as well as developing and recommending corporate governance guidelines to the Board of Directors. This provision is not binding for non-U.S. private issuers.

Eni standards. Pursuant to the Code, the Board of Directors shall establish among its members a nomination committee the majority of whose members shall be independent Directors. The Nomination Committee of Eni is made up of three to four Directors, a majority of whom shall be independent in accordance with the recommendations of the Code. On May 11, 2023, the Board of Directors of Eni established the Nomination Committee, chaired by Carolyn Adele Dittmeier (independent Director) and composed of Elisa Baroncini (independent Director) and Massimo Belcredi (independent Director).

Further details on this Committee are reported in the Item 6.

R emune r ation Committee

NYSE standards. U.S. listed companies must have a Remuneration Committee composed entirely of independent Directors who must satisfy the independence requirements provided for its members. The Remuneration Committee must have a written charter that addresses the Committee’s purpose and responsibilities within the limit set forth by the listing rules. The Remuneration Committee may, in its sole discretion, retain or obtain the advice of a compensation consultant, independent legal counsel or other adviser and shall be directly responsible for the appointment, compensation and oversight of the work of any compensation consultant, independent legal counsel or other adviser retained by it. These provisions are not binding for non-U.S. private issuers.

Eni standards. Pursuant to the Corporate Governance Code, the Board of Directors shall establish among its members a Remuneration Committee made up of three to four non-executive Directors, all of whom shall be independent or, alternatively, a majority of whom shall be independent. In the latter case, the Chairman of the Committee shall be chosen from among the independent Directors. At least one of the Committee’s members shall have adequate knowledge and experience in financial matters or remuneration policies. First established by the Board of Directors in 1996, the Remuneration Committee is currently chaired by Director Massimo Belcredi (independent Director). The other members include Directors Cristina Sgubin, and Raphael Louis L. Vermeir, both independent Directors. Two out of three directors possess knowledge and experience in financial matters or remuneration policies. The composition and functions of the Remuneration Committee are outlined in the committee charter (“Rules”) available on the Company’s website.

Further details on this Committee are reported in the Item 6.

Code of Business Conduct and Ethics

NYSE standards. The NYSE listing standards require each U.S. listed company to adopt a Code of Business Conduct and Ethics for its Directors, Officers and employees, and to promptly disclose any waivers of the code for Directors or Executive Officers.

Eni standards. The Board of Directors of Eni, at its meetings of December 15, 2003 and January 28, 2004, approved an organizational, management and control model pursuant to Italian Legislative Decree No.231 of 2001 (hereinafter “Model 231”) and established the associated 231 Supervisory Body of Eni SpA, with the role of supervising the effectiveness of Model 231 and of assessing its suitability to prevent crimes provided in the Italian Legislative Decree No. 231 of 2001.

The Model 231 was most recently updated by resolution of the Board of Directors, in the meeting of June 26, 2025, taking into account the experience gained, amendments to Legislative Decree no. 231/2001, and the corporate organizational changes of Eni SpA.

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The autonomy and independence of the 231 Supervisory Body are guaranteed by the position recognized to it within the organizational structure of the Company, and by the requisites of independence, good standing and professionalism of its members.

Furthermore, the Board of Directors, in its meeting of March 18, 2020, approved the new version of Eni’s Code of Ethics, that has been updated to become a modern and effective Charter of Values, designed to inspire and guide the conduct of all members of the administrative and control bodies and employees of Eni and its stakeholders.

Eni’s Code of Ethics sets out a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all its business activities are conducted in compliance with the law, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all the stakeholders with whom Eni interacts on an ongoing basis. These include shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the countries where Eni operates. All Eni personnel, without exception or distinction, starting with Directors, senior management and members of the Company’s bodies, as also required under SEC rules and the Sarbanes-Oxley Act, are committed to observing and enforcing the principles set out in the Code of Ethics in the performance of their functions and duties.

Item 16H. Mine safety disclosu r e

Not applicable since Eni does not engage in mining operations.

Item 16I. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

Item 16J. Insider trading policies

Eni has adopted insider trading policies and procedures, governing the purchase, sale, and other dispositions of the Company’s securities by directors, senior management and employees, that are reasonably designed to promote compliance with applicable insider trading laws, rules and regulations, and any listing standards applicable to the Company.

The Management System Guideline “Market Information Abuse (Issuers)”, together with Annex C “Managers’ transactions and Blocking Periods” are filed as exhibit.

Item 16K. Cybersecurity

The Company is aware that the oil&gas sector is particularly vulnerable to cybersecurity risks because of the geographical reach of operations, the complexity of integrating IT infrastructures with industrial control systems, and exposure to geopolitical risks.

In this context, Eni’s has adopted a set of processes and systems for assessing, identifying and managing the significant risks related to cybersecurity threats with the goal of minimizing the impacts of any potential cybersecurity incidents and avoid as far as possible any disruptions to the Company’s information systems, information resources, data infrastructures and ultimately to its business operations given that information systems are core to our industrial activities, financial transactions and correct and complete record, storage and use of data regarding acquisition and disposition of Company’s assets, and customers and other third parties data.

Eni’s cybersecurity program includes multi-layered technological capabilities designed to prevent and detect cybersecurity disruptions and is based on industry standard frameworks. The cybersecurity program incorporates an incident response plan to engage cross-functionally across the Corporation and report cybersecurity incidents to appropriate levels of management, including senior management, and the Audit Committee or the Board of Directors, based on potential impact. The Group conducts continuous cybersecurity awareness training and routinely tests cybersecurity awareness and business preparedness for response and recovery, which are developed based on real-world threats.

In recent years the business environment has been characterized by a significant rise in the cybersecurity risks, both in terms of frequency of incidents and their relevance, driven by increased operation complexity and geopolitical factors. Eni has established and is maintaining a risk-assessment program specifically designated to identify and to manage cybersecurity risks and based on the outcome of this review has adopted a suite of mitigation measures and protocols. We believe that thanks to those remedies our overall exposure to the cybersecurity risks has remained stable as the Company has been able to counteract an increased number of attacks against the Company’s information systems, which have arisen in connection with the adoption of the hybrid working environment (for example remote working) and a changed environment for cyber threats in connection with a deteriorated geopolitical landscape. The use of AI for malicious activities strengthens existing attack techniques, including phishing, vulnerability research, and target reconnaissance. At the same time, it amplifies the scale and reach of false and targeted content, fueling misinformation.

The internal control system has been designed taking into consideration primarily the characteristics of the Eni business, the Company’s long-term strategy, its countries of operations, the specific risks the oil&gas sector is exposed to (see Item 3 - Risk Factors for more information), among which the cybersecurity risk ranks highly.

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Looking forward the Company believes that cybersecurity threats in the following areas may materially affect the Company’s business strategy, reputation, results of operations and financial conditions:

• | Disruptions to industrial processes which may lead to loss of revenues and unplanned and restoring expenses;
• | Interruption in the IT systems used by the businesses and corporate and finance departments which may lead to a temporarily inability to record physical data and dispositions of Company’s products, to send invoices, to collect receipts which may results in disruptions, loss of revenues and cash collections and higher finance expenses impacting the profit&loss and the financial condition;
• | Breaches, violations, and subtraction of retail customer data which may negatively affect the Company’s reputation and may lead to violations of laws on data protection and claims against us.

Considering the possible risks of cybersecurity incidents, the Group has adopted several mitigation measures of the cybersecurity risks, which include the continuous upgrading of the IT infrastructure following a security by design methodology, availability of services to protect the Company against cybersecurity threats, extension of those measures to the cloud, also integrating technologies based on AI, strengthening procedures and resources of technological security and governance at the headquarter, foreign subsidiaries and industrial hubs by means of deploying tailored programs of technological enforcement.

Centralized information systems have been upgraded to improve monitoring and specific controls and procedures have been adopted intended to identify, mitigate, and supervise cyber risks that could be brought in by third parties performing activities on behalf of Eni, including supplier of cloud services. The Group takes a risk-based approach with respect to its third-party service providers, tailoring processes according to the nature and sensitivity of the data or systems accessed by such third-party service providers and performing additional risk screenings and procedures, as appropriate.

To ensure continuity in the functioning of the Company’s information systems, management has deployed several measures (contingency plans) intended to ensure the uninterrupted performance of information systems in case of cybersecurity threats and other malfunctioning of IT systems with possible fallouts on business operations, as well as in case of massive cyber threats having low probability of occurrence but that could cause relevant system disruptions. Those measures include adoption of a continuity management plan of the information system infrastructures, which drives simultaneously technologies, processes and procedures with the goal of ensuring resiliency and recovery of information systems in accordance with minimum services levels dictated by the business lines.

In addition, the set of countermeasures to mitigate cyber risk has been updated, consistent with recent industry-specific, legal obligations such as the recent NIS2 Directive, but also taking out Cyber insurance for Eni and its subsidiary and by disseminating throughout the organization a cybersecurity culture aimed at making managers and employees more conscious about ongoing cyber threats and at how to deal with cyber risks. Those also include the management of fault scenarios, the preparation of contingency plans and the execution of stress tests and test simulations.

The Company owns a proprietary green data center where most of the Company’s applications and systems run, and massive amounts of the Company’s data are stored. Considering that this is a core asset, several measures and procedures have been adopted which are designated to ensure continuity in the performance of the Company’s information systems even in case of an outage of the whole data center, particularly by equipping a backup site to ensure a disaster recovery of most critical information systems and data warehouse, and by preserving continuity at the core business. The green data center has undergone an upgrading plan which comprised:

i) | advances in technological solutions to prevent and manage through automated procedures partial or component faults ;
ii) | availability of spare capacity to elaborate and manage data and/or availability of off-line backup data at other sites;
iii) | reinforcement of the geographic enterprise redundant connectivity to consume services from GDC and Cloud suppliers.

Eni’s risk management processes for cybersecurity are part of the Company’s overall integrated internal control system designed to identify, assess, and manage the main risks to which the Company is exposed which include strategic, business, operational and compliance risks, and menaces.

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The Company’s internal control system is designed by the Company’s management under the direct supervision of the Board of Directors and the ultimate supervision of the Board of Statutory Auditors. The Board of Directors sets the guidelines of the internal control system, sets the tone of an effective organizational environment that drives management to continuously monitor and treat Company risks, and finally determines the maximum level of tolerable exposure to the Company’s main risks in view of achieving the Company’s profitability and industrial targets and executing against its stated strategic vision, both on the short and the medium-long term.

In performing its function, the Board is assisted by a committee comprised by all independent board members, named the Internal Control Committee (for a full description of its role, functioning and composition see Item 6), who has the role of examining the Company’s internal control system and of assessing its effectiveness against the Company’s strategy and objectives and ongoing business trends and evolution. As part of this, the Committee formulates proposals, and suggestions to the Board about any possible improvement of the internal control system. This committee is regularly informed by management about ongoing trends in the business environment which could affect the Company’s exposure to the cybersecurity risk, how cyber threats are evolving, changes in the expected probability of cybersecurity incidents to the Company’s information systems, and management’s ongoing or planned action to mitigate emerging risks or an increased probability of cybersecurity incidents. The Board of Statutory Auditors is responsible for the overall supervision of the activities of the Board of Directors (consistent with the functions required by the U.S. SEC rules and the Sarbanes-Oxley Act) and in exercising this function it is kept duly informed by, and it has the power under applicable laws to demand information from, the Board of Directors and management about the Group cybersecurity risks and the processes for assessing and managing such risks.

The CEO of Eni is responsible for establishing and maintaining an effective internal control system and for executing the guidelines defined by the Board. In performing this ample task, the CEO coordinates other management representatives and reports to the Board and the Committee on a quarterly basis about how the Company is responding and reacting to the main risks in the business environment and in the Company’s industrial operations and support processes.

Middle management is responsible for identifying and assessing risks across the whole of Eni’s industrial and business- support processes, which could jeopardize the achievement of the Company’s targets. This activity is performed at various organizational levels: subsidiary, business process, profit center, cost center, department, and business-supporting functions, among others, and is structured in various steps.

• | First, risk identification and assessment enable each manager to gain a comprehensive picture of possible adverse events which could negatively affect the effectiveness and efficiency of Company’s processes and operations.
• | Second, potential adverse impacts associated with each risk event are estimated both in quantitative (i.e., impacts on financial results and business continuity) and qualitative (i.e., impacts on Company reputation) terms, also weighting impacts by probability of occurrence.
• | Third, mitigating actions and plans are implemented or those in place are revised to reduce any possible risks to a tolerable level
• | Finally, controls have been designed to test the effective functioning of mitigating actions.

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Top management is responsible for verifying and monitoring whether all risk-reducing actions and plans are compatible with the ongoing evolution of the Company’s business model, the Company’s strategic guidelines and targets, including financial targets (operating profits and cash flow from operations), operating targets (production volumes, installed capacity, development of new product lines), business security and continuity targets (HSE incidents, cybersecurity threats, security of personnel and assets in high-risk areas, climate-adaptation of Company’s plants and equipment) and preservation of Company’s reputation. Those activities enable management to gain full comprehension of the effectiveness of the internal control system and risk treatment considering current/expected trends in the business environment (market trends, consumer behavior, evolution of technologies and of the competitive landscape) and in the Company’s structure (entrance in new markets, significant asset acquisitions/dispositions, restructuring and reorganizations).

Top management, including the CEO, reports to the Board and the Committee on a regular basis about the effectiveness of the Company’s internal control system, its evolution in connection with emerging risks or significant modifications of the Company’s risk profile and possible improvements, covening all aspects of the business, including the cybersecurity risk.

The manager in charge of running the Company’s IT infrastructures and information systems identifies on a regular basis the main cybersecurity threat, to which the Company is exposed, assesses the level of vulnerability and adopts all IT solutions and security protocols to reduce those risks to an acceptable level.

We believe that this manager has the academic background and the experience in IT systems required to perform its tasks effectively.

The Company’s cybersecurity program is managed by an IT senior manager, with support from cross-functional teams led by Eni’s information technology (IT) and operational technology (OT) cybersecurity operations managers (collectively, Cybersecurity Operations Managers). The Cybersecurity Operations Managers are responsible for the day-to- day management and effective functioning of the cybersecurity program, including the prevention, detection, investigation, and response to cybersecurity threats and incidents. The Cybersecurity Operations Managers collectively have many years of experience in cybersecurity operations.

IT management provides regular reports to the Company’s senior management throughout the year, and to the Audit Committee or the Board of Directors, as appropriate, on a regular schedule. Such reports typically address, among other things, the Company’s cybersecurity strategy, initiatives, key security metrics, penetration testing and benchmarking learnings, and business response plans as well as the evolving cybersecurity threat landscape.

In the event the Company becomes aware of a pending cybersecurity threat, a “crisis committee” is convened comprising representatives of the Company’s top management (including the Company’s Chief Financial Officer) to decide promptly which course of action is to be implemented to best cope with the threat or to plan remedial actions in case of a significant cybersecurity incident as well as to assess the materiality of a cybersecurity incident and whether to publicly disclose a cybersecurity incident.

The cybersecurity risk is regularly monitored to assess the effectiveness of the Company’s risk-reducing activities, proper functioning of controls and to identify emerging risks that may warrant improvements/upgrading of the Company’s cybersecurity infrastructures and protocols. Those activities are reported regularly to the Board of Directors and the Internal Control Committee, as part of the general process of reporting the whole of the internal control system for risk management, so directors can appreciate the robustness of the whole of the process for identifying, assessing, and mitigating cybersecurity threats.

As of the date of this report, we have not identified any risks from known cybersecurity threats, including as a result of any prior cybersecurity incidents, that have materially affected, or are reasonably likely to materially affect the Company, including our business strategy, results of operations, or financial condition.

While Eni believes its cybersecurity program to be appropriate for managing constantly evolving cybersecurity risks, no program can fully protect against all possible adverse events. In 2025, no material cybersecurity incidents were reported. For additional information on these risks and potential consequences if the measures we are taking prove to be insufficient or if our proprietary data is otherwise not protected, see “Item 3 - Risk Factors” in this report.

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P ART III

Item 17. FINANCIAL STATEMENTS

NOT APPLICABLE

Item 18. FINANCIAL STATEMENTS

Inde x to Financia l Statements:

​​

| Page
Report of Independent Registered Public Accounting Firm (PCAOB ID:000 30) | F-1
Consolidated Balance Sheet as of December 31, 2025 and December 31, 2024 | F-4
Consolidated Profit and Loss Account for the years ended December 31, 2025, 2024 and 2023 | F-5
Consolidated Statement of Comprehensive Income for the years ended December 31, 2025, 2024 and 2023 | F-6
Consolidated Statement of Changes in Equity for the years ended December 31, 2025, 2024 and 2023 | F-7
Consolidated Statement of Cash Flows for the years ended December 31, 2025, 2024 and 2023 | F-10
Notes on Consolidated Financial Statements | F-12

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Item 19. EXHIBITS

1. | By-laws of Eni SpA
2. | Description of securities registered under Section 12 of the Exchange Act
8. | List of subsidiaries (see Item 18 – Note 37 – Other information about investments – of the Notes on Consolidated Financial Statements)
11. | Code of Ethics (incorporated by reference to Exhibit 11 to Form 20-F 2019 (File No. 001-14090) filed on April 2, 2020)
11.2 | Insider trading policy and procedure (incorporated by reference to Exhibit 11.2 to Form 20-F 2024 (File No. 001-14090) filed on April 4, 2025)
Certifications:
12.1. | Certifications pursuant to Rule 13a-14(a) of the Securities Exchange Act
12.2. | Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act
13.1. | Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)
13.2. | Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)
15.a(i) | Excerpt of the pages and sections of the report on the 2026 remuneration policy and remuneration paid 2025 prepared in accordance with Italian listing standards incorporated herein by reference
15.a(ii) | Report of R yder Scott Co
15.a(iii) | Report of Sproule
15.a(iv) | Report of DeGol yer and MacNaughton
15.a(v) | Report of DeGol yer and MacNaughton
97 | Executive Compensation Clawback policy (incorporated by reference to Exhibit 97 to Form 20-F 2024 (File No. 001-14090) filed on April 4, 2025)
99 | EU Taxonomy
101.INS | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH | Inline XBRL Taxonomy Extension Schema
101.CAL | Inline XBRL Taxonomy Extension Schema Calculation Linkbase
101.DEF | Inline XBRL Taxonomy Extension Schema Definition Linkbase
101.LAB | Inline XBRL Taxonomy Extension Schema Label Linkbase
101.PRE | Inline XBRL Taxonomy Extension Schema Presentation Linkbase
104. | Cover Page Interactive Date File (formatted as Inline XBRL and contained in Exhibit 101)

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SIGNATURES

The registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: March 23, 2026

|  | Eni SpA
|  | /s/ FRANCESCO ESPOSITO
|  | Francesco Esposito
|  | Title: Head of Accounting and
|  | Financial Statements

190

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Eni SpA

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheet of Eni SpA and its subsidiaries (the “Company”) as of December 31, 2025 and 2024, and the related consolidated profit and loss account and consolidated statements of comprehensive income, of changes in equity and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Annual Report on Internal Control over Financial Reporting appearing under Item 15. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As described in Management’s Annual Report on Internal Control over Financial Reporting, management has excluded 58 entities from its assessment of internal control over financial reporting as of December 31, 2025 because they were acquired by the Company in several purchase business combinations during 2025. We have also excluded these 58 entities from our audit of internal control over financial reporting. These entities, each of which is wholly-owned, comprised, in the aggregate, total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting of approximately 1% and 0% of consolidated total assets and consolidated total revenues, respectively, as of and for the year ended December 31, 2025.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

The Impact of Estimated Proved Oil and Natural Gas Reserves on E&P Property, Plant and Equipment, Net

As described in Notes 1 and 12 to the consolidated financial statements, the Company’s consolidated net property, plant and equipment (PP&E) was €50.5 billion as of December 31, 2025, of which €41.0 billion relates to the Exploration and Production (E&P) segment. The Company’s depreciation, depletion and amortization (DD&A) expense for E&P wells, plant and machinery was €5.3 billion for the year ended December 31, 2025. Oil and natural gas exploration, appraisal and development activities are accounted for using the principles of the successful efforts method of accounting. Under this method, depreciation of investments relating to mineral activities is generally calculated using the unit of production (UOP) method. In particular: (i) exploration rights and mineral titles acquired related to proved reserves are amortised considering total proved reserves; (ii) capitalised exploration, appraisal and development costs related to production facilities are amortised considering proved developed reserves and facilities are depreciated considering total proved reserves; (iii) for owned floating facilities, depreciation is calculated using the UOP method considering the recovery of proved reserves. The estimate of the reserves depends on a number of factors, assumptions and variables, including: (i) the quality of available geological and technical engineering data; (ii) projections regarding future rates of production and operating costs and development costs; (iii) changes in the prevailing tax rules, other government regulations and contractual conditions; (iv) results of drilling, testing and the actual production performance of the Company’s reservoirs; and (v) changes in oil and natural gas commodity prices. As disclosed by management, staff involved in the reserves evaluation process have qualifications that comply with international standards and proved reserves are evaluated on a rotational basis by independent oil engineering companies (collectively “management’s specialists”).

The principal considerations for our determination that performing procedures relating to the impact of estimated proved oil and natural gas reserves on E&P PP&E, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved oil and natural gas reserves; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and management’s specialists in developing the estimates of proved oil and natural gas reserves; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil and natural gas reserves. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of proved oil and natural gas reserves. As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included (i) evaluating the data, methods and assumptions used by management and management’s specialists; (ii) testing the completeness and accuracy of the underlying data used by the specialists related to historical production volumes; and (iii) evaluating the specialists’ findings related to future production volumes by comparing the future production volumes to relevant historical and current period production volumes, as applicable. Professionals with specialized skill and knowledge were used to assist in (i) evaluating the process related to the reserve estimates including certain data, methods and assumptions used by management’s specialists and (ii) evaluating and testing, on a sample basis, the relevance and reliability of geological and technical engineering data used by management’s specialists to develop the reserve estimates.

Recoverability Assessment of Certain E&P Property, Plant and Equipment, Net

As described in Notes 1 and 12 to the consolidated financial statements, the Company’s consolidated net PP&E was €50.5 billion as of December 31, 2025, of which €41.0 billion relates to the E&P segment. The Company incurred impairment losses, net of recognized impairment reversals, before taxes associated with the E&P segment of €1.1 billion for the year ended December 31, 2025. The recoverability assessment is performed for each cash-generating unit (CGU) represented by the smallest identifiable group of assets that generate cash inflows that are largely independent of the cash inflows from other assets or group of assets. The assessment of the recoverability of non-financial assets depends on management estimates on highly uncertain and complex matters such as future commodity prices, future discount rates, future development costs and production costs, and the effects of inflation. For the determination of value in use, the estimated future cash flows are discounted using a rate that reflects a current market assessment of the time value of money and of the risks specific to the asset that are not reflected in the estimated future cash flows. For oil and natural gas properties, the expected future cash flows are estimated based on proved and probable reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. The estimate of the future rates of production is based on assumptions related to future commodity prices, operating costs, lifting and development costs, field decline rates and other factors. When an impairment loss no longer exists or has decreased, a reversal of the impairment loss is recognised in the profit and loss account. The impairment reversal shall not exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognised for the asset in prior years.

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The principal considerations for our determination that performing procedures relating to the recoverability assessment of certain E&P PP&E, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the value in use of oil and natural gas properties; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to the discount rates, future rates of production, future commodity prices including the effects of inflation, and future development costs and production costs, as applicable to the CGU; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s E&P PP&E, net recoverability assessment. These procedures also included, among others, (i) testing management’s process for assessing the recoverability of carrying amounts of E&P PP&E, net; (ii) evaluating the appropriateness of the value in use models used by management; (iii) testing the completeness and accuracy of underlying data used in the value in use models; and (iv) evaluating the reasonableness of significant assumptions used by management related to future rates of production, future commodity prices, future development costs and production costs, and the discount rates. Evaluating management’s assumptions related to future commodity prices involved comparing the assumptions to observable market data. Evaluating management’s assumptions related to future development costs and production costs involved comparing the assumption to the past performance of the Company. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of proved and probable oil and natural gas reserves and the reasonableness of the future production volumes. As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included (i) evaluating the data, methods and assumptions used by the specialists; (ii) testing the completeness and accuracy of the underlying data used by the specialists related to historical production volumes; and (iii) evaluating the specialists’ findings related to future production volumes by comparing the future production volumes to relevant historical and current period production volumes, as applicable. Professionals with specialized skill and knowledge were used to assist in (i) evaluating the process related to the reserve estimates including certain data, methods and assumptions used by management’s specialists; (ii) evaluating and testing, on a sample basis, the relevance and reliability of geological and technical engineering data used by the specialists to develop the reserve estimates; (iii) evaluating the appropriateness of the value in use models; (iv) evaluating the reasonableness of the future commodity prices including the effects of inflation assumption; and (v) evaluating the reasonableness of the discount rates assumption.

/s/ PricewaterhouseCoopers SpA

Rome, Italy

March 23, 2026

We have served as the Company’s auditor since 2019.

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CONSOLIDATED BALANCE SHEET

(€ million)

|  | December 31, 2025 | December 31, 2024
| Note | Total amount | of which with related parties | Total amount | of which with related parties
ASSETS |  |  |  |  |
Current assets |  |  |  |  |
Cash and cash equivalents | (6) | 8,100 |  | 8,183 |
Financial assets at fair value through profit or loss | (7) | 6,991 |  | 6,797 |
Other current financial assets | (17) | 3,710 | 2,357 | 1,085 | 48
Trade and other receivables | (8) | 12,436 | 1,375 | 16,901 | 1,601
Inventories | (9) | 5,143 |  | 6,259 |
Income tax receivables | (10) | 539 |  | 695 |
Other current assets | (11) (24) | 3,943 | 76 | 3,662 | 54
|  | 40,862 |  | 43,582 |
Non-current assets |  |  |  |  |
Property, plant and equipment | (12) | 50,536 |  | 59,864 |
Right-of-use assets | (13) | 5,184 |  | 5,822 |
Intangible assets | (14) | 6,022 |  | 6,434 |
Inventory - Compulsory stock | (9) | 1,187 |  | 1,595 |
Equity-accounted investments | (16) (37) | 13,155 |  | 14,150 |
Other investments | (16) | 1,329 |  | 1,395 |
Other non-current financial assets | (17) | 1,109 | 612 | 3,215 | 2,380
Deferred tax assets | (23) | 6,716 |  | 6,322 |
Income tax receivables | (10) | 125 |  | 129 |
Other non-current assets | (11) (24) | 2,839 | 207 | 4,011 | 142
|  | 88,202 |  | 102,937 |
Assets held for sale | (25) | 8,005 |  | 420 |
TOTAL ASSETS |  | 137,069 |  | 146,939 |
LIABILITIES AND EQUITY |  |  |  |  |
Current liabilities |  |  |  |  |
Short-term debt | (19) | 4,929 | 265 | 4,238 | 136
Current portion of long-term debt | (19) | 3,434 | 128 | 4,582 | 21
Current portion of long-term lease liabilities | (13) | 1,263 | 108 | 1,279 | 152
Trade and other payables | (18) | 20,261 | 4,283 | 22,092 | 4,017
Income tax payables | (10) | 343 |  | 587 |
Other current liabilities | (11) (24) | 4,039 | 86 | 5,049 | 34
|  | 34,269 |  | 37,827 |
Non-current liabilities |  |  |  |  |
Long-term debt | (19) | 20,139 | 52 | 21,570 | 79
Long-term lease liabilities | (13) | 4,437 | 40 | 5,174 | 31
Provisions | (21) | 14,580 |  | 15,774 |
Provisions for employee benefits | (22) | 596 |  | 681 |
Deferred tax liabilities | (23) | 4,805 |  | 5,581 |
Income tax payables | (10) | 40 |  | 40 |
Other non-current liabilities | (11) (24) | 3,390 | 462 | 4,449 | 520
|  | 47,987 |  | 53,269 |
Liabilities directly associated with assets held for sale | (25) | 2,026 |  | 195 |
TOTAL LIABILITIES |  | 84,282 |  | 91,291 |
Share capital |  | 4,005 |  | 4,005 |
Retained earnings |  | 33,209 |  | 32,552 |
Cumulative currency translation differences |  | 1,936 |  | 8,081 |
Other reserves and equity instruments |  | 8,964 |  | 8,406 |
Treasury shares |  | (2,782) |  | (2,883) |
Profit |  | 2,608 |  | 2,624 |
Equity attributable to equity holders of Eni |  | 47,940 |  | 52,785 |
Non-controlling interest |  | 4,847 |  | 2,863 |
TOTAL EQUITY | (26) | 52,787 |  | 55,648 |
TOTAL LIABILITIES AND EQUITY |  | 137,069 |  | 146,939 |

See the accompanying notes.

Information about the definitive purchase price allocation of business combinations made in 2024 is provided in note 27 ‐ Other Information.

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Table of Contents

CONSOLIDATED PROFIT AND LOSS ACCOUNT

(€ million except as otherwise stated)

|  | 2025 | 2024 | 2023
| Note | Total amount | of which with related parties | Total amount | of which with related parties | Total amount | of which with related parties
Sales from operations |  | 82,151 | 2,973 | 88,797 | 2,997 | 93,717 | 4,322
Other income and revenues |  | 1,478 | 285 | 2,417 | 279 | 1,099 | 156
REVENUES AND OTHER INCOME | (29) | 83,629 |  | 91,214 |  | 94,816 |
Purchases, services and other | (30) | (67,056) | (17,769) | (71,114) | (17,404) | (73,836) | (15,885)
Net (impairments) reversals of trade and other receivables | (8) | (11) | (1) | (168) | (2) | (249) | 5
Payroll and related costs | (30) | (3,229) | 17 | (3,262) | 3 | (3,136) | (8)
Other operating income (expense) | (24) | 641 | (264) | (352) | 201 | 478 | 17
Depreciation and amortization | (12) (13) (14) | (7,349) |  | (7,600) |  | (7,479) |
Net (impairments) reversals of tangible, intangible and right-of-use assets | (15) | (1,582) |  | (2,900) |  | (1,802) |
Write-off of tangible and intangible assets | (12) (13) (14) | (33) |  | (580) |  | (535) |
OPERATING PROFIT (LOSS) |  | 5,010 |  | 5,238 |  | 8,257 |
Finance income | (31) | 7,196 | 215 | 7,715 | 198 | 7,417 | 155
Finance expense | (31) | (8,170) | (77) | (8,980) | (57) | (8,113) | (28)
Net finance income (expense) from financial assets at fair value through profit or loss | (31) | 235 |  | 388 |  | 284 |
Derivative financial instruments | (24) (31) | (80) |  | 278 |  | (61) | 1
FINANCE INCOME (EXPENSE) |  | (819) |  | (599) |  | (473) |
Share of profit (loss) from equity-accounted investments |  | 1,161 |  | 866 |  | 1,336 |
Other gain (loss) from investments |  | 426 | (18) | 984 | (12) | 1,108 | 445
INCOME (EXPENSE) FROM INVESTMENTS | (16) (32) | 1,587 |  | 1,850 |  | 2,444 |
PROFIT BEFORE INCOME TAXES |  | 5,778 |  | 6,489 |  | 10,228 |
Income taxes | (33) | (3,020) |  | (3,725) |  | (5,368) |
PROFIT |  | 2,758 |  | 2,764 |  | 4,860 |
Attributable to Eni |  | 2,608 |  | 2,624 |  | 4,771 |
Attributable to non-controlling interest | (26) | 150 |  | 140 |  | 89 |
Earnings per share (€ per share) | (34) |  |  |  |  |  |
Basic |  | 0.78 |  | 0.79 |  | 1.41 |
Diluted |  | 0.78 |  | 0.78 |  | 1.40 |

See the accompanying notes.

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Table of Contents

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(€ million)

| Note | 2025 | 2024 | 2023
Profit |  | 2,758 | 2,764 | 4,860
Other items of comprehensive income (loss) |  |  |  |
Items that are not reclassified to profit or loss in later periods: |  |  |  |
Remeasurements of defined benefit plans | (26) | (9) | 8 | (31)
Share of other comprehensive income (loss) on equity-accounted investments | (26) |  | 1 | (2)
Change of minor investments measured at fair value with effects to OCI | (26) | (30) | 62 | 45
Tax effect | (26) | 2 | (4) | 10
|  | (37) | 67 | 22
Items that may be reclassified to profit or loss in later periods |  |  |  |
Currency translation differences | (26) | (6,410) | 3,066 | (2,010)
Change in the fair value of cash flow hedging derivatives | (26) | 865 | (912) | 541
Share of other comprehensive income (loss) on equity-accounted investments | (26) | 65 | (69) | 54
Tax effect | (26) | (258) | 263 | (158)
|  | (5,738) | 2,348 | (1,573)
Total other items of comprehensive income (loss) |  | (5,775) | 2,415 | (1,551)
Total comprehensive income |  | (3,017) | 5,179 | 3,309
Attributable to Eni |  | (2,874) | 4,962 | 3,220
Attributable to non-controlling interest |  | (143) | 217 | 89

See the accompanying notes.

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CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(€ million)

|  | Equity attributable to equity holders of Eni |  |
| Note | Share capital | Retained earnings | Cumulative currency translation differences | Other reserves and equity instruments | Treasury shares | Profit (loss) for the year | Total | Non-controlling interest | Total equity
Balance at December 31, 2024 | (26) | 4,005 | 32,552 | 8,081 | 8,406 | (2,883) | 2,624 | 52,785 | 2,863 | 55,648
Profit for the year |  |  |  |  |  |  | 2,608 | 2,608 | 150 | 2,758
Other items of comprehensive income (loss) |  |  |  |  |  |  |  |  |  |
Remeasurements of defined benefit plans net of tax effect | (26) |  |  |  | (9) |  |  | (9) | 2 | (7)
Change of minor investments measured at fair value with effects to OCI | (26) |  |  |  | (32) |  |  | (32) | 2 | (30)
Items that are not reclassified to profit or loss in later periods |  |  |  |  | (41) |  |  | (41) | 4 | (37)
Currency translation differences | (26) |  |  | (6,144) |  |  |  | (6,144) | (266) | (6,410)
Change in the fair value of cash flow hedge derivatives net of tax effect | (26) |  |  |  | 630 |  |  | 630 | (23) | 607
Share of “Other comprehensive income (loss)” on equity-accounted investments | (26) |  |  |  | 73 |  |  | 73 | (8) | 65
Items that may be reclassified to profit or loss in later periods |  |  |  | (6,144) | 703 |  |  | (5,441) | (297) | (5,738)
Total comprehensive income (loss) of the year |  |  |  | (6,144) | 662 |  | 2,608 | (2,874) | (143) | (3,017)
Dividend distribution of Eni SpA | (26) |  | (3,081) |  |  |  |  | (3,081) |  | (3,081)
Dividend distribution of other companies |  |  |  |  |  |  |  |  | (275) | (275)
Allocation of 2024 profit |  |  | 2,624 |  |  |  | (2,624) |  |  |
Capital contribution by non-controlling interests |  |  |  |  |  |  |  |  | 709 | 709
Purchase of treasury shares | (26) |  | (1,881) |  | 1,881 | (1,881) |  | (1,881) |  | (1,881)
Cancellation of treasury shares | (26) |  |  |  | (1,908) | 1,908 |  |  |  |
Long-term share-based incentive plan | (26) (30) |  | 35 |  | (74) | 74 |  | 35 |  | 35
Issuing of perpetual subordinated bonds | (26) |  |  |  | 1,500 |  |  | 1,500 |  | 1,500
Repurchase of perpetual subordinated bonds | (26) |  |  |  | (1,500) |  |  | (1,500) |  | (1,500)
Coupon payment on perpetual subordinated bonds | (26) |  | (310) |  |  |  |  | (310) |  | (310)
Change in non‐controlling interest | (26) |  | 3,417 | (35) | (5) |  |  | 3,377 | 1,695 | 5,072
Transactions with holders of equity instruments |  |  | 804 | (35) | (106) | 101 | (2,624) | (1,860) | 2,129 | 269
Other changes |  |  | (147) | 34 | 2 |  |  | (111) | (2) | (113)
Other changes in equity |  |  | (147) | 34 | 2 |  |  | (111) | (2) | (113)
Balance at December 31, 2025 | (26) | 4,005 | 33,209 | 1,936 | 8,964 | (2,782) | 2,608 | 47,940 | 4,847 | 52,787

See the accompanying notes.

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CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

continued

(€ million)

|  | Equity attributable to equity holders of Eni |  |
| Note | Share capital | Retained earnings | Cumulative currency translation differences | Other reserves and equity instruments | Treasury shares | Profit for the year | Total | Non-controlling interest | Total equity
Balance at December 31, 2023 |  | 4,005 | 32,988 | 5,238 | 8,515 | (2,333) | 4,771 | 53,184 | 460 | 53,644
Profit for the year |  |  |  |  |  |  | 2,624 | 2,624 | 140 | 2,764
Other items of comprehensive income |  |  |  |  |  |  |  |  |  |
Remeasurements of defined benefit plans net of tax effect | (26) |  |  |  | 4 |  |  | 4 |  | 4
Share of “Other comprehensive income” on equity-accounted investments | (26) |  |  |  | 1 |  |  | 1 |  | 1
Change of minor investments measured at fair value with effects to OCI | (26) |  |  |  | 62 |  |  | 62 |  | 62
Items that are not reclassified to profit or loss in later periods |  |  |  |  | 67 |  |  | 67 |  | 67
Currency translation differences | (26) |  |  | 2,992 | (2) |  |  | 2,990 | 76 | 3,066
Change in the fair value of cash flow hedge derivatives net of tax effect | (26) |  |  |  | (648) |  |  | (648) | (1) | (649)
Share of “Other comprehensive income” on equity-accounted investments | (26) |  |  |  | (71) |  |  | (71) | 2 | (69)
Items that may be reclassified to profit or loss in later periods |  |  |  | 2,992 | (721) |  |  | 2,271 | 77 | 2,348
Total comprehensive income for the year |  |  |  | 2,992 | (654) |  | 2,624 | 4,962 | 217 | 5,179
Dividend distribution of Eni SpA | (26) |  | (3,067) |  |  |  |  | (3,067) |  | (3,067)
Dividend distribution of other companies |  |  |  |  |  |  |  |  | (50) | (50)
Allocation of 2023 profit |  |  | 4,771 |  |  |  | (4,771) |  |  |
Capital contribution by non-controlling interests |  |  |  |  |  |  |  |  | 1 | 1
Purchase of treasury shares | (26) |  | (2,003) |  | 2,003 | (2,003) |  | (2,003) |  | (2,003)
Cancellation of treasury shares | (26) |  |  |  | (1,375) | 1,375 |  |  |  |
Long-term share-based incentive plan | (26) (30) |  | 24 |  | (78) | 78 |  | 24 |  | 24
Issuing of perpetual subordinated bonds | (26) |  |  |  |  |  |  |  | 1,848 | 1,848
Coupon payment on perpetual subordinated bonds | (26) |  | (138) |  |  |  |  | (138) |  | (138)
Change in non‐controlling interest | (26) |  | 196 |  |  |  |  | 196 | 392 | 588
Transactions with holders of equity instruments |  |  | (217) |  | 550 | (550) | (4,771) | (4,988) | 2,191 | (2,797)
Other changes |  |  | (219) | (149) | (5) |  |  | (373) | (5) | (378)
Other changes in equity |  |  | (219) | (149) | (5) |  |  | (373) | (5) | (378)
Balance at December 31, 2024 | (26) | 4,005 | 32,552 | 8,081 | 8,406 | (2,883) | 2,624 | 52,785 | 2,863 | 55,648

See the accompanying notes.

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CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

continued

(€ million)

|  | Equity attributable to equity holders of Eni |  |
|  | Share capital | Retained earnings | Cumulative currency translation differences | Other reserves and equity instruments | Treasury shares | Profit for the year | Total | Non-controlling interest | Total equity
Balance at December 31, 2022 |  | 4,005 | 23,455 | 7,564 | 8,785 | (2,937) | 13,887 | 54,759 | 471 | 55,230
Profit for the year |  |  |  |  |  |  | 4,771 | 4,771 | 89 | 4,860
Other items of comprehensive income |  |  |  |  |  |  |  |  |  |
Remeasurements of defined benefit plans net of tax effect |  |  |  |  | (21) |  |  | (21) |  | (21)
Share of “Other comprehensive income” on equity-accounted investments |  |  |  |  | (2) |  |  | (2) |  | (2)
Change of minor investments measured at fair value with effects to OCI |  |  |  |  | 45 |  |  | 45 |  | 45
Items that are not reclassified to profit or loss in later periods |  |  |  |  | 22 |  |  | 22 |  | 22
Currency translation differences |  |  |  | (2,001) | (9) |  |  | (2,010) |  | (2,010)
Change in the fair value of cash flow hedge derivatives net of tax effect |  |  |  |  | 383 |  |  | 383 |  | 383
Share of “Other comprehensive income (loss)” on equity-accounted investments |  |  |  |  | 54 |  |  | 54 |  | 54
Items that may be reclassified to profit or loss in later periods |  |  |  | (2,001) | 428 |  |  | (1,573) |  | (1,573)
Total comprehensive income for the year |  |  |  | (2,001) | 450 |  | 4,771 | 3,220 | 89 | 3,309
Dividend distribution of Eni SpA |  |  | (3,005) |  |  |  |  | (3,005) |  | (3,005)
Dividend distribution of other companies |  |  |  |  |  |  |  |  | (36) | (36)
Allocation of 2022 profit |  |  | 13,887 |  |  |  | (13,887) |  |  |
Reimbursement to non-controlling interests |  |  |  |  |  |  |  |  | (16) | (16)
Purchase of treasury shares |  |  | (1,837) |  | 1,837 | (1,837) |  | (1,837) |  | (1,837)
Cancellation of treasury shares |  |  |  |  | (2,400) | 2,400 |  |  |  |
Long-term share-based incentive plan |  |  | 20 |  | (41) | 41 |  | 20 |  | 20
Coupon payment on perpetual subordinated bonds |  |  | (138) |  |  |  |  | (138) |  | (138)
Change in non‐controlling interest |  |  | 47 |  |  |  |  | 47 | (47) |
Transactions with holders of equity instruments |  |  | 8,974 |  | (604) | 604 | (13,887) | (4,913) | (99) | (5,012)
Issuing effect of convertible bonds |  |  |  |  | 79 |  |  | 79 |  | 79
Other changes |  |  | 559 | (325) | (195) |  |  | 39 | (1) | 38
Other changes in equity |  |  | 559 | (325) | (116) |  |  | 118 | (1) | 117
Balance at December 31, 2023 |  | 4,005 | 32,988 | 5,238 | 8,515 | (2,333) | 4,771 | 53,184 | 460 | 53,644

See the accompanying notes.

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CONSOLIDATED STATEMENT OF CASH FLOWS

(€ million)

| Note | 2025 | 2024 | 2023
Profit |  | 2,758 | 2,764 | 4,860
Adjustments to reconcile profit (loss) to net cash provided by operating activities: |  |  |  |
Depreciation and amortization | (12) (13) (14) | 7,349 | 7,600 | 7,479
Net impairments (reversals) of tangible, intangible and right-of-use assets | (15) | 1,582 | 2,900 | 1,802
Write-off of tangible and intangible assets | (12) (13) (14) | 33 | 580 | 535
Share of (profit) loss of equity-accounted investments | (16) (32) | (1,161) | (866) | (1,336)
Net gain on disposal of assets |  | (99) | (601) | (441)
Dividend income | (32) | (242) | (227) | (255)
Interest income |  | (444) | (497) | (517)
Interest expense |  | 1,256 | 1,245 | 1,000
Income taxes | (33) | 3,020 | 3,725 | 5,368
Other changes |  | (515) | (158) | (700)
Cash flow from changes in working capital |  | 2,735 | 1,286 | 1,811
- inventories |  | 916 | 68 | 1,792
- trade receivables |  | 3,214 | 1,145 | 3,322
- trade payables |  | (835) | 110 | (4,823)
- provisions |  | (554) | (87) | 97
- other assets and liabilities |  | (6) | 50 | 1,423
Change in the provisions for employee benefits |  | (79) | (105) | 1
Dividends received |  | 1,785 | 1,946 | 2,255
Interest received |  | 358 | 456 | 459
Interest paid |  | (1,269) | (1,130) | (919)
Income taxes paid, net of tax receivables received |  | (3,737) | (5,826) | (6,283)
Net cash provided by operating activities |  | 13,330 | 13,092 | 15,119
- of which with related parties | (36) | (11,375) | (11,508) | (7,011)
Cash flow from investing activities |  | (9,999) | (11,782) | (12,404)
- tangible assets | (12) | (8,702) | (7,999) | (8,739)
- prepaid right-of-use assets | (13) |  | (5) |
- intangible assets | (14) | (527) | (486) | (476)
- consolidated subsidiaries and businesses net of cash and cash equivalents acquired | (5) (27) | (196) | (1,795) | (1,277)
- investments | (16) | (682) | (798) | (1,315)
- securities and financing receivables held for operating purposes |  | (89) | (185) | (388)
- change in payables in relation to investing activities |  | 197 | (514) | (209)
Cash flow from disposals |  | 2,040 | 2,496 | 845
- tangible assets |  | 1,414 | 1,354 | 122
- intangible assets |  | 4 | 21 | 32
- consolidated subsidiaries and businesses net of cash and cash equivalents disposed of | (5) (27) | 118 | 887 | 395
- investments |  | 135 | 526 | 47
- securities and financing receivables held for operating purposes |  | 98 | 69 | 32
- change in receivables in relation to disposals |  | 271 | (361) | 217
Net change in securities and financing receivables held for non-operating purposes |  | (1,339) | (531) | 2,194
Net cash used in investing activities |  | (9,298) | (9,817) | (9,365)
- of which with related parties | (36) | (3,181) | (3,140) | (1,695)

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| Note | 2025 | 2024 | 2023
Increase in long-term financial debt | (19) | 1,884 | 3,516 | 4,971
Repayments of long-term financial debt | (19) | (4,163) | (4,748) | (3,161)
Payments of lease liabilities | (13) | (1,250) | (1,205) | (963)
Increase (decrease) in short-term financial debt | (19) | (276) | (61) | (1,495)
Dividends paid to Eni's shareholders |  | (3,080) | (3,068) | (3,046)
Dividends paid to non-controlling interest |  | (277) | (45) | (36)
Capital contribution (reimbursement) by non-controlling interests |  | 709 | 589 | (16)
Sale (purchase) of additional interests in consolidated subsidiaries |  | 5,072 |  | (60)
Other contributions |  | 9 | 14 |
Purchase of treasury shares | (26) | (1,896) | (2,012) | (1,803)
Effect of issuance of convertible bonds | (26) |  |  | 79
Net issuance (repayment) of perpetual subordinated bonds | (26) | (18) | 1,778 |
Coupon payment on perpetual subordinated bonds | (26) | (310) | (138) | (138)
Net cash used in financing activities |  | (3,596) | (5,380) | (5,668)
- of which with related parties | (36) | (407) | (20) | (162)
Effect of exchange rate changes and other changes on cash and cash equivalents |  | (198) | 83 | (62)
Net increase (decrease) in cash and cash equivalents |  | 238 | (2,022) | 24
Cash and cash equivalents - beginning of the year | (6) | 8,183 | 10,205 | 10,181
Cash and cash equivalents - end of the year (a) | (6) | 8,421 | 8,183 | 10,205

(a) As of December 31, 2025, cash and cash equivalents included €321 million of cash and cash equivalents of consolidated subsidiaries held for sale that are reported in the item "Assets held for sale" (€12 million at December 31, 2023).

See the accompanying notes.

F-11

Table of Contents

Notes on Consolidated Financial Statements

1 Significant accounting policies, estimates and judgments

Basis of preparation

The Consolidated Financial Statements of Eni SpA and its subsidiaries (collectively referred to as Eni or the Group) have been prepared on a going concern-basis in accordance with International Financial Reporting Standards (IFRS)1 as issued by the International Accounting Standards Board (IASB).

The Consolidated Financial Statements have been prepared under the historical cost convention, taking into account, where appropriate, value adjustments, except for certain items that under IFRSs must be measured at fair value. The principles of consolidation and the significant accounting policies that follow have been consistently applied to all years presented, except where otherwise indicated.

The 2025 Consolidated Financial Statements included in the Annual Report on Form 20-F, were approved by the Eni’s Board of Directors on March 18, 2026.

The Consolidated Financial Statements are presented in euros and all values are rounded to the nearest million euros (€ million), except where otherwise indicated.

Significant accounting estimates and judgements

The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses recognized in the financial statements, as well as amounts included in the notes thereto, including disclosure of contingent assets and contingent liabilities. Estimates made are based on complex judgements and past experience of other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas activities, specifically in the determination of reserves, impairment of financial and non-financial assets, leases, decommissioning and restoration liabilities, environmental liabilities, business combinations, employee benefits, revenue from contracts with customers, fair value measurements and income taxes. Although the Company uses its best estimates and judgements, actual results could differ from the estimates and assumptions used. The accounting estimates and judgments relevant for the preparation of the Consolidated Financial Statement are illustrated in the description of the respective accounting policy.

Significant accounting estimates and judgments made in assessing the impacts of climate-related risks

Significant accounting estimates and judgments made by management for the preparation of the 2025 Consolidated Financial Statements are affected by the effects of actions to address climate change and by the potential impact of the energy transition. In particular, the global pressure towards a low-carbon economy, increasingly restrictive regulatory requirements for oil&gas activities and hydrocarbons consumption, carbon pricing schemes, the technological evolution of alternative energy sources for transportation, as well as changes in consumer preferences could imply a structural decline of the demand for hydrocarbons in the medium-long term, an increase in operating costs and a higher risk of stranded assets for Eni.

The Eni s decarbonization plan is composed of a series of actions and initiatives aimed to achieve carbon neutrality by 2050 through the Net Zero emissions for all Scope 1, 2 and 3 GHG emissions associated with Eni’s energy products. Scenarios adopted by management take into account policies, regulatory requirements and current and expected developments in technology and set out a development path of the future energy system, on the basis of an economic and demographic framework, analysis of existing and announced policies and technologies, identifying those which can reasonably reach maturity within the considered time horizon. Price variables reflect the best estimate by management of the fundamentals of several energy markets, which incorporates the ongoing and reasonably expected decarbonization trends, and are subject to continuous benchmarking with the views of market analysts and peers.

Such scenarios represent the basis for significant estimates and judgments relating to: (i) the assessment of the intention to continue exploration projects; (ii) the assessment of the recoverability of non-current assets and credit exposures towards National Oil Companies; (iii) the definition of useful lives and residual values of fixed assets; (iv) impacts on provisions (e.g. the anticipation of the expected timing of decommissioning and restoration costs).

Principles of consolidation

Subsidiaries

The Consolidated Financial Statements comprise the financial statements of the parent Company Eni SpA and those of its subsidiaries, being those entities over which the Company has control, either directly or indirectly, through exposure or rights to their variable returns and the ability to affect those returns through its power over the investees.

1 IFRSs include also International Accounting Standards (IAS), currently effective, as well as the interpretations developed by the IFRS Interpretations Committee, previously named International Financial Reporting Interpretations Committee (IFRIC) and initially Standing Interpretations Committee (SIC).

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Subsidiaries are fully recognized and included in the consolidated financial statement, on the basis of consistent accounting policies, from the date on which control is obtained until the date that control ceases, taking into account the appropriate eliminations of intragroup transactions (see the accounting policy for “Intragroup transactions”). Non-controlling interests are presented separately on the balance sheet within equity; the profit or loss and comprehensive income attributable to non-controlling interests are presented in specific line items, respectively, in the profit and loss account and in the statement of comprehensive income. Non-controlling interests also include subordinated perpetual bonds issued by subsidiaries for which the Group holds the unconditional right to defer repayment of principal and payment of coupons.

Taking into account the lack of any material 2 impact on the representation of the financial position and performance of the Group 3, the Consolidated Financial Statements do not consolidate: (i) some subsidiaries that are immaterial, both individually and in the aggregate, and (ii) subsidiaries acting as sole operator in the management of oil and gas contracts on behalf of companies participating in a joint project. In the latter case, the activities are financed proportionally based on a budget approved by the participating companies upon presentation of periodical reports of proceeds and expenses. Costs and revenue and other operating data (production, reserves, etc.) of the project, as well as the related obligations arising from the project, are recognized directly in the financial statements of the companies involved based on their own share.

When the proportion of the equity held by non-controlling interests changes, any difference between the consideration paid/received and the amount by which the related non-controlling interests are adjusted is attributed to Eni owners’ equity (within the line item “Retained earnings”). Moreover, in the event of the disposal of minority interests without loss of control, any put options on non-controlling interests, exercisable upon the occurrence of events not under the Group's control, result in the recognition of a liability, equal to the present value of the so-called redemption amount, as a balancing entry to Group equity.

The sale of equity interests with loss of control determines the recognition in the profit and loss account of: (i) any gain or loss calculated as the difference between the consideration received and the corresponding transferred net assets; (ii) any gain or loss recognized as a result of the remeasurement of any investment retained in the former subsidiary at its fair value; (iii) the estimate of fair value of any contingent consideration, to be settled in cash if specified future events occur or conditions are met; and (iv) any amount related to the former subsidiary previously recognized in other comprehensive income which may be reclassified subsequently to the profit and loss account 4. Any investment retained in the former subsidiary is recognized at its fair value at the date when control is lost and shall be accounted for in accordance with the applicable measurement criteria.

Interests in joint arrangements

Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.

A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. Investments in joint ventures are accounted for using the equity method as described in the accounting policy for “The equity method of accounting”.

A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have enforceable rights to the assets, and enforceable obligations for the liabilities, relating to the arrangement; in the Consolidated Financial Statements, Eni recognizes its share of the assets/liabilities and revenues/expenses of joint operations on the basis of its rights and obligations relating to the arrangements.

After the initial recognition, the assets/liabilities and revenues/expenses of the joint operations are measured in accordance with the applicable measurement criteria.

Immaterial joint operations structured through a separate vehicle are accounted for using the equity method or, if this does not result in a misrepresentation of the Company’s financial position and performance, at cost less any impairment losses.

Investments in associates

An associate is an entity over which Eni has significant influence, that is the power to participate in the financial and operating policy decisions of the investee but is not control or joint control of those policies. Investments in associates are accounted for using the equity method as described in the accounting policy for “The equity method of accounting”.

2 According to IFRSs, information is material if omitting, misstating or obscuring it could reasonably be expected to influence decisions that the primary users of general-purpose financial statements make on the basis of those financial statements.
3 Unconsolidated subsidiaries are accounted for as described in the accounting policy for “The equity method of accounting”.
4 Conversely, any amount related to the former subsidiary previously recognized in other comprehensive income, which may not be reclassified subsequently to the profit and loss account, are reclassified in another item of equity.

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The equity method of accounting 5

Under the equity method, investments are initially recognized at cost, allocating it to the investee’s identifiable assets/liabilities; any excess of the cost of the investment over the share of the net fair value of the investee’s identifiable assets and liabilities is accounted for as goodwill, not separately recognized but included in the carrying amount of the investment. If this allocation is provisionally recognized at initial recognition, it can be retrospectively adjusted within one year from the acquisition date, to reflect new information obtained about facts and circumstances that existed at the acquisition date. Subsequently, with the aim of reflecting the Group’s share of the investee’s net assets and the related changes, the carrying amount is adjusted to reflect: (i) the investor’s share of the profit or loss of the investee after the date of acquisition, adjusted to account for depreciation, amortization and any impairment losses of the equity-accounted entity’s assets based on their fair values at the date of acquisition; and (ii) the investor’s share of the investee’s other comprehensive income. Conversely, the carrying amount is not adjusted for changes in the equity of the investee arising, for instance, from the issue by the investee of perpetual subordinated bonds or convertible bonds not subscribed by the Group. Distributions received from an equity-accounted investee reduce the carrying amount of the investment; any excess amount is recognized in the profit and loss account. In applying the equity method, consolidation adjustments are considered (see also the accounting policy for “Subsidiaries”). Losses arising from the application of the equity method in excess of the carrying amount of the investment, recognized in the profit and loss account within “Income (Expense) from investments”, reduce the carrying amount, net of the related expected credit losses (see below), of any financing receivables towards the investee for which settlement is neither planned nor likely to occur in the foreseeable future (the so-called long-term interests), which are, in substance, an extension of the investment in the investee. The investor’s share of any losses of an equity-accounted investee that exceeds the carrying amount of the investment and any long-term interests (the so-called net investment), is recognized in a specific provision only to the extent that the investor has incurred legal or constructive obligations or made payments on behalf of the investee.

Whenever there is objective evidence of impairment (e.g. relevant breaches of contracts, significant financial difficulty, probable default of the counterparty, etc.), the carrying amount of the net investment, resulting from the application of the abovementioned measurement criteria, is tested for impairment considering the related recoverable amount, determined by adopting the criteria indicated in the accounting policy for “Impairment of non-financial assets”. When an impairment loss no longer exists or has decreased, any reversal of the impairment loss is recognized in the profit and loss account within “Income (Expense) from investments”. The impairment reversal of the net investment shall not exceed the previously recognized impairment losses.

The sale of equity interests with loss of joint control or significant influence over the investee determines the recognition in the profit and loss account of: (i) any gain or loss calculated as the difference between the consideration received and the corresponding transferred share; (ii) any gain or loss recognized as a result of the remeasurement of any investment retained in the former joint venture/associate at its fair value 6; and (iii) any amount related to the former joint venture/associate previously recognized in other comprehensive income which may be reclassified subsequently to the profit and loss account 7. Any investment retained in the former joint venture/associate is recognized at its fair value at the date when joint control or significant influence is lost and shall be accounted for in accordance with the applicable measurement criteria.

Business combinations

Business combinations are accounted for by applying the acquisition method. The consideration transferred in a business combination is the sum of the acquisition-date fair value of the assets transferred, the liabilities incurred and the equity interests issued by the acquirer. The consideration transferred also includes the fair value of any assets or liabilities resulting from contingent considerations, contractually agreed and dependent upon the occurrence of specified future events.

The acquirer shall measure the identifiable assets acquired and liabilities assumed at their acquisition-date fair values 8, unless another measurement basis is required by IFRSs. The excess of the consideration transferred over the Group’s share of the acquisition-date fair values of the identifiable assets acquired and liabilities assumed is recognized, on the balance sheet, as goodwill.

Any non-controlling interests are measured as the proportionate share in the recognized amounts of the acquiree’s identifiable net assets at the acquisition date excluding the portion of goodwill attributable to them (partial goodwill method). In a business combination achieved in stages, the purchase price is determined by summing the acquisition-date fair value of previously held equity interests in the acquiree and the consideration transferred for obtaining control; the previously held equity interests are remeasured at their acquisition-date fair value and the resulting gain or loss, if any, is recognized in the profit and loss account. Furthermore, on obtaining control, any amount recognized in other comprehensive income related to the previously held equity interests is reclassified to the profit and loss account, or in another item of equity when such amount may not be reclassified to the profit and loss account.

If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the provisional amounts recognized at the acquisition date shall be retrospectively adjusted within one year from the acquisition date, to reflect new information obtained about facts and circumstances that existed as of the acquisition date.

5 Joint ventures, associates and immaterial unconsolidated subsidiaries are accounted for at cost less any impairment losses, if this does not result in a misrepresentation of the Company's financial position and performance.

6 If the retained investment continues to be classified either as a joint venture or an associate and so accounted for using the equity method, no remeasurement at fair value is recognized in the profit and loss account.

7 Conversely, any amount related to the former joint venture/associate previously recognized in other comprehensive income, which may not be reclassified subsequently to the profit and loss account, are reclassified in another item of equity.

8 Fair value measurement principles are described in the accounting policy for “Fair value measurements”.

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Significant accounting estimates and judgments: investments and business combinations

The assessment of the existence of control, joint control, significant influence over an investee, as well as for joint operations, the assessment of the existence of enforceable rights to the investee’s assets and enforceable obligations for the investee’s liabilities imply that management makes complex judgments on the basis of the characteristics of the investee’s structure, arrangements between parties and other relevant facts and circumstances. Significant accounting estimates by management are required also for measuring the identifiable assets acquired and the liabilities assumed in a business combination at their acquisition-date fair values. For such measurement, to be performed also for the application of the equity method, Eni adopts the valuation techniques generally used by market participants taking into account the available information; for the most significant acquisitions, Eni engages external independent evaluators.

Intragroup transactions

All balances and transactions between consolidated companies, and not yet realized with third parties, including unrealized profits arising from such transactions have been eliminated 9.

Unrealized profits arising from transactions between the Group and its equity-accounted entities are eliminated to the extent of the Group’s interest in the equity-accounted entity; such accounting treatment is applied also for transfer of businesses to equity-accounted entities (so-called downstream transactions). In both cases, the unrealized losses are not eliminated as the transaction provides evidence of an impairment loss of the asset transferred.

Foreign currency translation

The financial statements of foreign operations having a functional currency other than the euro, that represents the parent’s functional currency as well as the presentation currency of the Consolidated Financial Statements, are translated into euros using the spot exchange rates on the balance sheet date for assets and liabilities, historical exchange rates for equity and average exchange rates for the profit and loss account and the statement of cash flows.

The cumulative resulting exchange differences are presented in the separate component of Eni owners’ equity “Cumulative currency translation differences”10. Cumulative amount of exchange differences relating to a foreign operation are reclassified to the profit and loss account when the entity disposes the entire interest in that foreign operation or when the partial disposal involves the loss of control, joint control or significant influence over the foreign operation. On a partial disposal that does not involve loss of control of a subsidiary that includes a foreign operation, the proportionate share of the cumulative exchange differences is reattributed to the non-controlling interests in that foreign operation. On a partial disposal of interests in joint arrangements or in associates that does not involve loss of joint control or significant influence, the proportionate share of the cumulative exchange differences is reclassified to the profit and loss account. The repayment of share capital made by a subsidiary having a functional currency other than the euro, without a change in the ownership interest, implies that the proportionate share of the cumulative amount of exchange differences relating to the subsidiary is reclassified to the profit and loss account.

Exchange differences arising from intragroup credit/debit, the repayment or payment of which is neither planned nor probable in the foreseeable future, are recognized in the statement of comprehensive income (loss).

The financial statements of foreign operations which are translated into euros are denominated in the foreign operations’ functional currencies which generally is the U.S. dollar.

Exchange gains and losses arising on intra-group foreign currency borrowings, for which settlement is neither planned nor likely to occur in the foreseeable future, are reported in other comprehensive income.

The main foreign exchange rates used to translate the financial statements into the parent’s functional currency are indicated below:

(currency amount for 1 €) | Annual average exchange rate 2025 | Exchange rate at December 31, 2025 | Annual average exchange rate 2024 | Exchange rate at December 31, 2024 | Annual average exchange rate 2023 | Exchange rate at December 31, 2023
U.S. Dollar | 1.13 | 1.18 | 1.08 | 1.04 | 1.08 | 1.11
Pound Sterling | 0.86 | 0.87 | 0.85 | 0.83 | 0.87 | 0.87
Australian Dollar | 1.75 | 1.76 | 1.64 | 1.68 | 1.63 | 1.63

Material accounting policies

The material accounting policies used in the preparation of the Consolidated Financial Statements are described below.

Oil and natural gas exploration, appraisal, development and production activities

Oil and natural gas exploration, appraisal and development activities are accounted for using the principles of the successful efforts method of accounting as described below.

9 Exchange differences associated with intragroup monetary assets and liabilities are not eliminated.

10 When the foreign subsidiary is partially owned, the cumulative exchange difference, that is attributable to the non-controlling interests, is allocated to and recognized as part of “Non-controlling interest”.

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Acquisition of exploration rights and mineral interest

Costs incurred for the acquisition of exploration rights (or their extension) are initially capitalized within the line item “Intangible assets” as “exploration rights — unproved” pending determination of whether the exploration and appraisal activities in the reference areas are successful or not. Unproved exploration rights are not amortized, but reviewed to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review is based on the confirmation of the commitment of the Company to continue the exploration activities and on the analysis of facts and circumstances that indicate the absence of uncertainties related to the recoverability of the carrying amount. If no future activity is planned, the carrying amount of the related exploration rights is recognized in the profit and loss account as write-off. Lower value exploration rights are pooled and amortized on a straight-line basis over the estimated period of exploration. In the event of a discovery of proved reserves (i.e. upon recognition of proved reserves and internal approval for development), the carrying amount of the related unproved exploration rights is reclassified to “proved exploration rights”, within the line item “Intangible assets”. Upon reclassification, as well as whether there is any indication of impairment, the carrying amount of exploration rights to reclassify as proved is tested for impairment considering the higher of their value in use and their fair value less costs of disposal.

Costs incurred for the acquisition of mineral interests are capitalized in connection with the assets acquired (such as exploration potential, possible and probable reserves and proved reserves). When the acquisition is related to a set of exploration potential and reserves, the cost is allocated to the different assets acquired based on their expected discounted cash flows.

Expenditure associated with possible and probable reserves (unproved mineral interests) is not amortized until classified as proved reserves; in case of a negative result of the subsequent appraisal activities, it is written off.

From the commencement of production, proved exploration rights are amortized according to the unit of production method (the so-called UOP method, described in the accounting policy for “UOP depreciation, depletion and amortization”).

Exploration and appraisal expenditure

Geological and geophysical exploration costs are recognized as an expense as incurred.

Costs directly associated with an exploration well are initially recognized within tangible assets in progress, as “exploration and appraisal costs — unproved” (exploration wells in progress) until the drilling of the well is completed and can continue to be capitalized in the following 12-month (or a longer period of time according to the complexity of the project and to the associated investment level) period pending the evaluation of drilling results (suspended exploration wells). If, at the end of this period, it is ascertained that the result is negative (no hydrocarbon found) or that the discovery is not sufficiently significant to justify the development, the wells are declared dry/unsuccessful and the related costs are written-off. Conversely, these costs continue to be capitalized only if and until: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well, and (ii) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. Analogous recognition criteria are adopted for the costs related to the appraisal activity. When proved reserves of oil and/or natural gas are determined, the relevant expenditure recognized as unproved is reclassified to proved exploration and appraisal costs within tangible assets in progress. Upon reclassification, or when there is any indication of impairment, the carrying amount of the costs to reclassify as proved is tested for impairment considering the higher of their value in use and their fair value less costs of disposal. From the commencement of production, proved exploration and appraisal costs are depreciated according to the UOP method (see the accounting policy for “UOP depreciation, depletion and amortization”).

Development and production costs

Development costs, including the costs related to unsuccessful and damaged development wells, are capitalized as “Tangible asset in progress — proved”. These costs are amortized, from the commencement of production, generally on a UOP basis. When development projects are unfeasible/not carried on, the related costs are written off when it is decided to abandon the project. Development costs are tested for impairment in accordance with the criteria described in the accounting policy for “Property, plant and equipment”.

Production costs are those costs incurred to operate and maintain wells and field equipment and are recognized as an expense as incurred.

UOP depreciation, depletion and amortization 11

Depreciation of investments relating to mineral activities is generally calculated using the UOP method 12, determined on the basis of the different types of hydrocarbon reserves in order to ensure adequate representation of the methods used to obtain the economic benefits associated with the use of the assets being depreciated. In particular: i) exploration rights and mineral titles acquired related to ‘proved’ reserves are amortised considering total proved reserves; ii) capitalised exploration, appraisal and development costs related to production facilities are amortised considering proved developed reserves; iii) facilities, based on their size, are depreciated considering total proved reserves and also probable developed reserves that are reasonably recoverable from existing production facilities and mineral rights; iv) for owned floating facilities (FLNG, FPSO), depreciation is calculated using the UOP method, or straight-line method, considering the duration of the concessions and the recovery of proved and probable reserves. In the event of significant changes in market prices that result in estimates of reserves and related depreciation rates that are not aligned with the methods used to obtain the expected future economic benefits from these assets, the reserves used to determine the UOP depreciation rate are estimated on the basis of reasonable economic parameters consistent with the production forecasts defined by management, in order to better reflect the expected methods of obtaining future economic benefits from these assets.

11 In relation to the consolidation of the upstream investment model based on proximity exploration and development and phased development, which extends the useful life of facilities, and in relation to the increasing use of vessels with economic lives linked to the exploitation of probable reserves, starting from the second half of 2025, the methods for determining the UOP depreciation rates of upstream facilities have been updated to also consider, where appropriate, probable reserves whose recovery does not require significant additional investments. The update, as a change in estimate, has only prospective effects.

12 Rate obtained from the ratio between the volumes extracted during the quarter and the reserves existing at the end of the quarter, increased by the volumes extracted during the quarter itself.

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Production Sharing Agreements and service contracts

Oil and gas reserves related to Production Sharing Agreements are determined on the basis of contractual terms related to the recovery of the contractor’s costs to undertake and finance exploration, development and production activities at its own risk (Cost Oil) and the Company’s stipulated share of the production remaining after such cost recovery (Profit Oil). Revenues from the sale of the lifted production, against both Cost Oil and Profit Oil, are accounted for on an accrual basis, whilst exploration, development and production costs are accounted for according to the above-mentioned accounting policies. A similar scheme applies to the service contracts where the Group is entitled to a share of the production as consideration for the rendered service.

The Company’s share of production volumes and reserves includes the share of hydrocarbons that 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 revenue, and a tax expense.

Plugging and abandonment of wells

Costs expected to be incurred with respect to the plugging and abandonment of a well, dismantlement and removal of production facilities, as well as site restoration, are capitalized, consistent with the accounting policy described under “Property, plant and equipment”, and then depreciated on a UOP basis.

Significant accounting estimates and judgments: oil and natural gas activities

Engineering estimates of the oil and gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering and geological criteria that must be met before estimated oil and gas reserves can be categorized as “proved”, the estimate of the reserves depends on a number of factors, assumptions and variables, including: (i) the quality of available geological and technical engineering data and their interpretation and judgment; (ii) projections regarding future rates of production and operating costs and development costs; (iii) changes in the prevailing tax rules, other government regulations and contractual conditions; (iv) results of drilling, testing and the actual production performance of the Company’s reservoirs after the date of the initial estimates which may drive substantial upward or downward revisions during the current period; and (v) changes in oil and natural gas commodity prices which could affect expected future cash flows and the quantities of the Company’s proved reserves since the estimates of reserves are based on prices existing as of the date when these estimates are made.

Lower oil prices or the projections of higher operating and development costs may impair the ability of the Company to economically produce reserves leading to downward reserve revisions.

Many of the factors, assumptions and variables involved in estimating proved reserves are subject to change over time and therefore affect the estimates of oil and natural gas reserves. Similar uncertainties concern unproved reserves.

The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is made within a year after well completion. The evaluation process of a discovery, which requires performing additional appraisal activities on the potential oil and natural gas field and establishing the optimum development plans, can take longer, in most cases, depending on the complexity of the project and on the size of capital expenditures required. During this period, the costs related to these exploration wells remain suspended on the balance sheet. In any case, all such capitalized costs are reviewed, at least, on an annual basis to confirm the continued intent to develop, or otherwise to extract value from the discovery.

Field reserves will be categorized as proved only when all the criteria for attribution of proved status have been met. Proved reserves can be classified as developed or undeveloped. Volumes are classified into proved developed reserves as a consequence of development activity. Generally, reserves are booked as proved developed at the start of production. Major development projects typically take one to four years from the time of initial booking to the start of production.

Estimated reserves are used both in determining depreciation, amortization and depletion charges (see the accounting policy for “UOP depreciation, depletion and amortization”) and for the definition of future cash flows of oil and natural gas assets within the impairment test.

Property, plant and equipment

Property, plant and equipment are recognized using the cost model and initially stated at their purchase price or construction cost including any costs directly attributable to bringing the asset to the location and condition necessary for it to be capable of operating in the manner intended by management.

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For assets that necessarily take a substantial period of time to get ready for their intended use, the purchase price or construction cost comprises the borrowing costs incurred in the period to get the asset ready for use that would have been avoided if the expenditure had not been made.

In the case of a present obligation for dismantling and removal of assets and restoration of sites, the initial carrying amount of an item of property, plant and equipment includes the estimated (discounted) costs to be incurred when the removal event occurs; a corresponding amount is recognized as part of a specific provision (see the accounting policy for “Decommissioning and restoration liabilities”). Analogous approach is adopted for present obligations to realize social projects in oil and gas development areas.

Property, plant and equipment are not revalued for financial reporting purposes.

Property, plant and equipment are depreciated on a systematic basis over their useful life. The useful life is the period over which an asset is expected to be available for use by the Company.

When tangible assets are composed of more than one significant part with different useful lives, each part is depreciated separately. The depreciable amount is the asset’s carrying amount less its residual value at the end of its useful life if it is significant and can be reasonably determined. Changes in the asset's useful life, in its residual value or in the pattern of consumption of the future economic benefits embodied in the asset, are accounted for prospectively.

Expenditures on upgrading, revamping and reconversion are recognized as items of property, plant and equipment when it is probable that they will increase the expected future economic benefits of the asset. Assets acquired for safety or environmental reasons, although not directly increasing the future economic benefits of any particular existing item of property, plant and equipment, qualify for recognition as assets when they are necessary for running the business.

Replacement costs of identifiable parts in complex assets are capitalized and depreciated over their useful life; the residual carrying amount of the part that has been substituted is charged to the profit and loss account. Non-removable leasehold improvements are depreciated over the earlier of the useful life of the improvements and the lease term. Expenditures for ordinary maintenance and repairs, other than replacements of identifiable components, which reintegrate, and do not increase the performance of the assets, are recognized as an expense as incurred.

The carrying amount of property, plant and equipment is derecognized on disposal or when no future economic benefits are expected from its use or disposal; the arising gain or loss is recognized in the profit and loss account.

Leases 13

A contract is, or contains, a lease, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration; such right exists whether, throughout the period of use, the customer has both the right to obtain substantially all of the economic benefits from use of the identified asset and the right to direct the use of the identified asset.

At the date on which the underlying asset is available for use (i.e. commencement date of the lease), a lessee recognizes an asset for its right to use the underlying leased asset (hereinafter also referred as right-of-use asset) and a liability for its obligation to make lease payments during the lease term (hereinafter also referred as lease liability).14 The lease term is the non-cancellable period of a contract, together with, if reasonably certain, periods covered by extension options or by the non-exercise of termination options.

In particular, the lease liability is initially recognized at the present value of the following lease payments 15 that are not paid at the commencement date: (i) fixed payments, less any lease incentives receivable; (ii) variable lease payments that on an index or a rate 16; (iii) amounts expected to be payable by the lessee under residual value guarantees; (iv) the exercise price of a purchase option if the lessee is reasonably certain to exercise that option; and (v) payments of penalties for terminating the lease, if the lease term reflects the lessee exercising an option to terminate the lease. The lease payments are discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the lessee’s incremental borrowing rate. The latter is determined considering the term of the lease, the frequency and currency of the contractual lease payments, as well as the features of the lessee’s economic environment (reflected in the country risk premium assigned to each country where Eni operates).

After the initial recognition, the lease liability is measured on an amortized cost basis and is remeasured, normally, as an adjustment to the carrying amount of the related right-of-use asset, to reflect changes to the lease payments due, essentially, to: (i) modifications in the lease contract not accounted as a separate lease; (ii) changes in indexes or rates (used to determine the variable lease payments); or (iii) changes in the assessment of the exercise of the contractual options.

13 This accounting policy does not apply to leases to explore for and extract resources such as those for oil and gas rights, leases of land and any rights of way related to oil and gas activities.

14 Eni applies the recognition exemptions allowed for short-term leases (for certain classes of underlying assets) and low-value leases, by recognizing the lease payments associated with those leases as an expense on a straight-line basis over the lease term.

15 Eni does not separate non-lease components from lease components except for main contracts related to upstream activities (drilling rigs), which provide for single payments relating to both lease and non-lease components.

16 Conversely, the other kinds of variable lease payments (payments that depend on the use of an underlying leased asset) are not included in the carrying amount of the lease liability but are recognized in the profit and loss account as operating expenses over the lease term.

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The right-of-use asset is initially measured as the sum of: (i) the amount of the initial measurement of the lease liability; (ii) any initial direct costs incurred by the lessee; (iii) any lease payments made at or before the commencement date, less any lease incentives received; and (iv) an estimate of costs to be incurred by the lessee in dismantling and removing the underlying asset, restoring the site on which it is located or restoring the underlying asset to the condition required by the terms and conditions of the lease. After the initial recognition, the right-of-use asset is adjusted also for any accumulated depreciation 17, any accumulated impairment losses (see the accounting policy for “Impairment of non-financial assets”).

The depreciation charges of the right-of-use asset and the interest expenses on the lease liability directly attributable to the construction of an asset are capitalized as part of the cost of such asset.

In the oil and gas activities, the operator of an unincorporated joint operation which enters into a lease contract as the sole signatory recognizes on the balance sheet: (i) the entire lease liability if, based on the contractual provisions and any other relevant facts and circumstances, it has primary responsibility for the liability towards the third-party supplier; and (ii) the entire right-of-use asset, unless, on the basis of the terms and conditions of the contract, there is a sublease with the followers.

The followers’ share of the right-of-use asset, recognized by the operator, will be recovered according to the joint operation’s contractual arrangements by billing the project costs attributable to the followers and collecting the related cash calls. Costs recovered from the followers are recognized as “Other income and revenues” in the profit and loss account and as net cash provided by operating activities in the statement of cash flows.

Differently, if a lease contract is signed by all the partners, Eni recognizes its share of the right-of-use asset and lease liability on the balance sheet based on its working interest.

If Eni does not have primary responsibility for the lease liability and, on the basis of the terms and conditions of the contract, there is not a sublease, it does not recognize any right-of-use asset and lease liability related to the lease contract.

When lease contracts are entered into by companies other than subsidiaries that act as operators on behalf of the other participating companies (the so-called operating companies), consistent with the provision to recover from the followers the costs related to the oil and gas activities, the participating companies recognize their share of the right-of-use assets and the lease liabilities based on their working interest, defined according to the expected use, to the extent that it is reliably determinable, of the underlying assets.

Significant accounting estimates and judgments: lease transactions

With reference to lease contracts, management makes significant estimates and judgments related to: (i) determining the lease term, considering all facts and circumstances that generate an economic incentive, or not, to exercise any extension and/or termination options; (ii) determining the lessee’s incremental borrowing rate; (iii) identifying and, where appropriate, separating non-lease components from lease components, where an observable stand-alone price is not readily available, taking into account also the analysis performed with external experts; (iv) recognizing lease contracts, for which the underlying assets are used in oil and gas activities (mainly drilling rigs and FPSOs), entered into as operator within an unincorporated joint operation, considering if the operator has primary responsibility for the liability towards the third-party supplier and the relationships with the followers; (v) identifying the variable lease payments and the related characteristics in order to include them in the measurement of the lease liability.

Intangible assets

Intangible assets are identifiable non-monetary assets without physical substance, controlled by the Company and able to produce future economic benefits, and goodwill. An asset is classified as intangible when management is able to distinguish it clearly from goodwill.

Intangible assets are initially recognized at cost as determined by the criteria described in the accounting policy for “Property, plant and equipment” and they are never revalued for financial reporting purposes.

Intangible assets with finite useful lives are amortized on a systematic basis over their useful life; the amortization is carried out in accordance with the criteria described in the accounting policy for “Property, plant and equipment”.

Goodwill and intangible assets with indefinite useful lives are not amortized. For the recoverability of the carrying amounts of goodwill and other intangible assets see the accounting policy for “Impairment of non-financial assets”.

Costs of obtaining a contract with a customer are recognized on the balance sheet if the Company expects to recover those costs. The carrying value of the intangible asset arising from those costs is amortized on a systematic basis, that is consistent with the transfer to the customer of the goods or services to which the asset relates, and is tested for impairment.

Costs of technological development activities, including development costs related to CCS Projects (Carbon, Capture and Storage) incurred before the construction of the physical infrastructure, are capitalized when: (i) the cost attributable to the development activity can be measured reliably; (ii) there is the intention and the availability of financial and technical resources to make the asset available for use or sale; and (iii) it can be demonstrated that the asset is able to generate probable future economic benefits.

The carrying amount of intangible assets is derecognized on disposal or when no future economic benefits are expected from its use or disposal; any arising gain or loss is recognized in the profit and loss account.

17 Depreciation charges are recognized on a systematic basis from the commencement date to the end of the useful life of the right-of-use. Nevertheless, if the lease transfers ownership of the underlying asset to the lessee at the lease term, or if the lessee is reasonably certain that he will exercise a purchase option , the right-of-use asset is depreciated from the commencement date to the end of the useful life of the underlying asset.

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Impairment of non-financial assets

Non-financial assets (tangible assets, intangible assets and right-of-use assets) are tested for impairment whenever events or changes in circumstances indicate that the carrying amounts for those assets may not be recoverable.

The recoverability assessment is performed for each cash-generating unit (hereinafter also CGU) represented by the smallest identifiable group of assets that generate cash inflows that are largely independent of the cash inflows from other assets or group of assets.

CGUs may include corporate assets which do not generate cash inflows independently of other assets or group of assets but which contribute to the future cash flows of more CGUs; the portions of corporate assets are allocated to a specific CGU or, if not possible, to a group of CGUs on a reasonable and consistent basis. Right-of-use assets, which generally do not generate cash inflows independently of other assets or groups of assets, are allocated to the CGU to which they belong; the right-of-use assets which cannot be fully attributed to a CGU are considered as corporate assets. The recoverability of the carrying amount of common facilities within the E&P operating segment is assessed by considering the set of recoverable amounts of the CGUs benefiting from the common facility. Goodwill is tested for impairment at least annually, and whenever there is any indication of impairment, at the lowest level within the entity at which it is monitored for internal management purposes.

The recoverability of a CGU is assessed by comparing its carrying amount with the recoverable amount, which is the higher of the CGU’s fair value less costs of disposal and its value in use. Value in use is the present value of the future cash flows expected to be derived from continuing use of the CGU and, if significant and reliably measurable, the cash flows expected to be obtained from its disposal at the end of its useful life, after deducting the costs of disposal.

The value in use of CGUs which include material right-of-use assets is calculated, normally, by ignoring lease payments included in the measurement of the lease liabilities.

For impairment test purposes, cash outflows expected to be incurred to guarantee compliance with laws and regulations regarding CO 2 emissions (e.g. Emission Trading Scheme) or on a voluntary basis (e.g. cash outflows related to forestry certificates acquired or produced consistent with the Company’s decarbonization strategy – hereinafter also forestry) are taken into account.

In particular, in estimating value in use, the cash outflows for forestry projects are included, consistent with the targets of the decarbonization strategy, within the expected operating cash outflows; in this regard, considering that the forestry projects can be developed in countries where Eni does not carry out operating activities and given the difficulty to allocate such cash outflows, on a reasonable and consistent basis, to CGUs of the relevant operating segment, the related discounted cash outflows are treated as a reduction of the headroom of the E&P operating segment.

For the determination of value in use, the estimated future cash flows are discounted using a rate that reflects a current market assessment of the time value of money and of the risks specific to the asset that are not reflected in the estimated future cash flows. In particular, the discount rate used is the Weighted Average Cost of Capital (WACC) adjusted for the specific country risk of the CGU. These adjustments are measured considering information from external parties. WACC differs considering the risk associated with each operating segment/business where the asset operates. In particular, for the assets belonging to the segment and businesses different from E&P and REVT (Refining Evolution and Transformation), the related riskiness is determined on the basis of a sample of comparable companies. For the E&P operating segment and REVT business, the riskiness is determined, on a residual basis, as the difference between the risk of Eni as a whole and the risk of other operating segments/business. Value in use is calculated net of the tax effect as this method results in values similar to those resulting from discounting pre-tax cash flows at a pre-tax discount rate derived, through an iteration process, from a post-tax valuation.

When the carrying amount of the CGU, including goodwill allocated thereto, determined taking into account any impairment loss of the non-current assets belonging to the CGU, exceeds its recoverable amount, the excess is recognized as an impairment loss. The impairment loss is allocated first to reduce the carrying amount of goodwill; any remaining excess is allocated to the other assets of the unit pro-rata on the basis of the carrying amount of each asset in the CGU, up to the related recoverable amount.

When an impairment loss no longer exists or has decreased, a reversal of the impairment loss is recognized in the profit and loss account. The impairment reversal shall not exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. An impairment loss recognized for goodwill is not reversed in a subsequent period.

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Grants related to assets

Government grants related to assets are recognized by deducting them in calculating the carrying amount of the related assets when there is reasonable assurance that the Company will comply with the conditions attaching to them and the grants will be received.

Inventories

Inventories, including compulsory stock, are measured at the lower of purchase or production cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business less the estimated costs of completion and the estimated costs necessary to make the sale, or, with reference to inventories of crude oil and petroleum products already included in binding sale contracts, the contractual selling price. Inventories which are principally acquired with the purpose of selling in the near future and generating a profit from fluctuations in price are measured at fair value less costs to sell and any subsequent changes in fair value are recognized in the profit and loss account. Materials and other supplies held for use in production are not written down below cost if the finished products in which they will be incorporated are expected to be sold at or above cost.

The cost of inventories of hydrocarbons (crude oil, condensates and natural gas) and petroleum products is determined by applying the weighted average cost method on a three-month basis, or on a different time period (e.g. monthly), when it is justified by the use and the turnover of inventories of crude oil and petroleum products; the cost of inventories of the Chemical business is determined by applying the weighted average cost on an annual basis.

When take-or-pay clauses are included in long-term gas purchase contracts, pre-paid gas volumes that are not withdrawn to fulfill minimum annual take obligations are measured using the pricing formulas contractually defined. They are recognized within “Other assets” as “Deferred costs”, as a contra to “Trade and other payables” or, after settlement, to “Cash and cash equivalents”. The allocated deferred costs are charged to the profit and loss account: (i) when natural gas is actually withdrawn, the related cost is included in the determination of the weighted average cost of inventories; and (ii) for the portion which is not recoverable, when it is not possible to withdraw the previously pre-paid gas within the contractually defined deadlines. Furthermore, the allocated deferred costs are tested for economic recoverability by comparing the related carrying amount and their net realizable value.

Significant accounting estimates and judgments: impairment of non-financial assets

The assessment of the recoverability of non-financial assets depends on management estimates on highly uncertain and complex matters such as future commodity prices, future discount rates, future development costs and production costs, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for global or regional market supply-and-demand conditions also with reference to the decarbonization process and the effects of changes in regulatory requirements. Judgement by management is required also in the definition of CGUs and the identification of their appropriate grouping for the purpose of testing for impairment the carrying amount of goodwill, corporate assets as well as common facilities within the E&P operating segment. In particular, CGUs are identified considering, inter alia, how management monitors the entity’s operations (such as by business lines) or how management makes decisions about continuing or disposing of the entity’s assets and operations.

Similar remarks are valid for assessing the physical recoverability of assets recognized on the balance sheet (deferred costs — see also the accounting policy for “Inventories”) related to natural gas volumes not withdrawn under long-term supply contracts with take-or-pay clauses.

The definition of the expected future cash flows used for impairment analyses is based on judgmental assessments of future production volumes, prices and costs, considering available information at the date of review. With reference to commodity prices, management assumes the price scenario adopted for economic-financial projections and for the evaluation of investments over their entire life, this scenario is approved by the Board of Directors (see point ‘Significant accounting estimates and judgments made in assessing the impacts of climate-related risks’). Moreover, the estimate of expected future cash flows, taking into consideration the current and the expected decarbonization trends, is performed taking into account: (i) the evolution of the future energy system, (ii) the fundamentals of the various energy markets, as well as (iii) the constant benchmarking with the views of market analysts and other specialized institutions.

For oil and natural gas properties, the expected future cash flows are estimated based on proved and probable reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. In limited cases (e.g. for mineral interests acquired from third parties as part of a business combination) the expected cash flows may take into account also the risk-adjusted possible reserves, if they are considered to determine the consideration transferred.

The estimate of the future rates of production is based on assumptions related to future commodity prices, operating costs, lifting and development costs, field decline rates and other factors.

More details on the main assumptions underlying the determination of the recoverable amount of non-financial assets are set out in note 15 – Impairments of tangible and intangible assets and right-of-use assets. Sensitivity of outcomes to decarbonization scenarios.

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Financial instruments

Financial assets

Financial assets held by the Group are classified, on the basis of both contractual cash flow characteristics and the entity’s business model for managing them, in the following categories: (i) financial assets measured at amortized cost; and (ii) financial assets measured at fair value through profit or loss (hereinafter also FVTPL).

At initial recognition, a financial asset is measured at its fair value plus, in the case of a financial asset not at FVTPL, transaction costs that are directly attributable; at initial recognition, trade receivables that do not have a significant financing component are measured at their transaction price.

After initial recognition, financial assets whose contractual terms give rise to cash flows that are solely payments of principal and interest on the principal amount outstanding are measured at amortized cost if they are held within a business model whose objective is to hold financial assets in order to collect contractual cash flows (the so-called hold to collect business model). For financial assets measured at amortized cost, interest income determined using the effective interest rate, foreign exchange differences and any impairment losses (see the accounting policy for “Impairment of financial assets”) are recognized in the profit and loss account.

Financial assets represented by debt instruments that are not measured at amortized cost, are measured at FVTPL; financial assets held for trading, as well as the portfolios of financial assets managed and evaluated on a fair value basis, fall into this category. Interest income on such financial assets contributes to the related fair value measurement and is recognized in “Finance income (expense)”, within “Net finance income (expense) from financial assets at fair value through profit or loss”.

When the purchase or sale of a financial asset is under a contract whose terms require delivery of the asset within the time frame established generally by regulation or convention in the marketplace concerned, the transaction is accounted for on the settlement date.

Cash and cash equivalents

Cash and cash equivalents include cash on hand, demand deposits, as well as financial assets originally due, generally, up to three months, readily convertible to known amount of cash and subject to an insignificant risk of changes in value.

Impairment of financial assets

The expected credit loss model is adopted for the impairment of financial assets that are debt instruments but are not measured at FVTPL.18

In particular, the expected credit losses are generally measured by multiplying: (i) the exposure to the counterparty’s credit risk net of any collateral held and other credit enhancements (Exposure At Default, EAD); (ii) the probability that the default of the counterparty occurs (Probability of Default, PD); and (iii) the percentage estimate of the exposure that will not be recovered in case of default (Loss Given Default, LGD), considering the past experiences and the range of recovery tools that can be activated (e.g. extrajudicial and/or legal proceedings, etc.).

With reference to trade and other receivables, Probabilities of Default of counterparties are determined by adopting the internal credit ratings already used for credit worthiness and are periodically reviewed using, inter alia, back-testing analyses; for government entities (e.g. National Oil Companies), the Probability of Default, represented essentially by the probability of a delayed payment, is determined by using, as input data, the country risk premium adopted to determine WACC for the impairment review of non-financial assets.

For customers without internal credit ratings, the expected credit losses are measured by using a provision matrix, defined by grouping, where appropriate, receivables into adequate clusters to which apply expected loss rates defined on the basis of their historical credit loss experiences, adjusted, where appropriate, to take into account forward-looking information on credit risk of the counterparty or clusters of counterparties.

18 The expected credit loss model is also adopted: (i) for issued financial guarantee contracts not measured at FVTPL; as well as (ii) for issued performance guarantees contracts. Expected credit losses recognized on issued guarantees are not material.

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Considering the characteristics of the reference markets, financial assets with more than 180 days past due or, in any case, with counterparties undergoing litigation, restructuring or renegotiation, are considered to be in default. Counterparties are considered undergoing litigation when judicial/legal proceedings aimed to recover a receivable have been activated or are going to be activated. Impairment losses of trade and other receivables are recognized in the profit and loss account, net of any impairment reversal, within the line item of the profit and loss account “Net (impairments) reversals of trade and other receivables”.

The financing receivables, granted to associates and joint ventures, for which settlement is neither planned nor likely to occur in the foreseeable future and which in substance form part of the entity’s net investment in these investees, are tested for impairment, first, on the basis of the expected credit loss model and, then, together with the carrying amount of the investment in the associate/joint venture, in accordance with the criteria indicated in the accounting policy for “The equity method of accounting”. In applying the expected credit loss model, any adjustments to the carrying amount of long-term interest that arise from applying the accounting policy for “The equity method of accounting” are not taken into account.

Significant accounting estimates and judgments: impairment of financial assets

Measuring impairment losses of financial assets requires management evaluation of complex and highly uncertain elements such as, for example, Probabilities of Default of counterparties, the assessment of any collateral or other credit enhancements, the expected exposure that will not be recovered in case of default, as well as the definition of customers’ clusters to be adopted.

Further details on the main assumptions underlying the measurement of expected credit losses of financial assets are provided in note 8 – Trade and other receivables.

Investments in equity instruments

Investments in equity instruments that are not held for trading are measured at fair value through other comprehensive income, without subsequent transfer of fair value changes to profit or loss on derecognition of these investments; conversely, dividends from these investments are recognized in the profit and loss account.

Financial liabilities

At initial recognition, financial liabilities, other than derivative financial instruments, are measured at their fair value, minus transaction costs that are directly attributable, and are subsequently measured at amortized cost.

The sustainability-linked bonds, i.e. financial liabilities featuring a potential increase in the related interest rate to reflect the borrower’s performance relative to certain sustainability targets (the so-called ESG metrics), are measured at amortized cost.

Generally, changes in the interest rate result in an update of the effective interest rate to be used for the recognition of interest expense.

The issue of a convertible bond into ordinary shares of the issuer (without substantial cash settlement option) determines the separate recognition of the components of the instrument represented by the debt component, measured at amortized cost, and by the conversion option, recognized in equity. Any eventually transaction costs are allocated proportionally between the financial liability and the equity instrument.

Significant judgments: financial liabilities

The Group’s companies can negotiate supplier finance arrangements (supply chain finance, payable finance, reverse factoring and similar agreements) with suppliers, to obtain extended payment terms, without the necessary and automatic involvement of a financial institution. In such cases, management judges whether or not payables towards suppliers have to be re-classified as financial liabilities from trade/investing activity payables. In order to make such judgment, management considers if the payment terms differ from the ones that are customary in the industry, any additional security is provided as part of the arrangement as well as any other facts and circumstances. The classification of a debt as financial determines: (i) upon reclassification/initial recognition of the liability, a non-monetary change with no impacts on the statement of cash flows; (ii) upon the settlement of the liability, the classification of the payment within net cash used in financing activities.

With reference to sustainability-linked bonds, management assesses whether the non-compliance with an ESG metric could adversely impact operations and, therefore, revenue generation and creditworthiness of the Company.

Derivative financial instruments and hedge accounting

Derivative financial instruments are assets and liabilities recognized and measured at their fair value.

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With reference to the defined risk management objectives and strategy, the qualifying criteria for hedge accounting requires: (i) the existence of an economic relationship between the hedged item and the hedging instrument in order to offset the related value changes and the effects of counterparty credit risk do not dominate the economic relationship between the hedged item and the hedging instrument; and (ii) the definition of the relationship between the quantity of the hedged item and the quantity of the hedging instrument (the so-called hedge ratio) consistent with the entity’s risk management objectives, under a defined risk management strategy; the hedge ratio is adjusted, where appropriate, after taking into account any adequate rebalancing. A hedging relationship is discontinued prospectively, in its entirety or a part of it, when it no longer meets the risk management objectives on the basis of which it qualified for hedge accounting, it ceases to meet the other qualifying criteria or after rebalancing it.

When derivatives hedge the risk of changes in the fair value of the hedged items (fair value hedge, e.g. hedging of the variability in the fair value of fixed interest rate assets/liabilities), the derivatives are measured at fair value through profit or loss. Consistently, the carrying amount of the hedged item is adjusted to reflect, in the profit and loss account, the changes in fair value of the hedged item attributable to the hedged risk; this applies even if the hedged item should be otherwise measured.

When derivatives hedge the exposure to variability in cash flows of the hedged items (cash flow hedge, e.g. hedging the variability in the cash flows of assets/liabilities as a result of the fluctuations of exchange rate), the effective changes in the fair value of the derivatives are initially recognized in the equity reserve related to other comprehensive income and then reclassified to the profit and loss account in the same period during which the hedged transaction affects the profit and loss account.

If a hedged forecast transaction subsequently results in the recognition of a non-financial asset or a non-financial liability, the accumulated changes in fair value of hedging derivatives, recognized in equity, are included directly in the carrying amount of the hedged non-financial asset/liability (commonly referred to as a “basis adjustment”).

The changes in the fair value of non-hedging derivatives on interest rates and exchange rates are recognized in the profit and loss account line item “Finance income (expense)”; conversely, the changes in the fair value of non-hedging derivatives on commodities are recognized in the profit and loss account line item “Other operating (expense) income”.

Derivatives embedded in financial assets are not accounted for separately; in such circumstances, the entire hybrid instrument is classified depending on the contractual cash flow characteristics of the financial instrument and the business model for managing it (see the accounting policy for “Financial assets”). Conversely, derivatives embedded in financial liabilities measured at amortized cost and/or non-financial assets are separated if the economic characteristics and risks of the embedded derivative are not closely related to the economic characteristics and risks of the host contract.

Eni assesses the existence of embedded derivatives to be separated when it becomes party to the contract and, afterwards, when a change in the terms of the contract that modifies its cash flows occurs.

Contracts to buy or sell commodities entered into and continued to be held for the purpose of their receipt or delivery in accordance with the Group’s expected purchase, sale or usage requirements are recognized on an accrual basis (the so-called own use exemption).

Offsetting of financial assets and liabilities

Financial assets and liabilities are set off if the Group currently has a legally enforceable right to set off and intends to settle on a net basis (or to realize the asset and settle the liability simultaneously).

Derecognition of financial assets and liabilities

Transferred financial assets are derecognized when the contractual rights to receive the cash flows from the financial assets expire or are transferred to another party. Financial liabilities are derecognized when they are extinguished, or when the obligation specified in the contract is discharged, cancelled or expired.

Provisions and contingent liabilities

Provisions are recognized when: (i) there is a present obligation, legal or constructive, as a result of a past event; (ii) it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation; and (iii) the amount of the obligation can be reliably estimated.

The amount recognized as a provision is the best estimate of the expenditure required to settle the present obligation. The amount recognized for onerous contracts is the lower of the cost necessary to fulfill the obligations, net of expected economic benefits deriving from the contracts, and any compensation or penalties arising from failure to fulfill these obligations. Where the effect of the time value is material, and the payment date of the obligations can be reasonably estimated, provisions to be accrued are the present value of the expected cash outflows determined taking into account the time value of money and the risks associated with the obligation. The change in provisions due to the passage of time is recognized within “Finance income (expense)” in the profit and loss account.

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A provision for restructuring costs is recognized only when the Company has a detailed formal plan for the restructuring and has raised a valid expectation in the affected parties that it will carry out the restructuring.

Provisions are periodically reviewed and adjusted to reflect changes in the estimates of costs, timing and discount rates.

Contingent liabilities are: (i) possible obligations arising from past events, whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company; or (ii) present obligations arising from past events, whose amount cannot be reliably measured or whose settlement will probably not result in an outflow of resources embodying economic benefits. Contingent liabilities are not recognized in the financial statements but are disclosed.

Decommissioning and restoration liabilities

Liabilities for decommissioning and restoration costs are recognized, together with a corresponding amount as part of the related property, plant and equipment.

Such liabilities are reviewed regularly to take into account the changes in the expected costs to be incurred, contractual obligations, regulatory requirements and practices in force in the countries where the tangible assets are located.

The effects of any changes in the estimate of the liability are recognized generally as an adjustment to the carrying amount of the related property, plant and equipment; however, if the resulting decrease in the liability exceeds the carrying amount of the related asset, the excess is recognized in the profit and loss account.

Environmental liabilities

Environmental liabilities are recognized when the Group has an obligation, relating to environmental clean-up and remediation of soil and groundwater in areas owned or under concession where the Group performed in the past industrial operations that were progressively divested, shut down, dismantled or restructured. The liability is measured on the basis of the costs expected to be incurred in relation to the existing situation at the balance sheet date, considering virtually certain future developments in technology and legislation that are known.

Significant accounting estimates and judgments: decommissioning and restoration liabilities, environmental liabilities and other provisions

The Group holds provisions for dismantling and removing items of property, plant and equipment, and restoring land or seabed at the end of the oil and gas production activity. Estimating the amount and the timing of the obligations to dismantle, remove and restore items of property, plant and equipment is complex. It requires management to make estimates and judgments with respect to removal obligations that will come to term many years into the future and contracts and regulations are often unclear as to what constitutes removal. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known as asset removal technologies and costs constantly evolve in the countries where Eni operates, as do political, environmental, safety and public expectations.

Decommissioning and restoration provisions, recognized in the financial statements, include, essentially, the present value of the expected costs for decommissioning oil and natural gas facilities at the end of the economic lives of fields, well-plugging, abandonment and site restoration of the Exploration & Production operating segment.

Any decommissioning and restoration provisions associated with the other operating segments’ assets, given their indeterminate settlement dates, also considering the strategy to reconvert plants in order to produce low carbon products, are recognized when it is possible to make a reliable estimate of the discounted abandonment costs. In this regard, Eni performs periodic reviews for any changes in facts and circumstances that might require recognition of a decommissioning and restoration provision.

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Moreover, Eni is subject to numerous EU, national, regional and local environmental laws and regulations concerning its oil and gas operations, production and other activities. They include legislations that implement international conventions or protocols. With reference to groundwater treatment plants, the enhancement of the know-how gained on water contamination trends, as well as the positions of the competent authorities, allows the definition of a predictive model for estimating the time horizon within which the operations of those plants will be terminated and, therefore, for estimating the cost of managing and monitoring them.

The reliable determinability is verified on the basis of the available information such as, for example, the approval or filing of the environmental projects to the relevant administrative authorities or the making of a commitment to the relevant administrative authorities.

Management, considering the actions already taken, insurance policies obtained to cover environmental risks and provisions already recognized, does not expect any material adverse effect on Eni’s consolidated results of operations and financial position as a result of such laws and regulations. However, there can be no assurance that there will not be a material adverse impact on Eni’s consolidated results of operations and financial position due to: (i) the possibility of an unknown contamination; (ii) the results of the ongoing surveys and other possible effects of statements required by applicable laws; (iii) the possible effects of future environmental legislations and rules; (iv) the effects of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, against other potentially responsible parties with respect to such litigations and the possible reimbursements.

Moreover, considering the significant time period covered by the environmental liabilities, further uncertainties associated with the estimate are related to the definition of: (i) the time-frame required to reduce contaminants; (ii) the future costs to be incurred for remediation activities; (iii) the discount and inflation rates.

In addition to environmental and decommissioning and restoration liabilities, Eni recognizes provisions primarily related to legal and trade proceedings. These provisions are estimated on the basis of complex managerial judgments.

Employee benefits

Employee benefits are considerations given by the Group in exchange for service rendered by employees or for the termination of employment.

Post-employment benefit plans, including informal arrangements, are classified as either defined contribution plans or defined benefit plans depending on the economic substance of the plan as derived from its principal terms and conditions. Under defined contribution plans, the Company’s obligation, which consists in making payments to the State or to a trust or a fund, is determined on the basis of contributions due; as a consequence, the related cost is recognized in profit and loss in the competence period.

The liabilities related to defined benefit plans, net of any plan assets, are determined on the basis of actuarial assumptions and charged on an accrual basis during the employment period required to obtain the benefits.

Net interest includes the interest cost on liabilities and interest income on plan assets. Net interest is measured by applying to the liability, net of any plan assets, the discount rate used to calculate the present value of the liability; net interest of defined benefit plans is recognized in “Finance income (expense)”.

Remeasurements of the net defined benefit liability, comprising actuarial gains and losses, resulting from changes in the actuarial assumptions used or from changes arising from experience adjustments, and the return on plan assets excluding amounts included in net interest, are recognized within the statement of comprehensive income. Remeasurements of the net defined benefit liability, recognized within other comprehensive income, are not reclassified subsequently to the profit and loss account.

Obligations for long-term benefits are determined by adopting actuarial assumptions. The effects of remeasurements are taken to profit and loss account in their entirety.

The liabilities for termination benefits are recognized at the earlier of the following dates: (a) when the entity can no longer withdraw the offer of those benefits; and (b) when the entity recognizes costs for a restructuring that involves the payment of termination benefits. Such liabilities are measured in accordance with the nature of the employee benefit. In particular, if the termination benefits are an enhancement to post-employment benefits, the related liability is measured in accordance with the requirements for post-employment benefits. Otherwise, liabilities for termination benefits are determined applying the requirements: (i) for short-term employee benefits, if the termination benefits are expected to be settled wholly before twelve months after the end of the annual reporting period in which the termination benefits are recognized; or (ii) for long-term benefits if the termination benefits are not expected to be settled wholly before twelve months after the end of the annual reporting period.

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Share-based payments

The line item “Payroll and related costs” includes the cost of the share-based incentive plan, consistent with its actual remunerative nature (Long-term share-based incentive plans for the managers of Eni and Employee Stock Ownership Plan).

With reference to Long-term share-based incentive plans for the managers of Eni, the cost of the share-based incentive plan is measured by reference to the fair value of the equity instruments granted and the estimate of the number of shares that eventually vest; the cost is recognized on an accrual basis pro rata temporis over the vesting period, that is the period between the grant date and the settlement date. The fair value of the shares underlying the incentive plan is measured at the grant date, taking into account the estimate of achievement of market conditions (e.g. Total Shareholder Return), and is not adjusted in subsequent periods; when the achievement is linked also to non-market conditions, the number of shares expected to vest is adjusted during the vesting period to reflect the updated estimate of these conditions. If, at the end of the vesting period, the incentive plan does not vest because of failure to satisfy the performance conditions, the portion of cost related to market conditions is not reversed to the profit and loss account.

A similar accounting treatment is adopted with reference to the Employee Stock Ownership Plan, whose cost is determined on the basis of the fair value of shares at the grant date, it is allocated over the period of time (three years) required for the employee to acquire full ownership and availability of the shares granted.

Significant accounting estimates and judgments: employee benefits and share-based payments

Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions. The significant assumptions used to account for defined benefit plans are determined as follows: (i) discount and inflation rates are based on the market yields on high quality corporate bonds (or, in the absence of a deep market of these bonds, on the market yields on government bonds) and on the expected inflation rates in the reference currency area; (ii) the future salary levels of the individual employees are determined including an estimate of future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority and promotion; (iii) healthcare cost trend assumptions reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends, including healthcare inflation, changes in healthcare utilization, changes in health status of the participants and the contributions paid to health funds; and (iv) demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for individual employees involved.

The amount of the net defined benefit liability (asset), changes according to the remeasurements, comprising, among others, changes in the current actuarial assumptions, differences in the previous actuarial assumptions and what has actually occurred and differences in the return on plan assets, excluding amounts included in net interest, usually occur. Similar to the approach followed for the fair value measurement of financial instruments, the fair value of the shares underlying the incentive plans is measured by using complex valuation techniques and identifying, through structured judgments, the assumptions to be adopted.

Further details on the share-based incentives plans for managers are provided in note 30 – Costs.

Equity instruments

Treasury shares

Treasury shares, including shares held to meet the future requirements of the share-based incentive plans and the Employee Stock Ownership Plan, are recognized as deductions from equity at cost. Any gain or loss resulting from subsequent sales is recognized in equity.

Hybrid bonds

The perpetual subordinated hybrid bonds are classified in the financial statements as equity instruments considering that the issuer has the unconditional right to defer, until the date of its own liquidation, the repayment of the principal amount and the payment of accrued interest 19. Therefore, the issuer recognizes the cash received from the bondholders, net of costs incurred in issuing the hybrid bonds, as an increase in Eni owners’ equity or in non-controlling interests when these instruments are issued by subsidiaries (see point “Subsidiaries”); differently, the repayments of the principal amount and the payments of accrued interest (upon the arising of the related contractual payment obligation) are accounted for as a decrease in Eni owners’ equity.

Revenue from contracts with customers

Revenue from contracts with customers is recognized when the related performance obligation is satisfied, that is when a promised good or service is transferred to a customer. A promised good or service is transferred when (or as) the customer obtains control of it. Control can be transferred over time or at a point in time. With reference to the most important products sold by Eni, revenue is generally recognized for:

 crude oil, upon shipment;

 natural gas, LNG and electricity, upon delivery to the customer;

 petroleum products sold to retail distribution networks, upon delivery to the service stations, whereas all other sales of petroleum products are recognized upon shipment; and

 chemical products and other products, upon shipment.

19 The payment of accrued interest is required upon the occurrence of events under the issuer’s control such as, for example, a distribution of dividends to shareholders.

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Revenue from crude oil and natural gas production from properties in which Eni has an interest together with other producers is recognized on the basis of the quantities actually lifted and sold (sales method); costs are recognized on the basis of the quantities actually sold.

Revenue is measured at the consideration to which the Company expects to be entitled in exchange for transferring promised goods and/or services to a customer, excluding amounts collected on behalf of third parties.

If the consideration promised in a contract includes a variable amount, the Company estimates the amount of consideration to which it will be entitled in exchange for transferring the promised goods and/or services to a customer; in particular, the amount of consideration can vary because of discounts, refunds, incentives, price concessions, performance bonuses, penalties or if the price is contingent on the occurrence or non-occurrence of future events.

If, in a contract, the Company grants a customer the option to acquire additional goods or services for free or at a discount (e.g. sales incentives, customer award points, etc.), this option gives rise to a separate performance obligation in the contract only if the option provides a material right to the customer that it would not receive without entering into that contract.

When goods or services are exchanged for goods or services which are of a similar nature and value, the exchange is not regarded as a transaction which generates revenue.

Significant accounting estimates and judgments: revenue from contracts with customers

Revenue from sales of electricity and gas to retail customers includes the amount accrued for electricity and gas supplied between the date of the last invoiced meter reading (actual or estimated) of volumes consumed and the end of the year. These estimates consider information provided by the grid managers about the volumes allocated among the customers of the secondary distribution network, about the actual and estimated volumes consumed by customers, as well as internal estimates about volumes consumed by customers. Therefore, revenue is accrued as a result of a complex estimate based on the volumes distributed and allocated, communicated by third parties, likely to be adjusted, according to applicable regulations, within the fifth year following the one in which they are accrued, as well as on estimates about volumes consumed by customers. Considering the contractual obligations on the supply delivery points, revenue from sales of electricity and gas to retail customers includes costs for transportation and dispatching and in these cases the gross amount of consideration to which the Company is entitled is recognized.

Costs associated with emission quotas

Costs associated with emission quotas, incurred to meet the compliance requirements (e.g. Emission Trading Scheme) and determined on the basis of market prices, spot or forward, are recognized in relation to the amounts of the carbon dioxide emissions that exceed free allowances. Costs related to the purchase of the emission rights that exceed the amount necessary to meet regulatory obligations are recognized as intangible assets. Revenue related to emission quotas is recognized when they are sold. Emission rights held for trading are recognized within inventories. The costs incurred on a voluntary basis for the acquisition or production of forestry certificates, also taking into account the absence of an active market, are recognized in the profit and loss account when incurred.

Exchange differences

Revenues and costs associated with transactions in foreign currencies are translated into the functional currency by applying the exchange rate at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated into the functional currency at the spot exchange rate on the balance sheet date and any resulting exchange differences are included in the profit and loss account within “Finance income (expense)” or, if designated as hedging instruments for the foreign currency risk, in the same line item in which the economic effects of the hedged item are recognized. Non-monetary assets and liabilities denominated in foreign currencies, measured at cost, are not retranslated subsequent to initial recognition. Non-monetary items measured at fair value, recoverable amount or net realizable value are retranslated using the exchange rate at the date when the value is determined.

Dividends

Dividends are recognized when the right to receive payment of the dividend is established.

Dividends and interim dividends to owners are shown as changes in equity when the dividends are declared by, respectively, the shareholders’ meeting and the Board of Directors.

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Income taxes

Current income taxes are determined on the basis of estimated taxable profit. Current income tax assets and liabilities are measured at the amount expected to be paid to (recovered from) the taxation authorities, using the tax rates and tax laws that have been enacted or substantively enacted by the end of the reporting period.

Deferred tax assets and liabilities are recognized for temporary differences arising between the carrying amounts of the assets and liabilities and their tax bases, based on tax rates and tax laws that are expected to apply to the period when the asset is realized or the liability is settled, based on tax rates and tax laws that have been enacted or substantively enacted by the end of the reporting period. Deferred tax assets are recognized when their recoverability is considered probable, i.e. when it is probable that sufficient taxable profit will be available in the same year as the reversal of the deductible temporary difference. Similarly, deferred tax assets for the carry-forward of unused tax credits and unused tax losses are recognized to the extent that their recoverability is probable. The carrying amount of the deferred tax assets is reviewed, at least, on an annual basis.

Relating to the taxable temporary differences associated with investments in subsidiaries and associates, and interests in joint arrangements, the related deferred tax liabilities are not recognized if the investor is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future.

If there is uncertainty over income tax treatments, if the company: (i) concludes it is probable that the taxation authority will accept an uncertain tax treatment, it determines the (current and/or deferred) income taxes to be recognized in the financial statements consistent with the tax treatment used or planned to be used in its income tax filings; (ii) concludes it is not probable that the taxation authority will accept an uncertain tax treatment, the company reflects the effect of uncertainty in determining the (current and/or deferred) income taxes to be recognized in the financial statements.

Deferred tax assets and liabilities are offset at a single entity level if related to off-settable taxes. The balance of the offset, if positive, is recognized in the line item “Deferred tax assets” and, if negative, in the line item “Deferred tax liabilities”.

When the results of transactions are recognized in other comprehensive income or directly in equity, the related current and deferred taxes are also recognized in other comprehensive income or directly in equity.

Significant accounting estimates and judgments: income taxes

The computation of income taxes involves the interpretation of applicable tax laws and regulations in many jurisdictions throughout the world. Although Eni aims to maintain a relationship with the taxation authorities characterized by transparency, dialogue and cooperation (e.g. by not using aggressive tax planning and by using, if available, procedures intended to eliminate or reduce tax litigations), there can be no assurance that there will not be a tax litigation with the taxation authorities where the legislation could be open to more than one interpretation. The resolution of tax disputes, through negotiations with relevant taxation authorities or through litigation, could take several years to complete. The estimate of liabilities related to uncertain tax treatments requires complex judgments by management. After the initial recognition, these liabilities are periodically reviewed for any changes in facts and circumstances.

Moreover, management makes complex judgments regarding mainly the assessment of the recoverability of deferred tax assets, related both to deductible temporary differences and unused tax losses, which requires estimates and evaluations about the amount and the timing of future taxable profits.

Assets held for sale

Non-current assets and current and non-current assets included within disposal groups are classified as held for sale if their carrying amounts will be recovered principally through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or the disposal group is available for immediate sale in its present condition.

Immediately before the initial classification of a non-current asset and/or a disposal group as held for sale, the non-current asset and/or the assets and liabilities in the disposal group are measured in accordance with applicable IFRSs. Subsequently, non-current assets held for sale are not depreciated or amortized and they are measured at the lower of the fair value less costs to sell and their carrying amount.

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Any difference between the carrying amount of the non-current assets and the fair value less costs to sell is taken to the profit and loss account as an impairment loss; any subsequent reversal is recognized up to the cumulative impairment losses, including those recognized prior to qualification of the asset as held for sale.

If events or circumstances occur that no longer allow to classify a non-current asset or a disposal group as held for sale, the non-current asset or the disposal group is reclassified into the original line items of the balance sheet and measured at the lower of: (i) its carrying amount at the date of classification as held for sale adjusted for any depreciation, amortization, impairment losses and reversals that would have been recognized had the asset or disposal group not been classified as held for sale, and (ii) its recoverable amount at the date of the subsequent decision not to sell.

Fair value measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

Assets and liabilities measured at fair value are categorized into the fair value hierarchy which is defined on the basis of the significance of the inputs used to measure fair value. In particular, on the basis of the features of the inputs used in the measurement, the fair value hierarchy provides for the following levels:

a) Level 1: quoted prices (unadjusted) in active markets for identical assets or liabilities;

b) Level 2: measurement based on inputs, other than quoted prices included within the previous point, that are observable for the asset or liability under measurement, either directly or indirectly;

c) Level 3: unobservable inputs for the asset or liability.

Significant accounting estimates and judgments: fair value

Fair value measurement, although based on the best available information and on the use of appropriate valuation techniques, is inherently uncertain, requires the use of professional judgment and could result in expected values other than the actual ones.

2 Primary financial statements

The primary financial statements are the same of the ones used in the previous reporting period.

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3 Changes in accounting policies

The amendments to IFRSs, effective from January 1, 2025, did not have a material impact on the Consolidated Financial Statements.

4 IFRSs not yet effective

On April 9, 2024, the IASB issued IFRS 18 “Presentation and Disclosure in Financial Statements,” which replaces IAS 1. In order to increase comparability and transparency of information, IFRS 18: (i) requires the profit and loss account to be divided into five sections (operating, investing, financing, income taxes and discontinued operation) and the mandatory presentation of operating profit or loss and profit or loss before financing and income tax; ; (ii) with reference to statement of cash flows: (a) generally requires the presentation of interests and dividends paid as cash flows from financing activities; (b) provides, in general terms, for the presentation of interests and dividends received as cash flows from investing activities; (c) identifies the operating profit or loss as the starting point when presenting cash flows from operating activities under the indirect method; (iii) requires the disclosure of the management performance measures and their reconciliation with the most directly comparable subtotals required by IFRS; and (iv) strengthens the guidance on the aggregation and disaggregation of information presented in the primary financial statements and in the notes. IFRS 18 shall be applied for annual reporting periods beginning on or after January 1, 2027. During 2025, analyses were initiated to identify the areas affected by the new provisions and the related impacts.

On May 30, 2024, the IASB issued the amendments to IFRS 9 and IFRS 7 “Classification and Measurement of Financial Instruments” aimed, essentially, to clarify the timing of derecognition of financial liabilities settled through electronic payment systems and to provide clarifications about the classification of financial assets with environmental, social and governance features (for example, sustainability bonds). The amendments shall be applied for annual reporting periods beginning on or after January 1, 2026.

On July 18, 2024, the IASB issued the document “Annual Improvements to IFRS Standards – Volume 11”, which include, basically, technical and editorial changes to existing standards. The amendments to the standards shall be applied for annual reporting periods beginning on or after January 1, 2026.

On December 18, 2024 the IASB issued the amendments to IFRS 9 and IFRS 7 “Contracts Referencing Nature dependent Electricity” aimed essentially at: (i) clarifying the use of the “own-use exemption” for power purchase agreements from renewable sources; and (ii) allowing, subject to certain conditions being met, the designation of a cash flow hedge in the presence of contracts for the purchase or sale of electricity from renewable sources (settable on a net basis). The amendments to the standards shall be applied for annual reporting periods beginning on or after January 1, 2026.

On November 13, 2025, the IASB issued amendments to IAS 21 “Translation to a Hyperinflationary Presentation Currency”, aimed at clarifying how financial statements should be translated from a non-hyperinflationary currency to a hyperinflationary one. The amendments are effective for annual reporting periods beginning on or after January 1, 2027.

Eni is currently reviewing the IFRSs not yet effective in order to determine the likely impact on the Consolidated Financial Statements.

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5 Business combinations and other significant transactions

Acquisitions

Plenitude

On December 22, 2025, Plenitude finalized the acquisition from Neoen, of a portfolio of 52 operating renewable generation plants and one operating battery, for a total of approximately 760 MW of installed capacity located throughout France. The total cash consideration of the transaction amounted to €234 million with acquisition of: (i) current and non-current assets for €1,040 million; (ii) net borrowings for €724 million, of which cash and cash equivalents for €38 million; (iv) current and non-current liabilities for €82 million. In the case of subsidiaries acquired exclusively for the purpose of sale/contribution, the Group, in applying the so-called short-cut method, does not fully consolidate the individual assets and liabilities, but instead separately presents assets and liabilities subject to future sale/contribution in the balance sheet.

Information about the definitive purchase price allocation of business combinations made in 2024 is provided in note 27 ‐ Other Information.

Divestments

Corporate and other activities

On December 18, 2025, Eni finalized the sale of a 49.99% stake in Eni CCUS Holding Ltd to the private equity fund Global Infrastructure Partners (GIP). Eni CCUS Holding Ltd acts as the holding company for the operating companies of the CCUS business, controlling 100% of Liverpool Bay CCS Ltd, Eni Netherlands CCUS BV, Bacton CCS Ltd, and Eni Tellus CCS Ltd. The transaction resulted in the exclusion from the scope of consolidation of net assets and liabilities for €222 million, of which other current financial assets for €45 million and cash and cash equivalents of €40 million, the realization of a capital gain for €46 million and the fair value of the retained stake of €27 million. Based on the agreements between the partners, joint control of the entity post-transfer was established.

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Balance sheet values of the divestments carried out in 2025 are shown in the following table:

(€ million) | Eni CCUS Holding Ltd | Other divestments | Total
Cash and cash equivalents | 40 |  | 40
Other current financial assets | 45 |  | 45
Other current assets | 84 | 1 | 85
Current assets | 169 | 1 | 170
Property, plant and equipment | 222 | 2 | 224
Deferred tax assets | 5 |  | 5
Other non-current assets | 428 |  | 428
Non-current assets | 655 | 2 | 657
TOTAL ASSETS | 824 | 3 | 827
Current financial liabilities |  |  |
Other current liabilities | 190 | 1 | 191
Current liabilities | 190 | 1 | 191
Non-current financial liabilities | 407 |  | 407
Other non-current liabilities | 5 |  | 5
Non-current liabilities | 412 |  | 412
TOTAL LIABILITIES | 602 | 1 | 603
Equity attributable to Eni | 222 | 2 | 224
TOTAL EQUITY | 222 | 2 | 224
TOTAL LIABILITIES AND EQUITY | 824 | 3 | 827

6 Cash and cash equivalents

Cash and cash equivalents of €8,100 million (€8,183 million at December 31, 2024) included financial assets with maturity of up to three months at the date of inception amounting to €5,304 million (€4,816 million at December 31, 202 4) and mainly included deposits with financial institutions, having notice of more than 48 hours, valued at amortized cost and with a non-significant expected credit loss.

Cash and cash equivalents mainly consisted of deposits in U.S. dollars for €4,713 million and in euro for €2,607 million (€5,269 million and €2,402 million at December 31, 2024, respectively) representing the use of cash on hand in the market for the financial needs of the Group.

Restricted cash amounted to €1 million (€54 million at December 31, 2024) in relation to foreclosure measures by third parties and obligations relating to the payment of debts.

The average maturity of financial assets originally due within 3 months was 10 days with an effective interest rate of 3.92% for bank deposits in U.S. dollars (€2,934 million) and 7 days with an effective interest rate of 2.21% for bank deposits in euros (€1,923 million).

7 Financial assets at fair value through profit or loss

(€ million) | December 31, 2025 | December 31, 2024
Financial assets held for trading |  |
Bonds issued by sovereign states | 734 | 965
Other securities | 6,168 | 5,474
| 6,902 | 6,439
Other financial assets at fair value through profit or loss |  |
Other securities | 89 | 358
| 89 | 358
| 6,991 | 6,797

The Company has established a liquidity reserve as part of its financial framework with a view of ensuring an adequate level of flexibility to the Group development plans and of copying with unexpected fund shortfalls or a sudden phase of credit crunch and restrictions in accessing financial markets. The management of this liquidity reserve is performed through trading activities with the aim of optimizing returns, within a predefined and authorized level of risk threshold, targeting the preservation of the invested capital and the ability to promptly convert it into cash.

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Financial assets held for trading include securities subject to lending agreements of €579 million (€738 million at December 31, 2024).

The breakdown by currency is provided below:

(€ million) | December 31, 2025 | December 31, 2024
Financial assets held for trading |  |
Euro | 4,458 | 4,230
U.S. dollars | 2,444 | 2,209
| 6,902 | 6,439
Other financial assets at fair value through profit or loss |  |
Euro |  | 162
U.S. dollars | 89 | 196
| 89 | 358
| 6,991 | 6,797

The breakdown by issuing entity and credit rating is presented below:

| Nominal value (€ million) | Fair Value (€ million) | Rating - Moody's | Rating - S&P
Quoted bonds issued by sovereign states |  |  |  |
Fixed rate bonds |  |  |  |
Italy | 56 | 57 | Baa2 | BBB+
United States of America | 483 | 481 | Aa1 | AA+
France | 65 | 65 | Aa3 | A+
Other (*) | 125 | 124 | from Aaa to Baa2 | from AAA to BBB-
| 729 | 727 |  |
Floating rate bonds |  |  |  |
Italy | 7 | 7 | Baa2 | BBB+
| 7 | 7 |  |
Total quoted bonds issued by sovereign states | 736 | 734 |  |
Other Bonds |  |  |  |
Fixed rate bonds |  |  |  |
Quoted bonds issued by industrial companies | 2,909 | 2,940 | from Aaa to Ba2 | from AAA to BB
Quoted bonds issued by financial and insurance companies | 1,086 | 1,098 | from Aa1 to Baa3 | from AA+ to BBB-
Other bonds | 355 | 363 | from Aaa to Ba1 | from AAA to BB+
| 4,350 | 4,401 |  |
Floating rate bonds |  |  |  |
Quoted bonds issued by industrial companies | 608 | 612 | from Aa2 to Ba1 | from AA to BB+
Quoted bonds issued by financial and insurance companies | 867 | 873 | from Aa1 to Baa2 | from AA+ to BBB
Other bonds | 280 | 282 | from Aaa to Baa2 | from AAA to BBB
| 1,755 | 1,767 |  |
Total other bonds | 6,105 | 6,168 |  |
Total financial assets held for trading | 6,841 | 6,902 |  |
Other financial assets at fair value through profit or loss | 85 | 89 | from Aaa to Baa1 | from AAA to BBB+
| 6,926 | 6,991 |  |

(*) Amounts included herein are lower than €50 million.

Other financial assets at fair value through profit or loss consisted of investments in Money Market funds.

The fair value hierarchy for financial assets held for trading is level 1 for €6,297 million and level 2 for €605 million. The fair value hierarchy for other financial assets measured at fair value with effects to profit or loss is level 2. During 2025, there were no significant transfers between the different hierarchy levels of fair value.

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8 Trade and other receivables

(€ million) | December 31, 2025 | December 31, 2024
Trade receivables | 8,986 | 12,562
Receivables from joint ventures in exploration and production activities | 1,238 | 1,754
Receivables from divestments | 209 | 527
Other receivables | 2,003 | 2,058
Total trade and other receivables net of allowance for doubtful accounts | 12,436 | 16,901

Generally, trade receivables do not bear interest and provide payment terms within 180 days.

The decrease in trade receivables of €3,576 million referred to the Global Gas & LNG Portfolio and Power segment for €1,621 million, to the Exploration & Production segment for €903 million and to the Plenitude business line for €821 million. The decrease in the Global Gas & LNG Portfolio and Power segment and the Plenitude business line reflected the decline in the prices of energy commodities, which decreased the nominal value of the receivables. The decrease in the Exploration & Production segment is due to crude oil trading activity, part of the reporting segment, due to price effects and to working capital optimization actions.

As part of its ordinary working capital management, Eni carries out non-recourse factoring transactions, mainly of trade receivables maturing in 2026. The transactions discounted in 2025 increased by €420 million compared to December 31, 2024.

At the balance sheet date, net trade receivables were outstanding for €498 million (€1,256 million at December 31, 2024) relating to supplies of equity hydrocarbons to Egyptian state-owned oil companies. During the year, a significant reduction in overdue receivables was recorded thanks to the completion of the regularization plan agreed with the Egyptian authorities in 2024 on the outstanding balance at that date. The accumulated impairment provisions corresponding to the amount recovered through the recovery plan were entirely reversed to the income statement.

The decrease in receivables from joint ventures in exploration and production activities of €516 million mainly related to cash calls from Eni’s partners in operated projects.

Receivables from other counterparties comprised: (i) the recoverable amount of €881 million (€690 million at December 31, 2024) of overdue trade receivables owed by the state-owned oil company of Venezuela, PDVSA, in relation to equity volumes of natural gas supplied by the joint venture Cardón IV SA, equally participated by Eni and Repsol sold by the venture to its shareholders. The recoverable value (nominal value of $2,300 million, corresponding to €1,956 million, with exclusion of accrued interest income) is estimated by discounting the expected stream of repayments at the cost of capital of the E&P segment adjusted to include Venezuela’s specific country risk premium (WACC adjusted). The increase included the update of the estimate of recoverability of the receivables and reflects a context of substantial cessation of in-kind reimbursements during 2025 due to the revocation of authorizations by the US Authorities. The assessment performed in the 2025 financial statements factored in the recent developments occurred in the Country in early 2026 and the initiatives undertaken by the U.S. administration with the issuance of general licenses to certain international oil companies, including Eni. Those developments have improved the prospects of recovering the overdue trade receivables compared to the previous context characterized by a substantial embargo of the USA over Venezuelan crude oil and products; (ii) prepayments for services of €404 million (€362 million at December 31, 2024); (iii) €243 million of receivables outstanding at December 31, 2024 relating to amounts to be received from customers following the triggering of the take-or-pay clause of long-term natural gas supply contracts. These receivables were offset against the debt for the related supply.

Trade and other receivables stated in euro for €6,880 million and U.S. dollars for €5,178 million (€9,173 million and €7,270 million at December 31, 2024, respectively).

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Credit risk exposure and expected losses relating to trade and other receivables have been prepared on the basis of internal ratings as follows:

| Performing receivables | Defaulted receivables | Plenitude customers | Total
(€ million) | Low risk | Medium Risk | High Risk
December 31, 2025 |  |  |  |  |  |
Business customers | 1,846 | 4,240 | 250 | 942 |  | 7,278
National Oil Companies and Public Administrations | 226 | 589 | 258 | 2,655 |  | 3,728
Other counterparties | 1,471 | 246 | 12 | 349 | 1,978 | 4,056
Gross amount | 3,543 | 5,075 | 520 | 3,946 | 1,978 | 15,062
Allowance for doubtful accounts | (8) | (18) | (12) | (2,034) | (554) | (2,626)
Net amount | 3,535 | 5,057 | 508 | 1,912 | 1,424 | 12,436
Expected loss (% net of counterpart risk mitigation factors) | 0.2 | 0.4 | 2.3 | 51.5 | 28.0 | 17.4
December 31, 2024 |  |  |  |  |  |
Business customers | 3,545 | 5,138 | 253 | 700 |  | 9,636
National Oil Companies and Public Administrations | 369 | 733 | 214 | 3,503 |  | 4,819
Other counterparties | 1,505 | 610 | 1 | 255 | 2,860 | 5,231
Gross amount | 5,419 | 6,481 | 468 | 4,458 | 2,860 | 19,686
Allowance for doubtful accounts | (10) | (27) | (12) | (2,162) | (574) | (2,785)
Net amount | 5,409 | 6,454 | 456 | 2,296 | 2,286 | 16,901
Expected loss (% net of counterpart risk mitigation factors) | 0.2 | 0.4 | 2.6 | 48.5 | 20.1 | 14.1

Defaulted receivables related to National Oil Companies and Public Administrations included receivables owed by the Venezuelan state oil company PDVSA for gas supplies produced by the Cardón IV SA joint venture, stated at the recoverable amount.

The classification of the Company’s customers and counterparties and the definition of the classes of counterparty risk are disclosed in note 1 – Significant accounting policies, estimates and judgments.

Recoverability of trade receivables for the supply of hydrocarbons, products and power to retail, business customers and national oil companies and of receivables towards partners in joint ventures of the Exploration & Production segment for cash calls (national oil companies, local private operators or international oil companies) is reviewed periodically at the close of each financial year to adjust the assessment to the current economic environment and business trends, as well as by factoring any possible increase in the counterparty risks.

The exposure to credit risk and expected losses relating to customers of Plenitude were assessed based on a provision matrix as follows:

| Not-past due | Past due | Total
(€ million) | from 0 to 3 months | from 3 to 6 months | from 6 to 12 months | over 12 months
December 31, 2025 |  |  |  |  |  |
Plenitude customers: |  |  |  |  |  |
- Retail | 812 | 91 | 51 | 127 | 281 | 1,362
- Middle | 385 | 15 | 2 | 8 | 105 | 515
- Other | 96 | 3 | 1 | 1 |  | 101
Gross amount | 1,293 | 109 | 54 | 136 | 386 | 1,978
Allowance for doubtful accounts | (46) | (25) | (40) | (95) | (348) | (554)
Net amount | 1,247 | 84 | 14 | 41 | 38 | 1,424
Expected loss (%) | 3.6 | 22.9 | 74.1 | 69.9 | 90.2 | 28.0
December 31, 2024 |  |  |  |  |  |
Plenitude customers: |  |  |  |  |  |
- Retail | 1,573 | 114 | 60 | 127 | 219 | 2,093
- Middle | 470 | 16 | 4 | 17 | 132 | 639
- Other | 123 | 2 | 1 | 1 | 1 | 128
Gross amount | 2,166 | 132 | 65 | 145 | 352 | 2,860
Allowance for doubtful accounts | (74) | (38) | (45) | (99) | (318) | (574)
Net amount | 2,092 | 94 | 20 | 46 | 34 | 2,286
Expected loss (%) | 3.4 | 28.8 | 69.2 | 68.3 | 90.3 | 20.1

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The following table analyses the allowance for doubtful accounts for trade and other receivables:

(€ million) | 2025 | 2024
Allowance for doubtful accounts - beginning of the year | 2,785 | 2,338
Additions for trade and other performing receivables | 150 | 136
Additions for trade and other defaulted receivables | 117 | 243
Utilizations for trade and other performing receivables | (21) | (85)
Utilizations for trade and other defaulted receivables | (416) | (324)
Other changes | 11 | 477
Allowance for doubtful accounts - end of the year | 2,626 | 2,785

The allowance for doubtful accounts was determined considering mitigation factors of the counterparty risk amounting to €2,775 million (€3,292 million at December 31, 2024), which included escrow accounts, insurance policies, sureties and bank guarantees.

Additions to allowance for doubtful accounts for trade and other performing receivables related to the Plenitude business line for €112 million (€92 million in 2024), mainly in the retail business.

Additions to allowance for doubtful accounts for trade and other defaulted receivables related to: (i) the Exploration & Production segment for €75 million (€150 million in 2024) and mainly concerned receivables for the supply of hydrocarbons to state company and receivables towards joint operators for cash calls in oil projects operated by Eni; (ii) the Refining business line for €17 million; (iii) the Plenitude business line for €9 million (€64 million in 2024).

Utilizations of allowance for doubtful accounts for trade and other performing and defaulted receivables amounted to €437 million and mainly related to: (i) the Exploration & Production segment for €265 million; (ii) the Plenitude business line for €138 million; (iii) to the Global Gas & LNG Portfolio business line for €8 million essentially as consequence of the reduction in credit exposures due to the changed market conditions.

Net (impairments) reversals of trade and other receivables are disclosed as follows:

(€ million) | 2025 | 2024 | 2023
New provisions | (267) | (379) | (502)
Net credit losses | (117) | (57) | (98)
Reversals | 373 | 268 | 351
Net (impairments) reversals of trade and other receivables | (11) | (168) | (249)

Receivables with related parties are disclosed in note 36 – Transactions with related parties.

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9 Current and non-current inventories

Current inventories are disclosed as follows:

(€ million) | December 31, 2025 | December 31, 2024
Raw and auxiliary materials and consumables | 1,001 | 1,436
Components and spare parts for drilling operations, plans and equipment | 1,288 | 1,721
Semi-finished, finished products and goods | 2,816 | 3,092
Other | 38 | 10
Current inventories | 5,143 | 6,259

Raw and auxiliary materials and consumables included oil-based feedstock and other consumables pertaining to refining and chemical activities.

Components to be consumed in drilling activities and maintenance of plants and infrastructure of the Exploration & Production segment amounted to €1,257 million (€1,685 million at December 31, 2024).

Semi-finished, finished products and goods included stocks of natural gas and oil products for €2,141 million (€2,164 million at December 31, 2024) and chemical products for €617 million (€742 million at December 31, 2024).

Inventories are stated net of write-down provisions of €656 million (€567 million at December 31, 2024).

Non-current inventories of €1,187 million (€1,595 million at December 31, 2024) are held for compliance purposes and related to Italian subsidiaries for €1,165 million (€1,575 million at December 31, 2024) in accordance with minimum stock requirements for oil and petroleum products set forth by applicable laws.

10 I ncome tax receivables and payables

| December 31, 2025 | December 31, 2024
(€ million) | Receivables | Payables | Receivables | Payables
| Current | Non-current | Current | Non-current | Current | Non-current | Current | Non-current
Income taxes | 539 | 125 | 343 | 40 | 695 | 129 | 587 | 40

Income taxes are described in note 33 — Income taxes.

Non-current income tax payables include a provision for the likely outcome of pending litigation with tax authorities in relation to uncertain tax matters relating to foreign subsidiaries of the Exploration & Production segment for €28 million (€34 million at December 31, 2024).

11 Other assets and liabilities

| December 31, 2025 | December 31, 2024
| Assets | Liabilities | Assets | Liabilities
(€ million) | Current | Non-current | Current | Non-current | Current | Non-current | Current | Non-current
Fair value of derivative financial instruments | 791 | 81 | 827 | 146 | 874 | 88 | 1,921 | 153
Contract liabilities |  |  | 788 | 520 |  |  | 552 | 655
Other Taxes | 919 | 24 | 1,589 | 47 | 850 | 147 | 1,749 | 48
Other | 2,233 | 2,734 | 835 | 2,677 | 1,938 | 3,776 | 827 | 3,593
| 3,943 | 2,839 | 4,039 | 3,390 | 3,662 | 4,011 | 5,049 | 4,449

The fair value related to derivative financial instruments is disclosed in note 24 – Derivative financial instruments and hedge accounting.

Assets related to other taxes included VAT for €763 million, of which €746 million are current, and advances made in December (€847 million at December 31, 2024, of which current €711 million).

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Other assets included: (i) tax credits current of €1,412 million (€1,210 million at December 31, 2024) and non-current of €1,570 million (€2,298 million at December 31, 2024) deriving from Italian tax measures to incentivize the renovation of residential buildings and energy savings; (ii) an asset of €550 million (€732 million at December 31,2024) recorded based on an agreement with an Italian operator to share past and expected environmental expenses incurred and fully provisioned by Eni at certain Italian industrial hub, under decommissioning, which were jointly operated in past years; (iii) underlifting positions of the Exploration & Production segment of €199 million (€318 million at December 31, 2024); (iv) non-current receivables from divestment activities for €169 million (€144 million at December 31, 2024); (v) gas volumes prepayments that were made in previous years due to take-or-pay obligations in relation to the Company's long-term supply contracts, whose underlying current portion Eni plans to recover within 12 months for €2 million and beyond 12 months for €85 million (€3 million and €295 respectively at December 31, 2024).

Contract liabilities included: (i) advances received from Società Oleodotti Meridionali SpA for the infrastructure upgrade of the crude oil transport system from Val d'Agri to the Taranto refinery for €496 million (€486 million at December 31, 2024); (ii) prepaid electronic fuel vouchers for €346 million (€331 million at December 31, 2024); (iii) advances received from customers for future gas supplies for €227 million (€65 million at December 31, 2024); (iv) advances received from Engie SA, relating to a long-term agreement for supplying natural gas and electricity for €44 million (€218 million at December 31, 2024), of which current for €12 million (€55 million at December 31, 2024).

Revenues recognized during the year related to contract liabilities stated at December 31, 2025, are indicated in note 29 – Revenues and other income.

Liabilities related to other current taxes include excise duties and consumer taxes for €811 million (€895 million at December 31, 2024) and VAT liabilities for €384 million (€405 million at December 31, 2024).

Other liabilities included: (i) non-current payables to factoring companies connected with the derecognition of tax credits deriving from Italian tax measures to incentivize the renovation of residential buildings and energy savings for €1,422 million (€2,104 million at December 31, 2024); (ii) current overlifting imbalances of the Exploration & Production segment for €267 million (€396 million at December 31, 2024); (iii) a put option recognized by Eni to EIP fund, which acquired a non-controlling interest of Plenitude, by subscribing a reserved capital increase of €588 million in March 2024 and a €209 million reserved capital increase in March 2025. The put option valorizes Eni’s commitment to repurchase at fair value enough shares of Plenitude held by EIP as required to pay down the financial debt incurred by EIP for the transaction. The book value of the put option is stated at the present value of Eni's maximum financial commitment equal to €541 million (€392 million as of December 31, 2024). The expiry date is 2027; (iv) the value of gas paid and undrawn by customers due to the triggering of the take-or-pay clause provided for by the relevant long-term contracts for €57 million is expected to be drawn beyond the next 12 months (€303 million at December 31, 2024); (v) payables related to investing activities for €49 million (€96 million at December 31, 2024).

Transactions with related parties are described in note 36 — Transactions with related parties.

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12 Property, plant and equipment

(€ million) | Land and buildings | E&P wells, plant and machinery | Other plant and machinery | E&P exploration assets and appraisal | E&P tangible assets in progress | Other tangible assets in progress and advances | Total
2025 |  |  |  |  |  |  |
Net carrying amount - beginning of the year | 1,142 | 38,229 | 4,491 | 1,742 | 11,296 | 2,964 | 59,864
Additions | 24 | 70 | 532 | 384 | 6,080 | 1,612 | 8,702
Depreciation capitalized |  |  |  | 8 | 259 |  | 267
Depreciation (*) | (60) | (5,295) | (614) |  |  |  | (5,969)
Impairments | (10) | (822) | (225) |  | (307) | (374) | (1,738)
Reversals |  | 30 | 109 |  | 24 | 42 | 205
Write-off |  |  | (1) | (13) |  | (2) | (16)
Currency translation differences | (2) | (4,092) | (132) | (178) | (1,065) | (24) | (5,493)
Initial recognition and changes in estimates | (2) | 75 | 11 | (8) | 174 | 29 | 279
Changes in the scope of consolidation | 10 |  | 5 |  |  | (224) | (209)
Transfers | 40 | 7,382 | 815 | (128) | (7,254) | (855) |
Other changes | (5) | (2,023) | (317) | (258) | (3,261) | 508 | (5,356)
Net carrying amount - end of the year | 1,137 | 33,554 | 4,674 | 1,549 | 5,946 | 3,676 | 50,536
Gross carrying amount - end of the year | 4,444 | 115,147 | 33,421 | 1,549 | 8,355 | 6,276 | 169,192
Provisions for depreciation and impairments | 3,307 | 81,593 | 28,747 |  | 2,409 | 2,600 | 118,656
2024 |  |  |  |  |  |  |
Net carrying amount - beginning of the year | 1,111 | 37,421 | 4,588 | 1,568 | 9,682 | 1,929 | 56,299
Additions | 31 | 20 | 255 | 419 | 5,546 | 1,728 | 7,999
Depreciation capitalized |  |  |  | 28 | 260 |  | 288
Depreciation (*) | (57) | (5,668) | (575) |  |  |  | (6,300)
Impairments | (9) | (1,705) | (371) |  | (669) | (382) | (3,136)
Reversals |  | 107 | 92 |  | 74 | 30 | 303
Write-off |  | (1) | (1) | (414) | (5) | (1) | (422)
Currency translation differences | 1 | 2,071 | 49 | 91 | 554 | 8 | 2,774
Initial recognition and changes in estimates |  | 35 | 6 | (4) | 62 | (2) | 97
Changes in the scope of consolidation - included entities | 12 | 1,314 | 3 | 97 | 1,090 | 70 | 2,586
Changes in the scope of consolidation - excluded entities | (1) | (822) | (17) | (25) | (486) |  | (1,351)
Transfers | 47 | 6,865 | 566 | (6) | (6,859) | (613) |
Other changes | 7 | (1,408) | (104) | (12) | 2,047 | 197 | 727
Net carrying amount - end of the year | 1,142 | 38,229 | 4,491 | 1,742 | 11,296 | 2,964 | 59,864
Gross carrying amount - end of the year | 4,412 | 139,117 | 33,226 | 1,742 | 14,589 | 5,490 | 198,576
Provisions for depreciation and impairments | 3,270 | 100,888 | 28,735 |  | 3,293 | 2,526 | 138,712

(*) Before capitalization of depreciation of tangible assets

Capital expenditures included capitalized finance expenses of €120 million (€220 million in 2024) related to the Exploration & Production segment for €76 million (€173 million in 2024) at an average interest rate of 3.2% (3.5% at December 31, 2024).

Capital expenditures primarily related to the Exploration & Production segment for €6,666 million (€6,033 million in 2024).

Investments for the purchase of plant and equipment under supplier financing arrangements which resulted in the classification of the related debt as financial liabilities were recorded in the line item “Other changes” (€1,371 million).

Capital expenditures by industry segment and geographical area of destination are reported in note 35 – Segment information and information by geographical area.

Depreciation other than that of oil&gas assets, relating to biorefineries, petrochemical plants, thermoelectric plants, photovoltaic or wind power systems, and other ancillary assets are calculated on a straight-line basis, based on their economic-technical lives.

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The main depreciation rates adopted are included in the following ranges and have remained substantially unchanged compared to 2024:

(%) |
Buildings | 2 - 10
Refining and chemical plants | 3 - 17
Gas pipelines and compression stations | 4 - 12
Power plants | 3 - 5
Other plant and machinery | 6 - 12
Industrial and commercial equipment | 5 - 25
Other assets | 10 - 20

Plant and equipment used for the extraction and treatment of hydrocarbons were depreciated according to the UOP method, using as a basis for calculation the proved reserves estimated according to the criteria of the U.S. SEC, as well as volumes of unproved reserves in the case of facilities used in phased development projects or common facilities (see note 1 – Accounting standards, accounting estimates and significant judgements, section UOP depreciation, depletion and amortization). The production plans associated with the existing assets gradually deplete the SEC proved reserves recorded at the balance sheet date, as well as the additional volumes of unproved reserves, which are expected to be produced within approximately thirteen years.

Net impairment losses of property, plant and equipment mainly related: (i) to oil&gas properties in Congo (€332 million) and Ivory Coast (€179 million), which were aligned to the sale price as part of the E&P portfolio rationalization program as well as oil & gas properties in Italy, Turkmenistan, United Arab Emirates and USA in relation to reserve revisions and commodity price forecasts (total €564 million); (ii) expenditures incurred for compliance and stay-in-business at CGUs in the Refining and traditional Chemicals segment were completely written-off because those CGUs were impaired in previous reporting periods and continued lacking any profitability prospects, as well as polyethylene plants due to a structurally deteriorated profitability outlook (€413 million). In the three-year period 2023-2025, Eni booked impairment charges at all its oil-based petrochemicals complexes, driven by challenged market fundamentals, competitive disadvantages of the European industrial sector resulting from higher operating and energy costs compared to other geographies, and rising competitive pressures from operators benefiting of larger scale and lower feedstock costs amid global overcapacities. A transformation and industrial reconversion plan for Eni's chemical segment is underway, leveraging proprietary technologies and the development of profitable business lines such as biochemistry, recycled chemicals and compounding, while traditional sites that are no longer competitive are being shut down or reconverted to transition businesses.

More information about Eni’s impairment review and the sensitivity of the outcome to different commodities scenarios is reported in note 15 – Impairments of tangible and intangible assets and right-of-use assets. Sensitivity of outcomes to decarbonization scenarios.

Currency translation differences related to subsidiaries utilizing the U.S. dollar as functional currency (€5,445 million).

Initial recognition and change in estimates include the increase in the asset retirement cost of tangible assets in the Exploration & Production segment due to the increase in abandonment cost estimates and start of new projects, partially offset by the decrease in discount rates, particularly of the U.S. dollar.

Changes in the scope of consolidation related to the divestment of €222 million in connection with the loss of control of Eni CCUS Holding Ltd. Further information on the transaction is provided in note 5 – Business combinations and other significant transactions.

Other changes include: (i) the sale of oil and gas assets in Ivory Coast for €1,160 million; (ii) the reclassification of oil and gas assets in Indonesia and in the United Arab Emirates to assets held for sale for €5,850 million, which are planned to be contributed in exchange of shareholdings in newly established equity-accounted entities with other operators in 2026, as well as in Congo and Ivory Coast in connection with ongoing divestments procedures. The carrying amounts of these portions of undivided properties have been aligned with the expected fair value of the sale. Further information is provided in note 25 – Assets held for sale and directly associated liabilities.

Transfers from E&P tangible assets in progress to E&P UOP wells, plant and equipment related for €6,280 million to the commissioning of wells, plants and equipment primarily in Congo, Ivory Coast, Egypt, Kazakhstan, Indonesia, Italy, Algeria and Mexico.

Exploration and appraisal activities included write-offs for €13 million of previously capitalized exploration wells pending economic and technical evaluation in Oman, Algeria and Nigeria.

Exploration and appraisal activities related for €1,441 million to the costs of suspended exploration wells pending final determination of commerciality based on management’s continuing commitment and for €108 million to costs of exploration wells in progress at the end of the year.

Changes relating to suspended wells are reported below:

(€ million) | 2025 | 2024 | 2023
Costs for exploratory wells suspended - beginning of the year | 1,662 | 1,391 | 1,085
Increases for which is ongoing the determination of proved reserves | 347 | 485 | 834
Amounts previously capitalized and expensed in the year | (11) | (362) | (388)
Reclassification to successful exploratory wells following the estimation of proved reserves | (128) | (4) | (72)
Disposals | (79) | (7) | (3)
Changes in the scope of consolidation |  | 76 |
Currency translation differences | (167) | 83 | (40)
Other changes | (183) |  | (25)
Costs for exploratory wells suspended - end of the year | 1,441 | 1,662 | 1,391

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The following information relates to the stratification of the suspended wells pending final determination (ageing):

| 2025 | 2024 | 2023
| (€ million) | (number of wells in Eni’s interest) | (€ million) | (number of wells in Eni’s interest) | (€ million) | (number of wells in Eni’s interest)
Costs capitalized and suspended for exploratory well activity |  |  |  |  |  |
- within 1 year | 218 | 5.8 | 253 | 4.4 | 417 | 7.9
- between 1 and 3 years | 419 | 8.3 | 604 | 11.3 | 347 | 6.1
- beyond 3 years | 804 | 16.0 | 805 | 18.2 | 627 | 14.5
| 1,441 | 30.1 | 1,662 | 33.9 | 1,391 | 28.5
Costs capitalized for suspended wells |  |  |  |  |  |
- fields including wells drilled over the last 12 months | 218 | 5.8 | 253 | 4.4 | 417 | 7.9
- fields for which the delineation campaign is in progress | 826 | 13.3 | 1,053 | 16.1 | 804 | 14.0
- fields including commercial discoveries that are progressing to a FID | 397 | 11.0 | 356 | 13.4 | 170 | 6.6
| 1,441 | 30.1 | 1,662 | 33.9 | 1,391 | 28.5

The capitalized costs for suspended wells relating to fields including wells drilled over the last twelve months referred to ten leases for which the evaluation of results is still in progress.

The capitalized costs for suspended wells relating to fields for which the delineation campaign is in progress referred for approximately €520 million to nine leases for which appraising activities and negotiations are ongoing to unlock the subsequent project phases; the remaining amounts are related to five leases for which drilling activities are underway or firmly planned for the near future.

Suspended wells costs pending a final investment decision primarily related to initiatives in Congo, Nigeria and United Arab Emirates.

Unproved mineral interests, comprised of assets in progress of the Exploration & Production segment, include the purchase price allocated to unproved reserves following business combinations or acquisition of individual properties.

Unproved mineral interests were as follows:

(€ million) | Congo | Nigeria | USA | Algeria | Egypt | United Arab Emirates | Italy | Indonesia | Netherlands | Tunisia | Australia | Total
2025 |  |  |  |  |  |  |  |  |  |  |  |
Carrying amount - beginning of the year | 16 | 981 | 77 | 187 | 3 | 445 | 2 | 848 | 120 |  |  | 2,679
Additions |  | 27 |  | 63 |  |  |  | 115 |  | 7 | 3 | 215
Net (impairments) reversals | (4) |  | (36) |  |  | (22) | (2) |  | (8) |  |  | (72)
Reclassification to Proved Mineral Interest |  | (20) |  | (100) |  | (54) |  | (804) | (88) |  |  | (1,066)
Currency translation differences and other changes | (3) | (114) | (8) | (20) | (1) | (137) |  | (124) |  |  | 19 | (388)
Carrying amount - end of the year | 9 | 874 | 33 | 130 | 2 | 232 |  | 35 | 24 | 7 | 22 | 1,368
2024 |  |  |  |  |  |  |  |  |  |  |  |
Carrying amount - beginning of the year | 429 | 924 | 23 | 215 | 2 | 475 | 2 | 89 |  |  |  | 2,159
Additions |  |  |  |  | 15 |  |  | 709 | 120 |  |  | 844
Net (impairments) reversals | (421) |  | 74 |  | (5) |  |  |  |  |  |  | (352)
Reclassification to Proved Mineral Interest |  | (2) | (24) | (40) | (9) | (58) |  |  |  |  |  | (133)
Currency translation differences and other changes | 8 | 59 | 4 | 12 |  | 28 |  | 50 |  |  |  | 161
Carrying amount - end of the year | 16 | 981 | 77 | 187 | 3 | 445 | 2 | 848 | 120 |  |  | 2,679

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Unproved mineral interests comprised the net book value of the Oil Prospecting License 245 property (“OPL 245”), offshore Nigeria, whose exploration period expired on May 11, 2021. The book value of €1,141 million included €835 million as the purchase price paid in 2011 to the Nigerian Government to acquire a 50% interest in the asset and the subsequent capitalized exploration costs and pre-development costs. A lengthy and complex criminal proceeding before the Court of Milan was definitively resolved in favor of Eni, which related to alleged crimes of international corruption regarding the purchase of the license. An arbitration started by Eni before an ICSID tribunal (the International Centre for Settlement of Investment Disputes) to protect the value of the investment, claiming the Company’s right to obtain the conversion of the license into an Oil Mining Lease has been put on hold as the parties have been exploring a possible agreement to set economic terms and conditions to develop the property’s reserves. The agreement was signed in early March 2026, with the parties waiving all pending claims relating to the asset, including the arbitration proceedings. The estimated recoverable value of the asset, based on the agreed economic terms of development of the license reserves, has confirmed the resilience of the book value.

The reclassification of unproved mineral interests to proved mineral interests mainly referred to Indonesia following the final investment decision of some projects with the consequent recognition of proved reserves.

Accumulated provisions for impairments amounted to €20,250 million (€22,205 million at December 31, 2024).

Property, plant and equipment include assets subject to operating leases for €270 million, essentially relating to service stations of the Enilive business line.

As of December 31, 2025, Eni pledged property, plant and equipment for €24 million to guarantee payments of excise duties (same amount as of December 31, 2024).

Government grants recorded as a decrease of property, plant and equipment amounted to €99 million (€88 million at December 31, 2024).

Contractual commitments related to the purchase of property, plant and equipment are disclosed in note 28 – Guarantees, commitments and risks – Liquidity risk.

Property, plant and equipment under concession arrangements are described in note 28 – Guarantees, commitments and risks.

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13 Right-of-use assets and lease liabilities

(€ million) | Floating production storage and offloading vessels (FPSO) | Drilling rig | Naval facilities and related logistic bases for oil and gas transportation | Motorway concessions and service stations | Oil and gas distribution facilities | Office buildings | Vehicles | Other | Total
2025 |  |  |  |  |  |  |  |  |
Net carrying amount - beginning of the year | 2,606 | 419 | 1,005 | 452 | 36 | 487 | 21 | 796 | 5,822
Additions |  | 266 | 566 | 91 | 10 | 138 | 20 | 59 | 1,150
Depreciation (*) | (176) | (248) | (496) | (76) | (20) | (120) | (10) | (98) | (1,244)
Impairments |  |  |  | (11) | (1) |  |  | (2) | (14)
Currency translation differences | (295) | (32) | (14) | 1 |  | (10) |  | (36) | (386)
Other changes | (1) | (53) | (44) | (7) | (2) | (3) | (5) | (29) | (144)
Net carrying amount - end of the year | 2,134 | 352 | 1,017 | 450 | 23 | 492 | 26 | 690 | 5,184
Gross carrying amount - end of the year | 2,844 | 1,309 | 2,490 | 954 | 101 | 1,142 | 53 | 999 | 9,892
Provisions for depreciation and impairment | 710 | 957 | 1,473 | 504 | 78 | 650 | 27 | 309 | 4,708
2024 |  |  |  |  |  |  |  |  |
Net carrying amount - beginning of the year | 1,977 | 449 | 724 | 492 | 17 | 580 | 17 | 578 | 4,834
Additions | 630 | 294 | 690 | 59 | 53 | 52 | 19 | 317 | 2,114
Depreciation (*) | (146) | (342) | (391) | (79) | (22) | (132) | (14) | (73) | (1,199)
Impairments |  |  | (4) | (21) | (10) |  |  | (5) | (40)
Currency translation differences | 145 | 19 | 5 | (1) |  | 7 |  | 18 | 193
Changes in the scope of consolidation |  | 38 |  |  |  | 5 | 1 | (2) | 42
Other changes |  | (39) | (19) | 2 | (2) | (25) | (2) | (37) | (122)
Net carrying amount - end of the year | 2,606 | 419 | 1,005 | 452 | 36 | 487 | 21 | 796 | 5,822
Gross carrying amount - end of the year | 3,217 | 1,235 | 2,095 | 873 | 97 | 1,067 | 57 | 1,049 | 9,690
Provisions for depreciation and impairment | 611 | 816 | 1,090 | 421 | 61 | 580 | 36 | 253 | 3,868

(*) Before capitalization of depreciation of tangible and intangible assets

Right-of-use assets (RoU) of €5,184 million mainly related: (i) for €3,634 million (€4,266 million at December 31, 2024) to the Exploration & Production segment and mainly comprised leases of certain FPSO vessels and platforms used in the development of the OCTP offshore projects in Ghana, Area 1 in Mexico and Baleine in Ivory Coast, for a duration between 11 and 15 years including the renewal option, as well as the multi-year rental of drilling rigs, in relation to the lease component only and the rental of naval vessels for shipping activities; (ii) for €538 million (€519 million at December 31, 2024) to the Enilive business line relating to highways concessions, leases of land and of service stations for sale of oil products, equipment rentals with EVS (Eni Virtual Station) cloud architecture for the integrated management of service stations and car fleet dedicated to the car sharing business; (iii) for €532 million (€476 million at December 31, 2024) to the Corporate and Other activities segment mainly regarding property rental contracts (real estate and IT).

The increase referred to: (i) the Exploration & Production segment for €860 million relating to vessels and related logistics equipment for oil & gas transport (€535 million) of which €115 million relating to Eni Trade & Biofuels SpA and the rental of drilling rigs for €266 million. Main contracts concerned assets in Congo, Italy and Mexico; (ii) the Enilive business line for new contracts and extension of existing contracts relating highways concessions, land leases, service station leases and car fleet dedicated to the car sharing business for €141 million; (iii) the Corporate and Other activities segment for €122 million, mainly referred to the extensions of Italian property leasing contracts for €94 million.

Leasing contracts signed for which the asset is not yet available essentially concern a contract with a nominal value of €331 million relating to lease of Italian office buildings with an expiry date of 20 years.

Main future cash outflows potentially due not reflected in the measurements of lease liabilities related to options for the extension or termination of leases existing as of December 31, 2025 of: (i) ancillary assets in the upstream business for €830 million; (ii) service stations for sale of oil products of €153 million; (iii) Italian office property leases of €166 million.

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Liabilities for leased assets were as follows:

(€ million) | Current portion of long-term lease liabilities | Long-term lease liabilities | Total
2025 |  |  |
Carrying amount at the beginning of the year | 1,279 | 5,174 | 6,453
Additions |  | 1,150 | 1,150
Decreases | (1,240) | (10) | (1,250)
Currency translation differences | (73) | (349) | (422)
Other changes | 1,297 | (1,528) | (231)
Carrying amount at the end of the year | 1,263 | 4,437 | 5,700
2024 |  |  |
Carrying amount at the beginning of the year | 1,128 | 4,208 | 5,336
Additions |  | 2,109 | 2,109
Decreases | (1,194) | (11) | (1,205)
Currency translation differences | 36 | 175 | 211
Changes in the scope of consolidation | 35 | 15 | 50
Other changes | 1,274 | (1,322) | (48)
Carrying amount at the end of the year | 1,279 | 5,174 | 6,453

Lease liabilities related for €761 million (€616 million at December 31, 2024) to the portion of the liabilities attributable to joint operators in Eni-led projects which will be recovered through partner billing process.

Total cash outflows for leases consisted of the following: (i) cash payments for the main portion of the lease liability for €1,250 million; (ii) cash payments for the interest portion of €324 million.

Lease liabilities stated in U.S. dollars for €3,788 million and in euro for €1,703 million (€4,510 million and €1,723 million at December 31, 2024, respectively).

Other changes in right-of-use assets and lease liabilities essentially related to early termination or renegotiation of lease contracts.

Liabilities for leased assets with related parties are described in note 36 — Transactions with related parties.

The amounts recognised in the profit and loss account consisted of the following:

(€ million) | 2025 | 2024 | 2023
Other income and revenues |  |  |
Income from remeasurement of lease liabilities | 22 | 14 | 17
| 22 | 14 | 17
Purchases, services and other |  |  |
Expense from remeasurement of lease liabilities | 2 | 3 | 3
Short-term leases | 69 | 81 | 59
Low-value leases | 39 | 37 | 37
Variable lease payments not included in the measurement of lease liabilities | 24 | 22 | 20
Capitalized direct cost associated with self-constructed assets - tangible assets | (4) | (5) | (5)
| 130 | 138 | 114
Depreciation, net impairments and write-offs |  |  |
Depreciation of RoU leased assets | 1,244 | 1,199 | 973
Capitalized direct cost associated with self-constructed assets - tangible and intangible assets | (260) | (277) | (199)
Impairments of RoU leased assets | 14 | 40 | 41
Reversals of RoU leased assets | (2) | (4) | (5)
Write-off of RoU leased assets |  | 3 |
| 996 | 961 | 810
Finance income (expense) from leases |  |  |
Interests on lease liabilities | (348) | (314) | (267)
Capitalized finance expense of RoU leased assets - tangible assets | 7 | 17 | 11
Net currency translation differences on lease liabilities | 62 | (36) | 19
| (279) | (333) | (237)

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14 Intangible assets

(€ million) | Exploration rights | Industrial patents and intellectual property rights | Other intangible assets with definite useful lives | Intangible assets with definite useful lives | Goodwill | Other intangible assets with indefinite useful lives | Total
2025 |  |  |  |  |  |  |
Net carrying amount - beginning of the year | 534 | 397 | 2,310 | 3,241 | 3,167 | 26 | 6,434
Additions | 7 | 14 | 506 | 527 |  |  | 527
Depreciation capitalized |  |  | 6 | 6 |  |  | 6
Depreciation (*) | (4) | (98) | (307) | (409) |  |  | (409)
Impairments |  |  | (45) | (45) |  |  | (45)
Reversals |  |  | 8 | 8 |  |  | 8
Write-off | (17) |  |  | (17) |  |  | (17)
Changes in the scope of consolidation |  |  | (428) | (428) | 2 |  | (426)
Currency translation differences | (54) |  | (21) | (75) |  |  | (75)
Other changes | (20) | 39 | 5 | 24 | (5) |  | 19
Net carrying amount - end of the year | 446 | 352 | 2,034 | 2,832 | 3,164 | 26 | 6,022
Gross carrying amount - end of the year | 869 | 2,215 | 5,235 | 8,319 |  |  |
Provisions for amortization and impairment | 423 | 1,863 | 3,201 | 5,487 |  |  |
2024 |  |  |  |  |  |  |
Net carrying amount - beginning of the year | 663 | 450 | 2,107 | 3,220 | 3,133 | 26 | 6,379
Additions | 14 | 31 | 441 | 486 |  |  | 486
Depreciation capitalized |  |  | 4 | 4 |  |  | 4
Depreciation (*) | (6) | (98) | (289) | (393) |  |  | (393)
Impairments | (10) |  | (12) | (22) | (9) |  | (31)
Write-off | (153) |  | (2) | (155) |  |  | (155)
Changes in the scope of consolidation |  |  | 73 | 73 | 36 |  | 109
Currency translation differences | 31 |  | 12 | 43 |  |  | 43
Other changes | (5) | 14 | (24) | (15) | 7 |  | (8)
Net carrying amount - end of the year | 534 | 397 | 2,310 | 3,241 | 3,167 | 26 | 6,434
Gross carrying amount - end of the year | 1,197 | 2,166 | 5,190 | 8,553 |  |  |
Provisions for amortization and impairment | 663 | 1,769 | 2,880 | 5,312 |  |  |

(*) Before capitalization of depreciation of intangible assets.

Exploration rights comprised the residual book value of signature bonuses and acquisition costs of exploration licenses relating to areas with proved reserves, which are amortized based on UOP criteria and are regularly reviewed for impairment. The costs of licenses with unproved reserves are also in this item and are suspended pending a final determination of the success of the exploration activity or until management confirms its commitment to the initiative. Additions for the year related to signature bonuses paid for the acquisition of new exploration acreage primarily in Ivory Coast.

The breakdown of exploration rights by type of asset was as follows:

(€ million) | December 31, 2025 | December 31, 2024
Proved licence and leasehold property acquisition costs | 61 | 79
Unproved licence and leasehold property acquisition costs | 385 | 455
| 446 | 534

Industrial patents and intellectual property rights mainly regarded the acquisition and internal development of software and rights for the use of production processes and software.

Write-offs of €17 million related to the abandonment of underlying initiatives.

Changes in the scope of consolidation of assets with a finite useful life comprised the divestments of Eni CCUS Holding Ltd. Further information on the transaction is provided in note 5 – Business combinations and other significant transactions.

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Other intangible assets comprised: (i) concessions, licenses, trademarks and similar items for €1,096 million (€1,154 million at December 31, 2024), of which €891 million relating to relating to the Plenitude business line essentially for activities in relation to renewable energy sources (€898 million at December 31, 2024); (ii) customer acquisition costs relating to the Plenitude business line for €469 million (€412 million at December 31, 2024); (iii) customer relationship for €75 million recognized following the acquisition of Finproject group from the Chemicals business line (€84 million at December 31, 2024).

The main amortization rates used were substantially unchanged from the previous year and ranged as follows:

(%) |
Exploration rights | UOP
Concessions, licenses, trademarks and similar items | 3 - 33
Industrial patents and intellectual property rights | 20 - 33
Capitalized costs for customer acquisition | 17 - 33
Other intangible assets | 3 - 20

Cumulative impairment charges of goodwill at the end of the year amounted to €2,642 million.

The breakdown of goodwill by segment and business line is provided below:

(€ million) | December 31, 2025 | December 31, 2024
Plenitude | 2,916 | 2,916
Enilive | 116 | 121
Chemical | 119 | 117
Others | 13 | 13
| 3,164 | 3,167

Changes in the scope of consolidation of goodwill related to the consolidation of ​​ Tecnofilm SpA, incorporated during the year by Finproject SpA.

Other changes relating to goodwill concern the definitive allocation of some acquisitions made in 2024, the allocation of which had been made on a provisional basis (see note 27 – Other information).

Contributions recorded as decrease in intangible assets amounted to €8 million (€37 million at December 31, 2024).

Goodwill acquired through business combinations has been allocated to the CGUs that are expected to benefit from the synergies of the acquisition.

The Plenitude business line is engaged in the retail sale of natural gas and electricity, in the electricity generation from renewable sources and in installing and managing a charging network for electric vehicles. Plenitude has closed several acquisitions in past reporting years leading to the recognition of significant amounts of goodwill in each of those activities.

Goodwill allocated to the activity of the retail sale of natural gas and electricity amounted to €1,220 million and to test its recoverability has been allocated to a single CGU encompassing all European retail markets where Plenitude is operating considering the significant cross-market synergies and geographic integration. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of this CGU comprising the book value of the allocated goodwill.

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The impairment review of the CGU Retail including goodwill, was performed by comparing the carrying amount to the value in use of the CGU, which was estimated based on the cash flows of the 2026-2030 industrial plan approved by management and on a terminal value calculated as the perpetuity of the cash flow of the last year of the plan by assuming a nominal long-term growth rate equal to zero, unchanged from the previous year. These cash flows were discounted by using the post-tax WACCs of the retail business in each country of operation, with post-tax values in a range of 4.3% - 4.8%, corresponding to 5.5% - 6.6% pre-tax. There are currently no reasonable assumptions of changes in the discount rate, growth rate, profitability or volumes that would lead to zeroing the headroom amounting to about €8 billion of the value in use of the CGU Retail with respect to its book value, including the allocated goodwill.

The renewable business of Plenitude included a goodwill of €978 million related to the business combinations made in Italy and in other European markets where operations are being developed (Spain, France, Greece). The recoverability of goodwill was tested by grouping the assets by homogeneous CGUs, corresponding to geographical areas, taking into account technical, economic, and contractual aspects. The recoverability of goodwill was assessed with reference to the entire CGU. The impairment test to verify the recoverability of the carrying amounts, including the allocated goodwill, was performed based on the calculation of the value in use using the discounted cash flow method, which includes, for the first four years of the projection, the business plan approved by management. For the following years the projection coincides with the economic-technical life of the plants using normalized cash flows. Cash flows were determined on the basis of wholesale electricity price forecasts estimated by management, differentiated by geographical area; for Italy an average price of approximately €106/kWh in the five-year plan 2026-2030 and of about €111/kWh for long-term prices. Cash flows have been discounted at sector and country-specific post-tax WACCs, which were comprised in a range of 5.5% - 8.9%, corresponding to 7% - 11.1% pre-tax. This test has confirmed the recoverability of the book values of the complex of plants generating renewable electricity, including the allocated goodwill. The headroom of €695 million is reduced to zero in case of a 1.4 percentage point increase in the WACC, or a reduction in power prices of approximately 14%.

Goodwill of the electric mobility business of Plenitude of €718 million was recognized in connection with the acquisition in 2021 of the entire share capital of Be Charge (now Plenitude On The Road), which engages in building and managing a network of charging infrastructures for electric mobility. This goodwill was tested for recoverability based on the calculation of the value in use through explicit cash flow projections for ten-years and a terminal value incorporating a normalized cash flow projection of the last year, using a nominal growth rate risked with respect to the projections on the development of the electric vehicle market provided by primary info-providers. The cash flow was discounted at a post-tax WACC of 9.2%, corresponding to 12.8% pre-tax. This test confirmed the recoverability of the allocated book values ​​including the allocated goodwill and showed a headroom of about €1 billion which would go to zero by assuming a 3.7% increase in the post-tax WACC and would remain positive even by assuming a zero-growth rate.

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

Climate change and energy transition

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

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

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

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

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

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

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

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

- the future cash flows were determined using the assumptions included in the industrial plan 2026-2030 and in the long-term plan of the Company approved by the Board of Directors. These assumptions, including operational costs, development expenditures, estimation of oil and gas reserves, future volumes produced and marketed, and timing and costs of decommissioning oil&gas plants and facilities represent the best estimate from the Company Management of economic and technical conditions over the remaining life of the assets;

The oil and gas price projections adopted by the Company are based on the following assumptions:

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

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

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

| 2026 | 2027 | 2028-2030 | 2050
Brent $/bbl | 68 | 66 | 75 | 53

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

|  | 2026 | 2027-2029 | 2030-2050
TTF Europe $/Mbtu |  | 11.8 | 8.5 | 7.5

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

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

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

The future cash flows are estimated over a period consistent with the life of the CGUs. They are elaborated post-tax and take into account specific risks related to the CGUs’ assets. They are discounted by applying a 6% post-tax discount rate (unchanged from 2024), this rate being the weighted-average cost of the capital to the Group estimated from market data and future projections of the mix of funds employed to finance the invested capital. This rate is adjusted to factor a risk premium specific to each country where the group operates (WACC Adjusted). The value in use calculated by discounting the above post-tax cash flows is not materially different from the value in use calculated by discounting pre-tax cash flows using a pre-tax discount rate determined by an iterative computation from the post-tax value in use. These pre-tax discount rates generally range from 9% to 15% in the case of assets impaired in 2025.

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

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

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

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

- consideration of the price curves and CO 2 costs of the IEA’s Net Zero Scenario 2050 for all assets.

| Value in use of the O&G CGUs Headroom vs Carrying amounts |  | Possible impairment losses through profit and loss account |
| Tax-deductible CO 2 charges |  | € billion |
Eni's scenario | 63% |  |  |
10% haircut of Eni's prices assumptions | 45% |  | (1) |
Eni's scenario with +1% increase in WAAC | 53% |  | (0.2) |
IEA NZE 2050 scenario | 18% |  | (3.4) |

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

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

The characteristics of Eni’ s portfolio, the fast-track and phased development approach in producing reserves and absence of exposure to unconventional projects mitigate the risk of having stranded assets in the future if a structural decline in demand for hydrocarbons occurs due to stricter global environmental regulations and constraints and a resulting change in consumer preferences. The Company will continue to review price assumptions as the energy transition progresses and this may result in additional impairment charges in the future.

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

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

Other risks

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

Asset retirement obligations, which result from a legal or constructive obligation, are recognized based on a reasonable estimate in the period in which the obligation arises. The associated asset retirement costs are capitalized as part of the carrying amount of the underlying asset and depreciated over the useful life of this asset.

An entity is required to measure changes in the liability for an asset retirement obligation due to the passage of time (accretion) by applying a discount rate to the amount of liability. Given the long-term nature of expenditures related to our asset retirement obligations, the rate is determined by reference to the rates of treasury bonds having comparable duration as that of the liability. The increase of the provision due to the passage of time is recognized as “Other financial expense”.

The discount rate used for the valuation of asset retirement obligation ranged 2-5.2% in 2025, slightly lower in 2024 for the U.S. dollar, higher for the euro (expenses are estimated at current currency values with an inflation rate between 2% and 2.4%).

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

In upstream activities, in application of its internal procedures, Eni regularly reviews, on an asset-by-asset basis, the estimate of its future asset retirement costs, as well as the date at which work will be performed.

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

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

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16 Investments

Equity-accounted investments

| 2025 | 2024
(€ million) | Investments in unconsolidated entities controlled by Eni | Joint ventures | Associates | Total | Investments in unconsolidated entities controlled by Eni | Joint ventures | Associates | Total
Carrying amount - beginning of the year | 82 | 9,449 | 4,619 | 14,150 | 53 | 8,250 | 4,327 | 12,630
Additions and subscriptions | 21 | 399 | 175 | 595 | 35 | 450 | 242 | 727
Divestments and reimbursements |  | (84) | (20) | (104) | (2) | (291) | (33) | (326)
Share of profit of equity-accounted investments | 4 | 664 | 746 | 1,414 | 5 | 795 | 402 | 1,202
Share of loss of equity-accounted investments | (9) | (102) | (141) | (252) | (12) | (123) | (181) | (316)
Deduction for dividends | (1) | (573) | (938) | (1,512) | (3) | (655) | (1,094) | (1,752)
Changes in the scope of consolidation | (13) | 138 |  | 125 | 8 | 635 | 7 | 650
Currency translation differences | (1) | (940) | (478) | (1,419) |  | 461 | 206 | 667
Other changes | 9 | 65 | 84 | 158 | (2) | (73) | 743 | 668
Carrying amount - end of the year | 92 | 9,016 | 4,047 | 13,155 | 82 | 9,449 | 4,619 | 14,150

Acquisitions and share capital increases mainly related: (i) for €111 million the acquisition in the Plenitude business line of stakes in the two joint ventures 2024 Sol XV Llc (Plenitude 37.98%) and 2024 Sol XVI Llc (Plenitude 32.07%) owners of two operating photovoltaic plants and an electricity storage plant under construction in California (United States), with a total installed capacity of approximately 245 MW in Plenitude's share; (ii) for €108 million to the capital increase of QatarEnergy LNG NFE (5) (Eni’s interest 25%) which participates with a 12.5% stake in the North Field East (NFE) project, ensuring Eni a 3.125% stake in the Qatar megaproject for the development of LNG; (iii) the increase of a further 12% stake in E&E Algeria Touat BV (Eni's interest 66%) for €62 million; (iv) the acquisition of 2025 Bateria II Llc (Plenitude 33.92%) for €55 million; (v) for €45 million to the capital increase of LG-Eni BioRefining Co Ltd (Enilive 49%) engaged in the construction of a biorefining plant in South Korea; (vi) for €30 million to the capital increase of Vårgrønn AS, the joint venture (Plenitude 65%) which owns the 20% stake in the Doggerbank A, B and C offshore wind projects in the United Kingdom; (vii) for €29 million to the capital increase of Lotte Versalis Elastomers Co Ltd (Versalis 50%).

Divestments and reimbursements related for €83 million to the capital reimbursement by E&E Algeria Touat BV.

Share of profit from equity-accounted investments essentially referred to: (i) Vår Energi ASA for €602 million, which includes the excess of the dividend distributed over the net equity of the investee attributable to Eni; (ii) Azule Energy Holdings Ltd for €415 million; (iii) ADNOC Global Trading Ltd for €96 million; (iv) Saipem SpA for €71 million; (v) Cardón IV SA for €62 million.

Share of loss from equity-accounted investments essentially referred to: (i) St. Bernard Renewables Llc for €58 million; (ii) Vårgrønn AS for €35 million.

Reduction for dividends related to: (i) Vår Energi ASA for €653 million; (ii) Azule Energy Holdings Ltd for €386 million; (iii) Ithaca Energy Plc for €161 million; (iv) SeaCorridor Srl for €95 million; (v) Saipem SpA for 72 million; (vi) Abu Dhabi Oil Refining Company (TAKREER) for €56 million; (v) ADNOC Global Trading Ltd for €49 million.

The change in the scope of consolidation included €138 million of the initial recognition of the investment in the joint venture Eni CCUS Holding Ltd, following the business combination with GIP, resulting in Eni contributing to the venture the CCUS assets in the UK and the Netherlands. The book value of the newly established joint venture corresponds to the fair value of the interest of 49.99% acquired by the other shareholder. The venture will be accounted for using the equity method going forward.

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Net carrying amounts related to the following companies:

| December 31, 2025 | December 31, 2024
(€ million) | Net carrying amount | % of the investment | Net carrying amount | % of the investment
Investments in unconsolidated entities controlled by Eni |  |  |  |
Other | 92 |  | 82 |
| 92 |  | 82 |
Joint ventures |  |  |  |
Azule Energy Holdings Ltd | 4,634 | 50.00 | 5,211 | 50.00
E&E Algeria Touat BV | 671 | 66.00 | 646 | 54.00
St. Bernard Renewables Llc | 657 | 50.00 | 806 | 50.00
Saipem SpA | 581 | 21.80 | 528 | 21.61
SeaCorridor Srl | 411 | 50.10 | 485 | 50.10
Vårgrønn AS | 374 | 65.00 | 406 | 65.00
Cardón IV SA | 370 | 50.00 | 351 | 50.00
Mozambique Rovuma Venture SpA | 366 | 35.71 | 382 | 35.71
GreenIT SpA | 140 | 51.00 | 111 | 51.00
Eni CCUS Holding Ltd | 136 | 50.01 |  |
2023 Sol IX Llc | 131 | 73.62 | 149 | 73.59
Lotte Versalis Elastomers Co Ltd | 81 | 50.00 | 61 | 50.00
Mangistau Power BV | 75 | 51.00 | 51 | 51.00
2024 Sol XV Llc | 67 | 47.47 |  |
2022 Sol VII Llc | 53 | 75.24 | 61 | 75.26
2025 Bateria II Llc | 53 | 33.92 |  |
Hergo Renewables SpA | 35 | 65.00 | 33 | 65.00
Mangistau Renewables BV | 35 | 51.00 | 21 | 51.00
2024 Sol XVI Llc | 31 | 40.58 |  |
Società Oleodotti Meridionali SOM SpA | 13 | 70.00 | 18 | 70.00
LabAnalysis Environmental Scienze Srl |  |  | 26 | 30.00
Other | 102 |  | 103 |
| 9,016 |  | 9,449 |
Associates |  |  |  |
Abu Dhabi Oil Refining Company (Takreer) | 1,980 | 20.00 | 2,275 | 20.00
QatarEnergy LNG NFE (5) | 661 | 25.00 | 633 | 25.00
Ithaca Energy Plc | 486 | 35.92 | 725 | 37.17
ADNOC Global Trading Ltd | 192 | 20.00 | 165 | 20.00
Coral FLNG SA | 184 | 25.00 | 231 | 25.00
LG-Eni BioRefining Co Ltd | 93 | 49.00 | 56 | 49.00
United Gas Derivatives Co | 71 | 33.33 | 79 | 33.33
Novis Renewables Holdings Llc | 66 | 49.00 | 74 | 49.00
Bluebell Solar Class A Holdings II Llc | 62 | 99.00 | 72 | 99.00
LabAnalysis Environmental Scienze Srl | 26 | 30.00 |  |
Vår Energi ASA |  | 63.04 |  | 63.04
Other | 226 |  | 309 |
| 4,047 |  | 4,619 |
| 13,155 |  | 14,150 |

The carrying amount of Vår Energi ASA is equal to zero in relation to the application of the equity method of accounting owing to the reduction for the dividends distributed to shareholders.

The results of equity-accounted investments by segment are disclosed in note 35 – Segment information and information by geographical area.

As of December 31, 2025, the book and market values of Saipem SpA, Vår Energi ASA and Ithaca Energy Plc, listed equity-accounted companies, respectively, were as follows:

|  | Saipem SpA | Vår Energi ASA | Ithaca Energy Plc
Number of ordinary shares held |  | 422,920,192 | 1,573,713,749 | 594,048,748
% of the investment |  | 21.80 | 63.04 | 35.92
Share price | (€) | 2.425 | 2.787 | 1.899
Market value | (€ million) | 1,025 | 4,386 | 1,128
Book value | (€ million) | 581 |  | 486
Market value vs Book value | (€ million) | 444 | 4,386 | 642

Additional information is included in note 37 – Other information about investments.

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Other investments

(€ million) | 2025 | 2024
Carrying amount - beginning of the year | 1,395 | 1,256
Additions and subscriptions | 87 | 71
Change in the fair value with effect to OCI | (30) | 62
Currency translation differences | (108) | 56
Other changes | (15) | (50)
Carrying amount - end of the year | 1,329 | 1,395

The fair value of the main non-controlling interests in non-listed investees on regulated markets, classified within level 3 of the fair value hierarchy, was estimated based on a methodology that combines future expected earnings and the sum-of-the-parts methodology (so-called residual income approach) and takes into account, inter alia, the following inputs: (i) expected net profits, as a gauge of the future profitability of the investees, derived from the business plans, but adjusted, where appropriate, to include the assumptions that market participants would incorporate; (ii) the cost of capital, adjusted to include the risk premium of the specific country (6%) in which each investee operates. A stress test based on a 1% change in the cost of capital considered in the valuation did not produce significant changes at the fair value.

Dividend income from these investments is disclosed in note 32 – Income (expense) from investments.

Acquisitions and subscriptions include €50 million for the acquisition of a minority stake in BF International Best Fields Best Food Ltd (Eni’s interest 10.58%).

The investment book value as of December 31, 2025, primarily related to Nigeria LNG Ltd for €607 million (€690 million at December 31, 2024), Saudi European Petrochemical Co “IBN ZAHR” for €110 million (€127 million at December 31, 2024) and Darwin LNG Pty Ltd for €84 million (€96 million at December 31, 2024).

17 Other financial assets

| December 31, 2025 | December 31, 2024
(€ million) | Current | Non-current | Current | Non-current
Long-term financing receivables held for operating purposes | 1 | 910 | 1 | 1,044
| 1 | 910 | 1 | 1,044
Long-term financing receivables held for non-operating purposes | 3,067 | 136 | 44 | 2,109
Short-term financing receivables held for non-operating purposes | 642 |  | 1,040 |
| 3,709 | 136 | 1,084 | 2,109
| 3,710 | 1,046 | 1,085 | 3,153
Securities held for operating purposes |  | 63 |  | 62
Total net of impairment provisions | 3,710 | 1,109 | 1,085 | 3,215

Changes in allowance for doubtful accounts were as follows:

(€ million) | 2025 | 2024
Carrying amount at the beginning of the year | 427 | 383
Additions | 1 | 26
Deductions | (2) | (3)
Currency translation differences | (47) | 24
Other changes | (2) | (3)
Carrying amount at the end of the year | 377 | 427

Financing receivables held for operating purposes primarily related to loans provided to joint ventures and associates in the Exploration & Production segment (€741 million) to execute capital projects of interest to Eni. These receivables are long-term interests in the initiatives funded. The main amounts were towards Coral FLNG SA (Eni’s interest 25%) for €417 million (€522 million at December 31, 2024), operating a floating gas liquefaction plant in Area 4, offshore Mozambique.

Financing receivables held for operating purposes due beyond five years amounted to €90 million (€214 million at December 31, 2024).

The fair value of non-current financing receivables held for operating purposes of €910 million has been estimated based on the present value of expected future cash flows discounted at rates ranging from 1.9% to 4.8% (1.7% and 4.8% at December 31, 2024).

The recoverability of other long-term financial assets was assessed by considering the expected probability of default in the next twelve months only, as creditworthiness suffered no significant deterioration in the reporting period.

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Financing receivables held for non-operating purposes related to: (i) the joint venture Mozambique Rovuma Venture SpA (Eni’s interest 35.71%) for €2,318 million (€1,769 million at December 31, 2024) engaged in production and development of natural gas reserves in the Coral discovery prospect offshore, located in the subarea of exclusive exploitation of the concessionaires of the larger Area 4. This receivable is not part of the long-term interest in the upstream initiative; (ii) €710 million of receivables from co-ventures arising from the reallocation of working interest in ongoing development projects in Area 4 offshore Mozambique; (iii) restricted deposits in escrow to guarantee transactions on derivative contracts for €495 million (€937 million at December 31, 2024), referred to the Global Gas & LNG Portfolio business line for €463 million (€907 million at December 31, 2024).

Financing receivables were denominated in U.S. dollar for €4,325 million and in euro for €307 million (€3,351 million and €855 million at December 31, 2024, respectively).

Securities for €18 million (€11 million at December 31, 2024) were pledged as guarantee of the deposit for gas cylinders as provided for by the Italian law.

The following table analyses securities per issuing entity:

| Amortized cost (€ million) | Nominal value (€ million) | Fair Value (€ million) | Nominal rate of return (%) | Maturity date | Rating - Moody's | Rating - S&P
Sovereign states |  |  |  |  |  |  |
Fixed rate bonds |  |  |  |  |  |  |
Italy | 18 | 18 | 17 | from 0 to 3.6 | from 2026 to 2035 | Baa2 | BBB+
Others (*) | 31 | 31 | 31 | from 0 to 5.0 | from 2026 to 2030 | from Aa1 to Baa2 | from AA+ to BBB-
Floating rate bonds |  |  |  |  |  |  |
Italy | 11 | 11 | 11 | from 2.6 to 2.9 | from 2026 to 2029 | Baa2 | BBB+
Total sovereign states | 60 | 60 | 59 |  |  |  |
Other financial institutions |  |  |  |  |  |  |
European Bank of Investments | 3 | 3 | 3 | 3.75 | 2026 | Aaa | AAA
Total | 63 | 63 | 62 |  |  |  |

(*) Amounts included herein are lower than €10 million.

Securities having maturity within five years amounted to €49 million.

The fair value of securities was derived from quoted market prices.

Receivables with related parties are described in note 36 – Transactions with related parties.

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18 Trade and other payables

(€ million) | December 31, 2025 | December 31, 2024
Trade payables | 13,901 | 15,170
Down payments and advances from joint ventures in exploration & production activities | 714 | 767
Payables for purchase of non-current assets | 1,666 | 1,939
Payables due to partners in exploration & production activities | 1,114 | 1,377
Other payables | 2,866 | 2,839
| 20,261 | 22,092

The decrease in trade payables of €1,269 million referred to Global Gas & LNG Portfolio business line for €1,929 million following lower gas purchases and, on the increase, to the Enilive business line for €374 million.

Trade payables include debts under credit letters with payment terms aligned with commercial ones and with fixed commissions.

Other payables included: (i) payables to factoring companies in relation to the derecognition of Eni's tax credits for €1,322 million (€1,129 million at December 31, 2024); (ii) payroll payables for €260 million (€268 million at December 31, 2024); (iii) payables for social security contributions for €124 million (€120 million at December 31, 2024).

Trade and other payables were denominated in euro for €10,937 million and in U.S. dollar for €8,994 million (€11,487 million and €10,047 million at December 31, 2024, respectively), with a carrying amount substantially aligned with fair value.

Trade and other payables due to related parties are described in note 36 – Transactions with related parties.

19 Finance debt

| December 31, 2025 | December 31, 2024
(€ million) | Short-term debt | Current portion of long-term debt | Long-term debt | Total | Short-term debt | Current portion of long-term debt | Long-term debt | Total
Banks | 3,394 | 330 | 1,268 | 4,992 | 2,941 | 269 | 921 | 4,131
Ordinary bonds |  | 2,320 | 17,855 | 20,175 |  | 2,695 | 19,641 | 22,336
Sustainability-linked convertible bonds |  | 9 | 939 | 948 |  | 9 | 928 | 937
Other financial institutions | 1,535 | 775 | 77 | 2,387 | 1,297 | 1,609 | 80 | 2,986
| 4,929 | 3,434 | 20,139 | 28,502 | 4,238 | 4,582 | 21,570 | 30,390

Finance debt decreased by €1,888 million as disclosed in table “Changes in liabilities arising from financing activities” detailed at the end of this paragraph.

As of December 31, 2025, finance debt included €200 million (€300 million at December 31, 2024) of sustainability-linked financial contracts with leading banking institutions which provide for an adjustment of the funding cost linked to the achievement of certain sustainability targets, which are disclosed in the comment of ordinary bonds.

Other financial institutions included supplier finance arrangements (SFAs) as follows:

(€ million) | Long-term SFAs | Current SFAs and current portion of long-term SFAs | Total
Carrying amount at December 31, 2024 | 26 | 2,542 | 2,568
Cash flows |  | (2,249) | (2,249)
Non-monetary increases | 12 | 1,430 | 1,442
Currency translation differences |  | (174) | (174)
Other non-monetary changes | (18) | 16 | (2)
Carrying amount at December 31, 2025 | 20 | 1,565 | 1,585
Carrying amount at December 31, 2023 | 92 | 893 | 985
Cash flows |  | (844) | (844)
Non-monetary increases | 451 | 1,788 | 2,239
Currency translation differences | 2 | 92 | 94
Other non-monetary changes | (519) | 613 | 94
Carrying amount at December 31, 2024 | 26 | 2,542 | 2,568

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The payment terms for financial liabilities falling within the scope of the SFAs range between 145 and 450 days, compared to the terms of other comparable commercial debt not falling within the scope of the agreement which are between 30 and 60 days. Eni formally has no information on the timing of the settlement made by the bank to the suppliers. The main transactions falling within the scope of the SFA agreements mainly concern: (i) within the Congo project, the construction of the floating LNG production vessel Nguya, which entered into service at the end of 2025 allowing the liquefaction capacity of the project to be increased up to 3 MTPA from the current 0.6 MTPA; (ii) EPC contracts for plant reconversion, laying of submarine lines and contracts for transportation and installation of subsea lines and cables; (iii) production facilities offshore Mexico (Area 1); (iv) the contract for transportation and installation of pipelines and umbilicals and subsea production system for the Baleine Phase II project offshore Ivory Coast.

Eni entered into long-term borrowing facilities with the European Investment Bank. These borrowing facilities are subject to the retention of a minimum level of credit rating. According to the agreements, should the Company lose the minimum credit rating, new guarantees could be required to be agreed upon with the European Investment Bank. As of December 31, 2025, debts subjected to restrictive covenants amounted to €981 million (€613 million at December 31, 2024). Eni was in compliance with those covenants.

Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which €12.8 billion were drawn as of December 31, 2025.

The following table provides a breakdown of ordinary bonds by issuing entity, maturity date, interest rate and currency as of December 31, 2025:

(€ million) | Amount | Discount on bond issue and accrued expense | Total | Currency | Maturity | Rate (%)
Issuing entity |  |  |  |  |  |
Euro Medium Term Notes |  |  |  |  |  |
Eni SpA | 1,250 | 24 | 1,274 | EUR | 2033 | 4.250
Eni SpA | 1,000 | 49 | 1,049 | EUR | 2029 | 3.625
Eni SpA | 1,000 | 26 | 1,026 | EUR | 2034 | 3.875
Eni SpA | 1,000 | 14 | 1,014 | EUR | 2026 | 1.500
Eni SpA | 1,000 | 11 | 1,011 | EUR | 2031 | 2.000
Eni SpA | 1,000 | 7 | 1,007 | EUR | 2026 | 1.250
Eni SpA | 1,000 | 4 | 1,004 | EUR | 2030 | 0.625
Eni SpA | 800 | 5 | 805 | EUR | 2028 | 1.625
Eni SpA | 750 | 10 | 760 | EUR | 2027 | 1.500
Eni SpA | 750 | (2) | 748 | EUR | 2034 | 1.000
Eni SpA | 638 | 8 | 646 | USD | 2027 | variable
Eni SpA | 600 |  | 600 | EUR | 2028 | 1.125
Eni SpA | 100 | 4 | 104 | EUR | 2028 | 5.441
Eni SpA | 75 |  | 75 | EUR | 2043 | 3.875
Eni SpA | 70 | 1 | 71 | EUR | 2032 | 4.000
Eni SpA | 50 |  | 50 | EUR | 2031 | 4.800
Eni SpA - Sustainability-linked | 1,000 |  | 1,000 | EUR | 2028 | 0.375
Eni SpA - Sustainability-linked | 750 | 16 | 766 | EUR | 2027 | 3.625
| 12,833 | 177 | 13,010 |  |  |
Other bonds |  |  |  |  |  |
Eni SpA | 1,063 | (21) | 1,042 | USD | 2054 | 5.950
Eni SpA | 851 | 8 | 859 | USD | 2028 | 4.750
Eni SpA | 851 | 2 | 853 | USD | 2029 | 4.250
Eni SpA | 851 | 7 | 858 | USD | 2034 | 5.500
Eni SpA | 851 | (7) | 844 | USD | 2035 | 5.750
Eni SpA | 298 | 1 | 299 | USD | 2040 | 5.700
Eni USA Inc | 340 | 3 | 343 | USD | 2027 | 7.300
Eni SpA - Sustainability-linked - Retail | 2,000 | 67 | 2,067 | EUR | 2028 | 4.300
| 7,105 | 60 | 7,165 |  |  |
| 19,938 | 237 | 20,175 |  |  |

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During 2025, new ordinary bonds in euro were issued by Eni SpA for a nominal value of €851 million.

As of December 31, 2025, Eni SpA had in place sustainability-linked bonds for a total nominal value of €3,750 million. In case the Company misses those targets, a step-up mechanism will be applied, providing for a marginal increase in the interest rate.

As of December 31, 2025, nominal value of ordinary bonds maturing within 18 months amounted to €3,500 million.

Information relating to the senior unsecured sustainability-linked convertible bonds is as follows:

(€ million) | Amount | Discount on bond issue and accrued expense | Total | Currency | Maturity | Rate (%)
Issuing entity |  |  |  |  |  |
Eni SpA - Convertible senior unsecured sustainability-linked bonds | 1,000 | 27 | 1,027 | EUR | 2030 | 2.950
of which financial liabilities | 920 | 28 | 948 | EUR |  |
of which equity | 80 | (1) | 79 | EUR |  |

As of December 31, 2025, Eni SpA had in place a sustainability-linked senior unsecured convertible bond with an aggregate nominal amount of €1,000 million. The bonds will be convertible into Eni existing ordinary shares bought under the share buyback program approved by the Shareholders’ Meeting held on May 10, 2023. The bonds will mature in 7 years. The conversion price is €17.5513.

Sustainability-linked bonds and sustainability-linked convertible bonds are indexed to the achievement of sustainability targets related to the Net Carbon Footprint of the Upstream (Scope 1 and 2) and renewable energy installed capacity. In case the Company fails to reach each of the agreed targets, a step-up adjustment to the interest rates of the underlying financing is due to be applied.

The following table provides a breakdown by currency of finance debt and the related weighted average interest rates:

| December 31, 2025 | December 31, 2024
| Short-term debt (€ million) | Weighted average rate (%) | Long-term debt and current portion of long-term debt (€ million) | Weighted average rate (%) | Short-term debt (€ million) | Weighted average rate (%) | Long-term debt and current portion of long-term debt (€ million) | Weighted average rate (%)
Euro | 4,449 | 2.1 | 16,959 | 2.5 | 3,518 | 3.0 | 19,547 | 2.5
U.S. dollar | 437 | 3.0 | 6,612 | 4.9 | 707 | 4.8 | 6,603 | 5.3
Other currencies | 43 | 1.7 | 2 | 2.7 | 13 | 2.2 | 2 | 2.7
| 4,929 |  | 23,573 |  | 4,238 |  | 26,152 |

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As of December 31, 2025, Eni retained committed borrowing facilities of €9,012 million (€9,001 million at December 31, 2024), of which €9,000 undrawn. Those facilities bore interest rates reflecting prevailing conditions in the marketplace.

As of December 31, 2025, Eni was in compliance with covenants and other contractual provisions in relation to borrowing facilities.

Fair value of long-term debt, including the current portion of long-term debt is described below:

(€ million) | December 31, 2025 | December 31, 2024
Ordinary bonds and sustainability-linked bonds | 20,119 | 21,026
Convertible sustainability-linked bonds | 1,071 | 973
Banks | 1,608 | 1,143
Other financial institutions | 852 | 1,689
| 23,650 | 24,831

Fair value of finance debts was calculated by discounting the expected future cash flows at discount rates ranging from 1.9% to 4.8% (1.7% and 4.8% at December 31, 2024).

Because of the short-term maturity and conditions of remuneration of short-term debt, the fair value approximated the carrying amount.

Changes in liabilities arising from financing activities

(€ million) | Long-term debt and current portion of long-term debt | Short-term debt | Long-term and current portion of long-term lease liabilities | Total
Carrying amount at December 31, 2024 | 26,152 | 4,238 | 6,453 | 36,843
Cash flows | (2,279) | (276) | (1,250) | (3,805)
Currency translation differences | (586) | 201 | (484) | (869)
Changes in the scope of consolidation | 470 | 4 |  | 474
Other non-monetary changes | (184) | 762 | 981 | 1,559
Carrying amount at December 31, 2025 | 23,573 | 4,929 | 5,700 | 34,202
Carrying amount at December 31, 2023 | 24,637 | 4,092 | 5,336 | 34,065
Cash flows | (1,232) | (61) | (1,205) | (2,498)
Currency translation differences | 232 | (303) | 247 | 176
Changes in the scope of consolidation | 855 | 12 | 50 | 917
Other non-monetary changes | 1,660 | 498 | 2,025 | 4,183
Carrying amount at December 31, 2024 | 26,152 | 4,238 | 6,453 | 36,843

Changes in the scope of consolidation related to the acquisition of Plenitude Production France SAS for €762 million and the loss of control of Eni CCUS Holding Ltd for €298 million.

Other non-monetary changes include €1,442 million of trade payables on which payment term extensions have been negotiated, resulting in the classification of the debt as financial, lease liabilities assumptions for €1,150 million and, as a decrease, €762 the reclassification to assets held for sale of Plenitude Production France SAS.

Lease liabilities are described in note 13 – Right-of-use assets and lease liabilities.

Transactions with related parties are described in note 36 – Transactions with related parties.

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20 Information on net borrowings

(€ million) | December 31, 2025 | December 31, 2024
A. | Cash | 2,796 | 3,367
B. | Cash equivalents | 5,304 | 4,816
C. | Other current financial assets | 10,700 | 7,881
D. | Liquidity (A+B+C) | 18,800 | 16,064
E. | Current financial debt | 7,258 | 6,942
F. | Current portion of non-current financial debt | 2,368 | 3,157
G. | Current financial indebtedness (E+F) | 9,626 | 10,099
H. | Net current financial indebtedness (G-D) | (9,174) | (5,965)
I. | Non-current financial debt | 5,782 | 6,175
J. | Debt instruments | 18,756 | 20,527
K. | Non‐current trade and other payables |  |
L. | Non-current financial indebtedness (I+J+K) | 24,538 | 26,702
M. | Total financial indebtedness (H+L) | 15,364 | 20,737

Net borrowings did not include €136 million of non-current financing receivables (€2,109 million at December 31, 2024).

Other current financial assets include: (i) financial assets at fair value through profit or loss, disclosed in note 7 – Financial assets at fair value through profit or loss; (ii) financing receivables, disclosed in note 17 – Other financial assets.

Current and non-current debts are disclosed in note 19 – Finance debts.

Debt instruments included €38 million (€42 million at December 31, 2024) of positive fair value hedge derivative contracts entered to hedge fixed rate bonds.

Current portion of non-current financial debt and non-current financial debt include lease liabilities of €1,263 million and €4,437 million (€1,279 million and €5,174 million at December 31, 2024, respectively). More information on lease liabilities is reported in note 13 – Right-of-use assets and lease liabilities.

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21 Provisions

(€ million) | Provisions for site restoration, abandonment and social projects | Environmental provisions | Provisions for litigations | Provisions for taxes other than income taxes | Loss adjustments and actuarial provisions for Eni's insurance companies | Provisions for losses on investments | Provisions for EVEREN insurance coverage | Other | Total
Carrying amount at December 31, 2024 | 9,712 | 3,700 | 594 | 158 | 229 | 234 | 86 | 1,061 | 15,774
New or increased provisions | 135 | 641 | 353 | 19 | 89 | 6 | 23 | 404 | 1,670
Initial recognition and changes in estimates | 279 |  |  |  |  |  |  |  | 279
Accretion discount | 290 | (40) |  |  |  |  |  |  | 250
Reversal of utilized provisions | (824) | (671) | (175) | (18) | (132) |  | (1) | (135) | (1,956)
Reversal of unutilized provisions | (144) | (42) | (85) |  |  | (5) | (1) | (238) | (515)
Currency translation differences | (554) | (4) | (36) | (8) |  | (5) | (1) | (17) | (625)
Other changes | (272) | (42) | 26 | 22 | 2 | 7 | (7) | (33) | (297)
Carrying amount at December 31, 2025 | 8,622 | 3,542 | 677 | 173 | 188 | 237 | 99 | 1,042 | 14,580

Provisions for site restoration, abandonment and social projects mainly comprised: (i) for €7,557 million the present value of the estimated costs that the Company expects to incur for dismantling oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, site clean-up and environmental restoration; (ii) for €507 million the estimated costs for social projects in the Exploration & Production segment, relating for €230 million to the estimated costs for social projects as part of the commitments between Eni SpA and the Basilicata region in relation to the oil development program in the Val d’Agri concession area; (iii) for €442 million the estimate for decommissioning and dismantling costs of refining plants for which there are no prospects of economic reuse or reconversion into transition processes, in the current market context, as well as fuel distribution outlets.

In 2025, increases in the decommissioning provisions related to: (i) the revision of cost estimates relating to depleted oil & gas assets, whose book value has been completely written-down for €79 million; (ii) cost estimates for dismantling and removing refining plants and fuel distribution for €55 million for which management has assessed the absence of economic prospectives in the current market context. Reversal of unutilized provisions mainly concerned a downstream plant in Italy for which negotiations are underway for the sale to third parties.

Initial recognition and changes in cost estimates include the updated estimates of site decommissioning and restoration costs (primarily in Italy and Algeria) partly offset by an increased yield curve for the euro. The effect of the accretion of discount recognized through profit and loss was determined based on discount rates ranging from 1.7% to 5.6% (from 1.8% to 5.3% at December 31, 2024). Utilizations of the decommissioning provision mainly related to advance in decommissioning activities in Italy for €253 million, in the United Kingdom for €243 million and in Libya for €111 million. Other changes included the reclassification to liabilities directly associated with assets held for sale of the Exploration & Production segment for €231 million. Main expenditures associated with decommissioning operations are expected to be incurred over a fifty-year period, with utilizations essentially starting after 12 months. Further information on the uncertainty relating to the estimation of the times of dismantling and restoration of hydrocarbon extraction plants is reported in note 15 - Impairments of tangible and intangible assets and right-of-use assets. Sensitivity of outcomes to decarbonization scenarios.

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Provisions for environmental risks included the estimated costs for environmental clean-up and remediation of soil and groundwater in areas owned or under concession where the Group performed in the past industrial operations that were progressively divested, shut down, dismantled or restructured. The provision was accrued because at the balance sheet date there is a legal or constructive obligation for Eni to carry out environmental clean-up and remediation and the expected costs can be estimated reliably. The provision included the expected charges associated with strict liability related to obligations of cleaning up and remediating polluted areas that met the parameters set by law at the time when the pollution occurred but to date are no more in compliance with current environmental laws and regulations, or because Eni assumed the liability borne by other operators at the time of acquisition or otherwise took over the site operations. The prerequisite for the recognition of these environmental costs is the evaluation of the probability of their being incurred and the possibility of estimating them reliably. Provisions related: (i) for €294 million to remediation activities at brownfield sites in Italy and costs related to groundwater cleanups; (ii) for €191 million to refining plants, storage sites, fuel distribution outlets and oil pipelines; (iii) for €78 million to remediation activities at petrochemical plants. Reversal of utilized provisions related to the progress of environmental remediation and restoration operations. At December 31, 2025, environmental provisions related to Eni Rewind SpA for €2,251 million and to the Refining and Chemical segment for €750 million.

Litigation provisions comprised expected liabilities associated with legal proceedings and other matters arising from contractual claims, including arbitrations, fines and penalties due to antitrust proceedings and administrative matters. The provision was allocated on the basis of the best estimate of the existing liability at the balance sheet date and referred to the Exploration & Production segment for €282 million. The provision also included the estimate provisions in certain antitrust proceedings.

Provisions for uncertain tax matters related to the estimated losses that the Company expects to incur to settle tax litigations and tax claims pending with tax authorities in relation to uncertainties in applying rules in force and referred to the Exploration & Production segment for €142 million. In particular, charges mainly relate to the dispute regarding the taxation of Italian local administrations on Eni offshore platforms located in common territorial waters.

Loss adjustments and actuarial provisions of Eni’s insurance company Eni Insurance SpA represented the estimated liabilities accrued on the basis for third party claims. Against such liability were recorded receivables for €34 million towards insurance companies for reinsurance contracts.

Provisions for losses on investments included provisions relating to investments whose loss exceeds equity and primarily related to Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation) for €176 million.

Provisions for the Everen insurance coverage included insurance premiums which will be charged to Eni in the next five years by the mutual insurance company in which Eni participates together with other oil companies.

Other provisions mainly related to claims, contingencies and commercial renegotiations as part of the ordinary course of the business. Those provisions were outstanding mainly in the Global Gas & LNG Portfolio and Enilive business lines.

Based on the outlay forecasts in relation to the progress of the restoration and decommissioning activities of depleted oil assets, the short-term portion of the risk provisions amounts to approximately €1.7 billion.

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22 Provisions for employee benefits

(€ million) | December 31, 2025 | December 31, 2024
Italian defined benefit plans | 143 | 151
Foreign defined benefit plans | 89 | 108
FISDE, foreign medical plans and other | 112 | 112
Defined benefit plans | 344 | 371
Other benefit plans | 252 | 310
Provision for employee benefits | 596 | 681

The liability relating to Eni's commitment to cover the healthcare costs of personnel is determined, among other things, based on the contributions paid by the Company.

Other employee benefit plans related to deferred monetary incentive plans for €139 million (€134 million at December 31, 2024), expansion contracts for €51 million (€86 million at December 31, 2024), isopensione plans (a post-retirement benefit plan applicable to a specific category of employees) of Eni Plenitude SpA for €28 million (€47 million at December 31, 2024), Jubilee Awards for €18 million (€25 million at December 31, 2024) and other long-term plans for €16 million (€18 million at December 31, 2024).

Present value of employee benefits, estimated by applying actuarial techniques, consisted of the following:

| 2025 | 2024
(€ million) | Italian defined benefit plans | Foreign defined benefit plans | FISDE, foreign medical plans and other | Defined benefit plans | Other benefit plans | Total | Italian defined benefit plans | Foreign defined benefit plans | FISDE, foreign medical plans and other | Defined benefit plans | Other benefit plans | Total
Present value of benefit liabilities at beginning of year | 151 | 369 | 112 | 632 | 310 | 942 | 156 | 380 | 118 | 654 | 353 | 1,007
Current service cost | 1 | 6 | 2 | 9 | 57 | 66 | 1 | 12 | 2 | 15 | 56 | 71
Interest cost | 5 | 17 | 3 | 25 | 8 | 33 | 5 | 18 | 4 | 27 | 11 | 38
Remeasurements: | (4) | 7 | (2) | 1 | (8) | (7) | (1) | (22) | (2) | (25) | 1 | (24)
- actuarial (gains) losses due to changes in demographic assumptions |  | (7) |  | (7) |  | (7) |  | (1) |  | (1) |  | (1)
- actuarial (gains) losses due to changes in financial assumptions | (1) |  | (1) | (2) | (3) | (5) |  | (22) |  | (22) | 5 | (17)
- experience (gains) losses | (3) | 14 | (1) | 10 | (5) | 5 | (1) | 1 | (2) | (2) | (4) | (6)
Past service cost and (gain) loss on settlements |  | 1 | 5 | 6 | (9) | (3) |  | 9 |  | 9 | 3 | 12
Plan contributions: |  | 1 |  | 1 |  | 1 |  | 2 |  | 2 |  | 2
- employee contributions |  | 1 |  | 1 |  | 1 |  | 2 |  | 2 |  | 2
Benefits paid | (11) | (31) | (8) | (50) | (105) | (155) | (10) | (85) | (8) | (103) | (113) | (216)
Reclassification to liabilities directly associated with assets held for sale |  | (16) |  | (16) | (1) | (17) |  |  |  |  |  |
Currency translation differences and other changes | 1 | (7) |  | (6) |  | (6) |  | 55 | (2) | 53 | (1) | 52
Present value of benefit liabilities at end of year (a) | 143 | 347 | 112 | 602 | 252 | 854 | 151 | 369 | 112 | 632 | 310 | 942
Plan assets at beginning of year |  | 263 |  | 263 |  | 263 |  | 261 |  | 261 |  | 261
Interest income |  | 18 |  | 18 |  | 18 |  | 14 |  | 14 |  | 14
Return on plan assets |  | (8) |  | (8) |  | (8) |  | (17) |  | (17) |  | (17)
Administrative fees paid |  | (1) |  | (1) |  | (1) |  | (1) |  | (1) |  | (1)
Plan contributions: |  | 21 |  | 21 |  | 21 |  | 25 |  | 25 |  | 25
- employee contributions |  | 1 |  | 1 |  | 1 |  | 2 |  | 2 |  | 2
- employer contributions |  | 20 |  | 20 |  | 20 |  | 23 |  | 23 |  | 23
Benefits paid |  | (24) |  | (24) |  | (24) |  | (25) |  | (25) |  | (25)
Reclassification to liabilities directly associated with assets held for sale |  | (1) |  | (1) |  | (1) |  |  |  |  |  |
Currency translation differences and other changes |  | (8) |  | (8) |  | (8) |  | 6 |  | 6 |  | 6
Plan assets at end of year (b) |  | 260 |  | 260 |  | 260 |  | 263 |  | 263 |  | 263
Asset ceiling at beginning of year |  | 2 |  | 2 |  | 2 |  | 2 |  | 2 |  | 2
Change in asset ceiling |  |  |  |  |  |  |  |  |  |  |  |
Asset ceiling at end of year (c) |  | 2 |  | 2 |  | 2 |  | 2 |  | 2 |  | 2
Net liability recognized at end of year (a-b+c) | 143 | 89 | 112 | 344 | 252 | 596 | 151 | 108 | 112 | 371 | 310 | 681

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Costs charged to the profit and loss account, valued using actuarial assumptions, consisted of the following:

(€ million) | Italian defined benefit plans | Foreign defined benefit plans | FISDE, foreign medical plans and other | Defined benefit plans | Other benefit plans | Total
2025 |  |  |  |  |  |
Current service cost | 1 | 6 | 2 | 9 | 57 | 66
Past service cost and (gains) losses on settlements |  | 1 | 5 | 6 | (9) | (3)
Interest cost (income), net: |  |  |  |  |  |
- interest cost on liabilities | 5 | 17 | 3 | 25 | 8 | 33
- interest income on plan assets |  | (18) |  | (18) |  | (18)
Total interest cost (income), net | 5 | (1) | 3 | 7 | 8 | 15
- of which recognized in Payroll and related cost |  |  |  |  | 8 | 8
- of which recognized in Financial income (expense) | 5 | (1) | 3 | 7 |  | 7
Remeasurements for long-term plans |  |  |  |  | (8) | (8)
Administrative fees paid |  | 1 |  | 1 |  | 1
Total | 6 | 7 | 10 | 23 | 48 | 71
- of which recognized in Payroll and related cost | 1 | 8 | 7 | 16 | 48 | 64
- of which recognized in Financial income (expense) | 5 | (1) | 3 | 7 |  | 7
2024 |  |  |  |  |  |
Current service cost | 1 | 12 | 2 | 15 | 56 | 71
Past service cost and (gains) losses on settlements |  | 9 |  | 9 | 3 | 12
Interest cost (income), net: |  |  |  |  |  |
- interest cost on liabilities | 5 | 18 | 4 | 27 | 11 | 38
- interest income on plan assets |  | (14) |  | (14) |  | (14)
Total interest cost (income), net | 5 | 4 | 4 | 13 | 11 | 24
- of which recognized in Payroll and related cost |  |  |  |  | 11 | 11
- of which recognized in Financial income (expense) | 5 | 4 | 4 | 13 |  | 13
Remeasurements for long-term plans |  |  |  |  | 1 | 1
Administrative fees paid |  | 1 |  | 1 |  | 1
Total | 6 | 26 | 6 | 38 | 71 | 109
- of which recognized in Payroll and related cost | 1 | 22 | 2 | 25 | 71 | 96
- of which recognized in Financial income (expense) | 5 | 4 | 4 | 13 |  | 13

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Costs of defined benefit plans recognized in other comprehensive income consisted of the following:

| 2025 | 2024
(€ million) | Italian defined benefit plans | Foreign defined benefit plans | FISDE, foreign medical plans and other | Total | Italian defined benefit plans | Foreign defined benefit plans | FISDE, foreign medical plans and other | Total
Actuarial (gain)/loss due to changes in demographic assumptions |  | (7) |  | (7) |  | (1) |  | (1)
Actuarial (gain)/loss due to changes in financial assumptions | (1) |  | (1) | (2) |  | (22) |  | (22)
Experience (gain)/loss | (3) | 14 | (1) | 10 | (1) | 1 | (2) | (2)
Return on plan assets |  | 8 |  | 8 |  | 17 |  | 17
Changes in asset ceiling |  |  |  |  |  |  |  |
Remeasurements | (4) | 15 | (2) | 9 | (1) | (5) | (2) | (8)

Plan assets consisted of the following:

(€ million) | Cash and cash equivalents | Equity securities | Debt securities | Real estate | Derivatives | Investment funds | Assets held by insurance companies | Other | Total
December 31, 2025 |  |  |  |  |  |  |  |  |
Plan assets with a quoted market price: |  |  |  |  |  |  |  |  |
- with a quoted market price | 9 | 24 | 126 | 11 | 41 |  | 4 | 15 | 230
- without a quoted market price |  |  |  |  |  |  | 30 |  | 30
| 9 | 24 | 126 | 11 | 41 |  | 34 | 15 | 260
December 31, 2024 |  |  |  |  |  |  |  |  |
Plan assets with a quoted market price: |  |  |  |  |  |  |  |  |
- with a quoted market price | 4 | 25 | 125 | 11 | 43 | 1 | 32 | 19 | 260
- without a quoted market price |  |  |  |  |  |  | 3 |  | 3
| 4 | 25 | 125 | 11 | 43 | 1 | 35 | 19 | 263

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The main actuarial assumptions used in the measurement of the liabilities at year-end and in the estimate of costs expected for the following year consisted of:

|  | Italian defined benefit plans | Foreign defined benefit plans | FISDE, foreign medical plans and other | Other benefit plans
2025 |  |  |  |  |  |  |  |  |
Discount rate | (%) | 3.2 | 1.3 | - | 20.5 | 3.2 | 2.4 | - | 3.2
Rate of compensation increase | (%) | 3.0 | 2.0 | - | 19.7 |  |  |  |
Rate of price inflation | (%) | 2.0 | 1.0 | - | 14.0 | 2.0 |  |  | 2.0
Life expectations on retirement at age 65 | (years) |  | 14 | - | 24 | 24 |  |  |
2024 |  |  |  |  |  |  |  |  |
Discount rate | (%) | 3.1 | 1.1 | - | 26.1 | 3.1 | 2.8 | - | 3.1
Rate of compensation increase | (%) | 3.0 | 2.0 | - | 15.0 |  |  |  |
Rate of price inflation | (%) | 2.0 | 1.0 | - | 14.0 | 2.0 |  |  | 2.0
Life expectations on retirement at age 65 | (years) |  | 14 | - | 24 | 24 |  |  |

The following is an analysis by geographical area related to the main actuarial assumptions used in the valuation of the principal foreign defined benefit plans:

|  | Euro area | Rest of Europe | Africa | Other areas | Foreign defined benefit plans
2025 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Discount rate | (%) | 3.4 | - | 4.2 | 1.3 | - | 5.5 | 4.0 | - | 20.5 |  | 1.3 | - | 20.5
Rate of compensation increase | (%) | 2.0 | - | 3.4 |  |  | 2.8 | 5.0 | - | 19.7 |  | 2.0 | - | 19.7
Rate of price inflation | (%) |  |  | 2.0 | 1.0 | - | 3.1 | 3.0 | - | 14.0 |  | 1.0 | - | 14.0
Life expectations on retirement at age 65 | (years) | 21 | - | 23 | 22 | - | 24 | 14 | - | 18 |  | 14 | - | 24
2024 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Discount rate | (%) | 3.2 | - | 3.6 | 1.1 | - | 5.5 | 3.3 | - | 26.1 | 7.1 | 1.1 | - | 26.1
Rate of compensation increase | (%) | 2.0 | - | 3.4 |  |  | 2.8 | 5.0 | - | 15.0 | 5.0 | 2.0 | - | 15.0
Rate of price inflation | (%) |  |  | 2.0 | 1.0 | - | 3.5 | 3.0 | - | 14.0 | 3.5 | 1.0 | - | 14.0
Life expectations on retirement at age 65 | (years) | 21 | - | 23 | 23 | - | 24 | 14 | - | 18 |  | 14 | - | 24

The effects of a possible change in the main actuarial assumptions at the end of the year are not material.

The contributions expected to be paid for employee benefit plans in the next year amounted to €130 million, of which €40 million related to defined benefit plans.

The following is an analysis by maturity date of the liabilities for employee benefit plans and their relative weighted-average duration:

(€ million) |  | Italian defined benefit plans | Foreign defined benefit plans | FISDE, foreign medical plans and other | Other benefit plans
December 31, 2025 |  |  |  |  |
2026 |  | 18 | 17 | 8 | 90
2027 |  | 16 | 25 | 8 | 79
2028 |  | 17 | 19 | 8 | 64
2029 |  | 18 | 21 | 7 | 5
2030 |  | 18 | 20 | 7 | 3
2031 and thereafter |  | 56 | 245 | 74 | 11
Weighted average duration (years) |  | 5.8 | 12.4 | 10.9 | 2.1
December 31, 2024 |  |  |  |  |
2025 |  | 19 | 24 | 8 | 108
2026 |  | 16 | 26 | 7 | 92
2027 |  | 16 | 21 | 7 | 80
2028 |  | 17 | 16 | 7 | 13
2029 |  | 18 | 19 | 7 | 5
2030 and thereafter |  | 65 | 263 | 76 | 12
Weighted average duration (years) |  | 6.1 | 13.1 | 11.3 | 2.1

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23 Deferred tax assets and liabilities

(€ million) | December 31, 2025 | December 31, 2024
Deferred tax liabilities before offsetting | 6,937 | 8,724
Deferred tax assets available for offset | (2,132) | (3,143)
Deferred tax liabilities | 4,805 | 5,581
Deferred tax assets before offsetting (net of accumulated write-down provisions) | 8,848 | 9,465
Deferred tax liabilities available for offset | (2,132) | (3,143)
Deferred tax assets | 6,716 | 6,322

The most significant temporary differences giving rise to net deferred tax assets and liabilities are disclosed below:

(€ million) | December 31, 2025 | December 31, 2024
Deferred tax liabilities |  |
Accelerated tax depreciation | 4,875 | 5,755
Leasing | 297 | 354
Site restoration and abandonment (tangible assets) | 269 | 368
Difference between the fair value and the carrying amount of assets acquired | 108 | 858
Derivative financial instruments | 80 | 44
Application of the weighted average cost method in evaluation of inventories | 20 | 20
Other | 1,288 | 1,325
| 6,937 | 8,724
Deferred tax assets |  |
Carry-forward tax losses | (4,746) | (5,018)
Site restoration and abandonment (provisions for contingencies) | (1,953) | (2,148)
Timing differences on depreciation and amortization | (1,738) | (1,847)
Accruals for impairment losses and provisions for contingencies | (1,329) | (1,432)
Asset Impairment losses | (1,378) | (1,320)
Derivative financial instruments | (104) | (352)
Leasing | (268) | (338)
Employee benefits | (134) | (151)
Over/Under lifting | (89) | (120)
Unrealized intercompany profits | (71) | (77)
Other | (1,193) | (1,313)
| (13,003) | (14,116)
Accumulated write-downs of deferred tax assets | 4,155 | 4,651
Deferred tax assets, net of accumulated write-downs | (8,848) | (9,465)

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The following table summarizes the changes in deferred tax liabilities and assets:

(€ million) | Deferred tax liabilities before offsetting | Deferred tax assets before offsetting, gross | Accumulated write-downs of deferred tax assets | Deferred tax assets before offsetting net of accumulated write-down provisions
At December 31, 2024 | 8,724 | (14,116) | 4,651 | (9,465)
Additions | 506 | (2,628) | 528 | (2,100)
Deductions | (600) | 1,469 | (60) | 1,409
Changes with effect to OCI | 77 | 173 |  | 173
Currency translation differences | (897) | 679 | (245) | 434
Change in scope of consolidation | 1 | 3 |  | 3
Other changes | (874) | 1,417 | (719) | 698
At December 31, 2025 | 6,937 | (13,003) | 4,155 | (8,848)
At December 31, 2023 | 8,461 | (13,909) | 5,668 | (8,241)
Additions | 946 | (1,862) | 457 | (1,405)
Deductions | (1,042) | 2,176 | (1,663) | 513
Changes with effect to OCI | (351) | 92 |  | 92
Currency translation differences | 484 | (384) | 121 | (263)
Change in scope of consolidation | 193 | 156 | (168) | (12)
Other changes | 33 | (385) | 236 | (149)
At December 31, 2024 | 8,724 | (14,116) | 4,651 | (9,465)

Carry-forward tax losses amounted to €18,575 million, of which €15,432 million can be carried forward indefinitely. Carry-forward tax losses were €10,841 million at Italian subsidiaries and €7,734 million at foreign subsidiaries. Deferred tax assets gross of accumulated write-downs recognized on these losses amounted to €2,602 million and €2,144 million, respectively.

The Italian tax law allows the carry-forward of tax losses indefinitely. Foreign tax laws generally allow the carry-forward of tax losses over a period longer than five years, and in many cases, indefinitely. A tax rate of 24% was applied to tax losses of Italian subsidiaries to determine the portion of the carry-forwards tax losses. The corresponding average rate for foreign subsidiaries was 27.7%.

Accumulated write-downs of deferred tax assets related to Italian companies for €2,134 million and non-Italian companies for €2,021 million.

Taxes are also described in note 33 – Income taxes.

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24 Derivative financial instruments and hedge accounting

| December 31, 2025 | December 31, 2024
(€ million) | Fair value asset | Fair value liability | Level of Fair value | Fair value asset | Fair value liability | Level of Fair value
Non-hedging derivatives |  |  |  |  |  |
Derivatives on interest rate |  |  |  |  |  |
- Interest rate swap | 41 | 18 | 2 | 20 | 27 | 2
- Other | 1 |  | 2 |  |  |
| 42 | 18 |  | 20 | 27 |
Derivatives on exchange rate |  |  |  |  |  |
- Currency swap | 26 | 72 | 2 | 233 | 33 | 2
- Interest currency swap | 5 | 2 | 2 |  | 125 | 2
- Outright |  | 11 | 2 | 3 | 24 | 2
| 31 | 85 |  | 236 | 182 |
Derivatives on commodities |  |  |  |  |  |
- Over the counter | 633 | 767 | 2 | 632 | 923 | 2
- Future | 816 | 999 | 1 | 1,429 | 1,538 | 1
- Options | 11 | 22 | 1 | 61 | 111 | 2
- Other | 6 |  | 2 |  | 8 | 2
| 1,466 | 1,788 |  | 2,122 | 2,580 |
| 1,539 | 1,891 |  | 2,378 | 2,789 |
Fair value hedge derivatives |  |  |  |  |  |
Derivatives on interest rate |  |  |  |  |  |
- Interest rate swap | 38 |  | 2 | 42 |  | 2
| 38 |  |  | 42 |  |
Derivatives on exchange rate |  |  |  |  |  |
- Outright |  |  |  | 2 |  | 1
|  |  |  | 2 |  |
| 38 |  |  | 44 |  |
Cash flow hedge derivatives |  |  |  |  |  |
Derivatives on commodities |  |  |  |  |  |
- Over the counter | 167 |  | 2 | 20 | 335 | 2
- Future | 256 | 89 | 1 | 28 | 421 | 1
- Other | 5 | 105 | 2 |  |  |
| 428 | 194 |  | 48 | 756 |
| 428 | 194 |  | 48 | 756 |
Options |  |  |  |  |  |
- Other options |  | 21 | 2 |  | 37 | 2
|  | 21 |  |  | 37 |
Gross amount | 2,005 | 2,106 |  | 2,470 | 3,582 |
Offsetting | (1,133) | (1,133) |  | (1,508) | (1,508) |
Net amount | 872 | 973 |  | 962 | 2,074 |
- current | 791 | 827 |  | 874 | 1,921 |
- non-current | 81 | 146 |  | 88 | 153 |

Eni is exposed to market risk, which is the risk that changes in prices of energy commodities, exchange rates and interest rates could reduce the future cash flows of highly probable future transactions or the fair value of the assets. Eni enters into financial and commodities derivatives traded on organized markets (like MTF and OTF) and into commodities derivatives traded over the counter (swaps, forward, contracts for differences and options on commodities) to reduce the market risk, currencies or interest rates and, to a limited extent in compliance with internal authorization thresholds, with speculative purposes to profit from expected market trends.

Derivatives fair values were estimated based on market quotations provided by primary info-provider or, alternatively, appropriate valuation techniques generally adopted in the marketplace.

Fair-valued non-hedging derivatives mainly comprised forward sale contracts of natural gas for physical delivery which were not entitled to the own use exemption, as well as derivatives for proprietary trading activities.

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Fair-valued cash flow hedges mainly related to commodity hedges and were entered into by the Global Gas & LNG Portfolio business line to hedge variability in future cash flows associated with highly probable future trade transactions or on already contracted trades due to different indexation mechanisms of supply costs versus selling prices. A similar scheme applies to exchange rate hedging derivatives. The existence of a relationship between the hedged item and the hedging derivative is checked at inception to verify eligibility for hedge accounting by observing the offset in changes of the fair values at both the underlying commodity and the derivative. The hedging relationship is also stress-tested against the level of credit risk of the counterparty in the derivative transaction. The hedge ratio is defined consistently with the Company’s risk management objectives, under a defined risk management strategy. The hedging relationship is discontinued when it ceases to meet the qualifying criteria and the risk management objectives on the basis of which hedge accounting has initially been applied.

The effects of the measurement at fair value of cash flow hedge derivatives are given in note 26 – Equity. Information on hedged risks, the hedging policies are disclosed in note 28 – Guarantees, commitments and risks - Risk factors.

In 2025, the exposure to the exchange rate risk deriving from securities denominated in U.S. dollars included in the strategic liquidity portfolio amounting to €2,326 million was hedged by using, in a fair value hedge relationship, positive exchange differences for €262 million resulting on a portion of bonds denominated in U.S. dollars amounting to €2,010 million.

The offsetting of financial derivatives primarily related to Eni Global Energy Markets SpA and Eni Trade & Biofuels SpA.

During 2025, there were no transfers between the different hierarchy levels of fair value.

Hedging derivative instruments are disclosed below:

| December 31, 2025 | December 31, 2024
(€ million) | Nominal amount of the hedging instrument | Change in fair value (effective hedge) | Change in fair value (ineffective hedge) | Nominal amount of the hedging instrument | Change in fair value (effective hedge) | Change in fair value (ineffective hedge)
Cash flow hedge derivatives |  |  |  |  |  |
Derivatives on commodity |  |  |  |  |  |
- Over the counter | 1,506 | 448 | 2 | 1,753 | (524) | 13
- Future | 3,472 | 184 | 1 | 3,375 | (499) | 13
| 4,978 | 632 | 3 | 5,128 | (1,023) | 26
Other cash flow hedge derivatives |  |  |  |  |  |
- Other |  |  |  | 348 | (12) |
|  |  |  | 348 | (12) |
| 4,978 | 632 | 3 | 5,476 | (1,035) | 26
Fair value hedge derivatives |  |  |  |  |  |
Derivatives on interest rate |  |  |  |  |  |
- Interest rate swap | 1,962 | (4) |  | 1,981 | 42 | 1
| 1,962 | (4) |  | 1,981 | 42 | 1
Derivatives on exchange rate |  |  |  |  |  |
- Outright |  |  |  | 43 | 2 |
|  |  |  | 43 | 2 |
| 1,962 | (4) |  | 2,024 | 44 | 1

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The breakdown of the underlying asset or liability by type of risk hedged under cash flow hedge and fair value hedge is provided below:

| December 31, 2025 | December 31, 2024
(€ million) | Change of the underlying item used for the calculation of hedging ineffectiveness | CFH reserve | Reclassification adjustments | Change of the underlying item used for the calculation of hedging ineffectiveness | CFH reserve | Reclassification adjustments
Cash flow hedge derivatives |  |  |  |  |  |
Commodity price risk |  |  |  |  |  |
- Planned sales | (600) | 10 | (233) | 1,023 | (850) | (123)
Other cash flow hedge derivatives |  |  |  |  |  |
- hedged flows | (26) | 24 |  | 12 | (12) |

| December 31, 2025 | December 31, 2024
(€ million) | Nominal amount of the underlying item | Cumulative changes of the underlying item | Changes of the underlying item | Nominal amount of the underlying item | Cumulative changes of the underlying item | Changes of the underlying item
Fair value hedge derivatives |  |  |  |  |  |
Derivatives on interest rate |  |  |  |  |  |
- Financial liabilities | 2,008 | 39 | (5) | 2,066 | 44 | 44
Derivatives on exchange rate |  |  |  |  |  |
- Investments |  |  |  | 43 | (2) | (2)

More information is reported in note 28 — Guarantees, Commitments and Risks — Financial risks.

Effects recognized in other operating profit (loss)

Other operating profit (loss) related to derivative financial instruments on commodity was as follows:

(€ million) | 2025 | 2024 | 2023
Net income (loss) on cash flow hedging derivatives | 3 | 26 | 6
Net income (loss) on other derivatives | 638 | (378) | 472
| 641 | (352) | 478

Net income (loss) on cash flow hedging derivatives related to the ineffective portion of the hedging relationship on commodity derivatives was recognized through profit and loss.

Net income (loss) on other derivatives included the fair value measurement and settlement of commodity derivatives which could not be elected for hedge accounting under IFRS because they related to net exposure to commodity risk and derivatives for trading purposes and proprietary trading.

Effects recognized in finance income (loss)

(€ million) | 2025 | 2024 | 2023
Derivatives on exchange rate | (86) | 310 | (63)
Derivatives on interest rate | 6 | (32) | 2
| (80) | 278 | (61)

Net finance income from derivative financial instruments was recognized in connection with the fair value valuation of certain derivatives which lacked the formal criteria to be treated in accordance with hedge accounting under IFRS, as they were entered into for amounts equal to the net exposure to exchange rate risk and interest rate risk, and as such, they cannot be referred to specific trade or financing transactions. Exchange rate derivatives were entered into in order to manage exposures to foreign currency exchange rates arising from the pricing indexation of energy commodities.

More information is disclosed in note 36 – Transactions with related parties.

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25 Assets held for sale and liabilities directly associated with assets held for sale

As of December 31, 2025, assets held for sale of €8,005 million (€420 million at 31 December, 2024) and directly associated liabilities of €2,026 million (€195 million at 31 December, 2024) mainly concerned oil&gas assets in Indonesia, United Arab Emirates, Congo and Ivory Coast, which book value was aligned to the expected fair value, amounting to €6,924 million and €1,182 million, respectively. More information is provided in note 12 – Property, plant and equipment. The company Plenitude Production France SAS, acquired in December 2025 and comprising assets and liabilities of €1,078 million and €844 million respectively, falls within the category of subsidiaries acquired exclusively for the purpose of sale.

During 2025, assets reclassified as held for sale in the 2024 relating to some oil&gas assets in Congo.

26 Equity

Non-controlling interest

| Profit (Loss) | Equity
(€ million) | 2025 | 2024 | December 31, 2025 | December 31, 2024
Eni Plenitude Group | 6 | 54 | 1,816 | 491
Eni Marine Services SpA |  |  | 1,701 | 1,924
Enilive Group | 87 |  | 860 |
EniPower Group | 64 | 85 | 457 | 446
Others | (7) | 1 | 13 | 2
| 150 | 140 | 4,847 | 2,863

On March 6, 2025, Eni and the private equity fund KKR finalized KKR's investment in a 25% minority stake in its subsidiary Enilive, with total proceeds for Eni of €2,968 million, including a €500 million capital increase. Subsequently, on April 11, 2025, Eni and KKR completed a similar transaction for an additional 5% investment for €601 million. Following the transaction, KKR holds a total stake of 30% of Enilive’s share capital.

On March 31, 2025, Energy Infrastructure Partners (EIP) completed an increase in Plenitude's share capital, reaching a total of 10%. EIP's stake was increased through a capital increase of €209 million, which, taking into account the €588 million paid in March 2024, brings the total investment to approximately €800 million. On November 4, Eni and the private equity fund Ares Capital finalized a 20% minority interest in Plenitude's share capital for €2,003 million.

Minority interests in Eni Marine Services SpA related to perpetual subordinated bonds issued in U.S. dollars to finance a Group’s major capital project in Congo. The perpetual subordinated bonds were recognized among minority interests in consideration of the Group’s unconditional right to avoid transferring cash or other financial assets to the bondholders. The carrying amount at December 31, 2025, was adjusted to the EUR/USD exchange rate, resulting in a decrease of €223 million.

Equity attributable to equity holders of Eni

(€ million) | December 31, 2025 | December 31, 2024
Share capital | 4,005 | 4,005
Retained earnings | 33,209 | 32,552
Cumulative currency translation differences | 1,936 | 8,081
Other reserves and equity instruments: |  |
- Perpetual subordinated bonds | 5,000 | 5,000
- Legal reserve | 959 | 959
- Reserve for treasury shares | 2,782 | 2,883
- Reserve for OCI on cash flow hedging derivatives net of tax effect | 42 | (612)
- Reserve for OCI on defined benefit plans net of tax effect | (94) | (91)
- Reserve for OCI on equity-accounted investments | 92 | 28
- Reserve for OCI on other investments valued at fair value | 104 | 160
- Reserve for convertible bond issue | 79 | 79
Treasury shares | (2,782) | (2,883)
Profit for the year | 2,608 | 2,624
| 47,940 | 52,785

Share capital

As of December 31, 2025, the parent company’s issued share capital consisted of €4,005,358,876 (same amount as of December 31, 2024) represented by 3,146,765,114 ordinary shares without nominal value (3,284,490,525 ordinary shares at December 31, 2024).

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On May 14, 2025, Eni’s Shareholders’ Meeting resolved: (i) to distribute available reserves by way of and in place of the payment of the dividend for the year 2025 of €1.05 per share in four tranches, in September 2025 (€0.26 per share), November 2025 (€0.26 per share), March 2026 (€0.26 per share) and May 2026 (€0.27 per share); (ii) to authorize the Board of Directors pursuant to and for the purposes of Art. 2357 of the Italian Civil Code to proceed with the purchase of shares of the Company, in multiple tranches, for a period up to April 30, 2026, in a maximum number of shares to be purchased equal to 315,000,000 ordinary shares for a total outlay of up to €3.5 billion; (iii) to authorize the Board of Directors to cancel up to a maximum of 315,000,000 treasury shares which will eventually be acquired based on the shareholders' authorization of the previous point. In execution of these resolutions, as of December 31, 2025, 102,255,755 treasury shares have been acquired for a total value of €1,520 million.

Cumulative foreign currency translation differences

The cumulative foreign currency translation differences arose from the translation of financial statements denominated in currencies other than euro.

Perpetual subordinated hybrid bonds

The hybrid bonds are governed by the English law and are traded on the regulated market of the Luxembourg Stock Exchange. As of December 31, 2025, hybrid bonds amounted to €5 billion (same amount as at December 31, 2024).

The key characteristics of the hybrid bonds are: (i) an issue of €1.5 billion perpetual 9-year subordinated non-call hybrid notes with a re-offer price of 100% and an annual fixed coupon of 3.375% until the first reset date of October 13, 2029. As from such date, unless it has been redeemed in whole on or before the first reset date, which is the last day for the first optional redemption, the bond will bear interest per annum determined according to the relevant 5-year Euro Mid Swap rate plus an initial spread of 364.1 basis points, increased by additional 25 basis points as from October 13, 2034 and a subsequent increase of additional 75 basis points as from October 13, 2049; (ii) an issue of €1 billion subordinated hybrid perpetual bond with a 6-year non-call period, with a re-offer price at issuance of 100% and an annual coupon of 2% until the first reset date scheduled for May 11, 2027. If the early repayment has not taken place by the first reset date, which coincides with the last early repayment date, this bond pays annual interest equal to the reference five-year Euro Mid Swap rate increased by an initial margin of 220.4 basis points, increased by a further margin of 25 basis points starting from May 11, 2032 and a subsequent increase of a further 75 basis points starting from May 11, 2047; (iii) an issue of €1 billion subordinated hybrid perpetual bond with a 9-year non-call period, with a re-offer price at issuance of 99.607% and an annual coupon of 2.75% until the first reset date scheduled for May 11, 2030. If the early repayment has not taken place by the first reset date, which coincides with the last early repayment date, this bond pays annual interest equal to the reference five-year Euro Mid Swap rate increased by an initial margin of 277.1 basis points, increased by a further margin of 25 basis points starting from May 11, 2035 and a subsequent increase of a further 75 basis points starting from May 11, 2050; (iv) a subordinated hybrid perpetual issue of €900 million, with a re-offer price at issuance of 99.354% and an annual coupon of 4.5% until the first reset date scheduled 6.25 years after issuance (April 21, 2031). If the early repayment has not occurred, the annual coupon will be reset starting from April 21, 2031 and every 5 years thereafter, with a rate equal to the 5-year Euro Mid Swap in effect from time to time plus an initial spread of 208.3 basis points. This spread will be further increased by 25 basis points starting from April 21, 2036 and by a subsequent increase of a further 75 basis points starting from April 21, 2051; (v) a subordinated hybrid perpetual issue of €600 million, with a re-offer price at issuance of 99.114% and an annual coupon of 4.875% until the first reset date scheduled 9.25 years after issuance (April 21, 2034). If the early repayment has not occurred, the annual coupon will be reset starting from April 21, 2034 and every 5 years thereafter, with a rate equal to the 5-year Euro Mid Swap in effect from time to time plus an initial spread of 239.9 basis points. This spread will be further increased by 25 basis points starting from April 21, 2039 and by a subsequent increase of a further 75 basis points starting from April 21, 2054.

Legal reserve

This reserve represents earnings restricted from the payment of dividends pursuant to Article 2430 of the Italian Civil Code. The legal reserve has reached the maximum amount required by the Italian Law.

Reserve for treasury shares

The reserve for treasury shares represents the reserve that was established in previous reporting periods to repurchase the Company shares in accordance with resolutions at Eni’s Shareholders’ Meetings.

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Reserves for Other Comprehensive Income

| Reserve for OCI on cash flow hedge derivatives | Reserve for OCI on defined benefit plans | Reserve for OCI on equity-accounted investments (*) | Reserve for OCI on investments valued at fair value
(€ million) | Gross reserve | Deferred tax liabilities | Net reserve | Gross reserve | Deferred tax liabilities | Net reserve
Reserve as of December 31, 2024 | (861) | 249 | (612) | (121) | 30 | (91) | 28 | 160
Changes of the year | 661 | (197) | 464 | (11) | 2 | (9) | 73 | (32)
Currency translation differences | 3 | (1) | 2 | 1 | (1) |  |  | (19)
Changes in scope of consolidation and non-controlling interest | 27 | (9) | 18 | 8 | (2) | 6 | (9) | (5)
Reversal to inventories adjustments | 5 | (1) | 4 |  |  |  |  |
Reclassification adjustments | 233 | (67) | 166 |  |  |  |  |
Reserve as of December 31, 2025 | 68 | (26) | 42 | (123) | 29 | (94) | 92 | 104
Reserve as of December 31, 2023 | 50 | (14) | 36 | (94) | 6 | (88) | 98 | 98
Changes of the year | (1,034) | 299 | (735) | 8 | (4) | 4 | (70) | 62
Currency translation differences |  |  |  | (5) | 3 | (2) |  |
Changes in scope of consolidation |  |  |  | (30) | 25 | (5) |  |
Reclassification adjustments | 123 | (36) | 87 |  |  |  |  |
Reserve as of December 31, 2024 | (861) | 249 | (612) | (121) | 30 | (91) | 28 | 160

(*) Reserve for OCI on equity-accounted investments at December 31, 2025 includes €1 million relating to defined benefit plans (same amount as of December 31, 2024)

Treasury shares

A total of 189,083,769 of Eni’s ordinary shares (203,137,967 at December 31, 2024) were held in treasury for a total cost of €2,782 million (€2,883 million at December 31, 2024).

During 2025, 128,453,526 shares were acquired, for a total value of €1,881 million, as part of the completion of the 2024 buy-back plan and the execution of the €1.8 billion 2025 program 84% completed at the balance sheet date, in compliance with the shareholders' authorizations; 137,725,411 treasury shares have been cancelled for a total value of €1,908 million and 1,492,968 treasury shares were assigned free of charge to Eni managers, following the conclusion of the Vesting Period as required by the “Long-Term Monetary Incentive Plan 2020-2022” approved by Eni's Shareholders' Meeting of May 13, 2020 and 3,289,345 treasury shares were assigned free of charge to Eni employees as provided for in the 2024-2026 Employee Stock Ownership Plan approved by the Shareholders’ Meeting on May 15, 2024. The vesting and performance conditions of long-term incentive plans are reported in note 30 – Costs.

Distributable reserves

As of December 31, 2025, equity attributable to Eni included distributable reserves of approximately €38 billion.

Reconciliation of profit and equity of the parent company Eni SpA to the consolidated profit and equity

| Profit | Shareholders’ equity
(€ million) | 2025 | 2024 | December 31, 2025 | December 31, 2024
As recorded in Eni SpA's Financial Statements | 4,429 | 6,419 | 50,986 | 50,735
Excess of net equity stated in the separate accounts of consolidated subsidiaries over the corresponding carrying amounts of the parent company | (1,643) | (2,029) | 1,643 | 4,338
Consolidation adjustments: |  |  |  |
- difference between purchase cost and underlying carrying amounts of net equity |  |  | 153 | 153
- adjustments to comply with Group accounting policies | (285) | (1,722) | 425 | 1,240
- elimination of unrealized intercompany profits | 219 | (80) | (301) | (537)
- deferred taxation | 38 | 176 | (119) | (281)
| 2,758 | 2,764 | 52,787 | 55,648
Non-controlling interest | (150) | (140) | (4,847) | (2,863)
As recorded in Consolidated Financial Statements | 2,608 | 2,624 | 47,940 | 52,785

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27 Other information

Supplemental cash flow information

(€ million) | 2025 | 2024 | 2023
Investment in consolidated subsidiaries and businesses |  |  |
Current assets |  | 486 | 408
Non-current assets | 1,040 | 3,863 | 1,985
Net borrowings | (724) | (468) | (91)
Current and non-current liabilities | (82) | (1,825) | (622)
Net effect of investments | 234 | 2,056 | 1,680
Goodwill |  | 33 | 25
Fair value of investments held before the acquisition of control |  | (28) | (271)
Non-controlling interests |  | (1) | (2)
Purchase price | 234 | 2,060 | 1,432
less: |  |  |
Cash and cash equivalents acquired | (38) | (265) | (155)
Consolidated subsidiaries and businesses net of cash and cash equivalent acquired | 196 | 1,795 | 1,277
Disposal of consolidated subsidiaries and businesses |  |  |
Current assets | 85 | 802 | 130
Non-current assets | 657 | 2,695 | 153
Net borrowings | (322) | 101 | 180
Current and non-current liabilities | (196) | (2,267) | (124)
Net effect of disposals | 224 | 1,331 | 339
Current value of the stake held for business combinations | (138) | (788) | (580)
Reclassification among other items of OCI |  |  | (7)
Gain on disposal of business combinations | 45 | 379 | 427
Fair value of share capital held after the sale of control | 27 | 118 | 414
Credits for divestments |  |  | (173)
Selling price | 158 | 1,040 | 420
less: |  |  |
Cash and cash equivalents sold | (40) | (153) | (25)
Consolidated subsidiaries and businesses net of cash and cash equivalent disposed of before business combination | 118 | 887 | 395

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Investments and disposals in 2025 are disclosed in note 5 – Business combinations and other significant transactions.

Business combinations and other significant transactions

The provisional and definitive price allocation of the net assets acquired in 2024 is shown below:

(€ million) | Plenitude - Renewable energies and retail (Provisional allocation) | Plenitude - Renewable energies and retail (Definitive allocation) | Enilive - Atenoil (Provisional allocation) | Enilive - Atenoil (Definitive allocation)
Current assets | 5 | 5 | 5 | 5
Property, plant and equipment | 71 | 71 | 14 | 30
Goodwill | 5 | 5 | 28 | 23
Other non-current assets | 52 | 52 | 23 | 17
Cash and cash equivalent (Net borrowings) | (53) | (53) | (10) | (10)
Current and non-current liabilities | (5) | (5) | (10) | (15)
Net effects of investments | 75 | 75 | 50 | 50

Following the definitive allocation of the 2024 business combinations, financial statements were not restated taking into account the immateriality of the changes.

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28 Guarantees, commitments and risks

Guarantees

(€ million) | December 31, 2025 | December 31, 2024
Associates | 6,694 | 9,063
Joint ventures | 1,473 | 165
Others | 634 | 424
| 8,801 | 9,652

In the ordinary course of business, Eni issues guarantees on behalf of non-consolidated companies (joint ventures or associates) in relation to the fulfillment of contractual obligations, mainly autonomous contracts to guarantee the correct execution of works, participation in tenders and other commitments of companies relating to the Exploration & Production segment, as well as parent company guarantees to banks and financial institutions funding those non-consolidated entities in relation to the execution of capital projects in the interest of the Group. Some guarantees have been issued to governments and State entities with the aim of insuring the counterparty against possible environmental damages or in relation to negligent conducts in the development of oil projects or failure to comply with contractual provisions. In case of guarantees for environmental damages or similar contractual breaches which do not provide a cap, the reported value reflects the management’s best estimate of potential maximum exposure. In case management would be unable to estimate the maximum amount of potential future payments, the adverse event is deemed to have only a remote possibility of occurrence or a negligible impact (as the case of the parent company guarantee issued on behalf of the jointly controlled entity Cardón IV in the event of a default on the supply of equity gas to the national oil company of Venezuela).

The decrease of €851 million was mainly due to the termination of the guarantees issued to banks and to the Mozambican State oil company ENH on behalf of the financing consortium for the development of gas reserves of the Coral discovery (€1,710 million). This decrease was partially offset by the issuance of new guarantees in connection with the sale of 49.99% of CCUS activities in the United Kingdom and the Netherlands to a private equity fund (€1,218 million).

At December 31, 2025, the underlying commitment relating to the guarantees issued was €5,223 million (€5,790 million at December 31, 2024), which takes into account the progress of the activities and the repaid obligations.

Also on the basis of historical experience, management considers reasonably probable that such guarantees will not have significant effects on the economic results and cash flows of the consolidated financial statements.

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Commitments and risks

(€ million) | December 31, 2025 | December 31, 2024
Commitments | 77,006 | 84,129
Risks | 856 | 1,046
| 77,862 | 85,175

Commitments related to: (i) parent company guarantees that were issued in connection with certain contractual commitments for hydrocarbon exploration and production activities and quantified, based on the capital expenditures to be incurred, to be €72,797 million (€79,858 million at December 31, 2024). The decrease of €7,061 million was mainly due to currency translation differences and the closure of the parent company guarantee relating to Eni RAK BV (€1,924 million); (ii) a parent company guarantee of €3,402 million (€3,849 million at December 31, 2024) issued on behalf of Eni Abu Dhabi Refining & Trading BV following the Share Purchase Agreement to acquire from Abu Dhabi National Oil Company (ADNOC) a 20% equity interest in ADNOC Refining and the set-up of the joint venture ADNOC Global Trading Ltd dedicated to marketing petroleum products. The parent company guarantee will remain in force as long as the shareholding is maintained; (iii) commitments in the Plenitude business line for the purchase of renewable energy projects in Italy and Spain for €560 million (€246 million at December 31, 2024).

Risks related to: (i) assets of third parties under custody of Eni for €610 million (€772 million at December 31, 2024); (ii) contractual assurances given to acquirers of certain divestments and businesses of Eni for €236 million (€264 million at December 31, 2024).

Other commitments and risks

Other commitments include the agreements entered into for forestry initiatives, implemented within the low carbon strategy defined by the Company, concerning the commitments for the purchase until 2038 of carbon credits produced and certified according to international standards by experts specialized in forest conservation programs.

In addition, following the sale of equity investments and businesses or loss of control transactions, Eni is exposed to non-quantifiable risks against certain contingent liabilities deriving from tax, social security contributions, environmental issues and other matters applicable to periods during which such assets were operated by Eni or as result of Eni’s loss of control of formerly consolidated subsidiaries. Eni believes such risks will not have a material adverse effect on Eni’s results of consolidated financial statements.

Regarding take-or-pay supply contracts with Russian state-owned companies (Gazprom and its affiliates), since 2023, Eni has ceased to withdraw natural gas from existing contracts with Gazprom for sale in EU markets due to various commercial disputes between the parties. Eni expects this situation to continue into 2026.

In relation to oil and gas asset sales, including transactions concluded in previous years, decommissioning obligations may revert to the seller if the buyer fails to fulfill these obligations.

Risk factors

The following is the description of financial risks and their management. With reference to the issues related to credit risk, the parameters adopted for the determination of Expected Credit Loss have been updated to take into account the current energy crisis and the impacts associated with the conflicts between Russia and Ukraine and in the Middle East.

As of December 31, 2025, the Company retains liquidity reserves that management deems enough to meet the financial obligations due in the next eighteen months.

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Financial risks

Financial risks are managed in respect of the guidelines issued by the Board of Directors of Eni SpA in its role of directing and setting the risk limits, targeting to align and centrally coordinate Group companies’ policies on financial risks (“Guidelines on financial risks management and control”). The “Guidelines” define for each financial risk the key components of the management and control process, such as the target of the risk management, the valuation methodology, the structure of limits, the relationship model and the hedging and mitigation instruments.

Market risk

Market risk is the possibility that changes in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected cash flows. The Company actively manages market risk in accordance with the aforementioned guidelines that provide a centralized model of handling finance, treasury and risk management transactions based on the Company’s departments of operational finance: the parent company’s (Eni SpA) finance department and Banque Eni SA, which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk, as well as Eni Trade & Biofuels SpA and Eni Global Energy Markets SpA, that are in charge to execute certain activities relating to commodity derivatives. In particular, Eni Corporate finance department manages Eni subsidiaries’ financing requirements, covering funding requirements and using available surpluses and the transactions concerning currencies and financial derivatives different from commodities of Eni, while Eni Trade & Biofuels SpA and Eni Global Energy Markets SpA execute the negotiation of commodity derivatives over the market. Eni SpA, Eni Trade & Biofuels SpA and Eni Global Energy Markets SpA (also through the subsidiary Eni Trading & Shipping Inc) perform trading activities in financial derivatives on external trading venues, such as European and non-European regulated markets, Multilateral Trading Facility (MTF), Organized Trading Facility (OTF), or similar brokerage platforms (i.e. SEF), as well as over the counter on a bilateral basis with external counterparties. Other legal entities belonging to Eni that require financial derivatives enter these transactions through Eni Trade & Biofuels SpA, Eni Global Energy Markets SpA and Eni SpA based on the relevant asset class expertise. Eni uses derivative financial instruments to minimize exposure to market risks related to transactional exchange rates and interest rates, as well as to optimize exposure to commodity prices risk considering the currency in which commodities are quoted. Eni monitors that every activity in derivatives classified as risk-reducing is directly or indirectly related to covered industrial assets, to effectively optimize the risk profile to which Eni is exposed or could be exposed. If the result of the monitoring shows those derivatives should not be considered as risk reducing, these derivatives are reclassified in proprietary trading. As proprietary trading is considered separately from the other activities in specific portfolios of Eni Trade & Biofuels SpA and Eni Global Energy Markets SpA, their exposure is subject to specific controls, both in terms of Value at Risk (VaR) and stop loss and in terms of nominal gross value. For Eni, the gross nominal value of proprietary trading activities is compared with the limits set by the relevant international standards. The framework defined by Eni’s guidelines provides that the valuation and control of market risk is performed on the basis of maximum tolerable levels of risk exposure defined in terms of stop loss, which expresses the maximum tolerable amount of losses associated with a certain portfolio of assets over a pre-defined time horizon, and limits of strategy revision, which consist in the triggering of a revision process of the strategy in the event of exceeding the level of profit and loss given and VaR, which measures the maximum potential loss of the portfolio, given a certain confidence level and holding period, assuming adverse changes in market variables and taking into account the correlation among the different positions held in the portfolio. Eni’s finance department defines the maximum tolerable levels of risk exposure to changes in interest rates and foreign currency exchange rates in terms of VaR, pooling Group companies’ risk positions maximizing, when possible, the benefits of the netting activity. Eni’s calculation and valuation techniques are in accordance with banking standards, as established by the Basel Committee for bank activities surveillance. Tolerable levels of risk are based on a conservative approach, considering the industrial nature of the Company. Eni’s guidelines prescribe that Eni’s Group operating companies minimize such kind of market risks by transferring risk exposure to the parent company finance departments. Eni’s guidelines define rules to manage the commodity price risk aiming at optimizing core activities and pursuing preset targets of stabilizing industrial and commercial margins. The maximum tolerable level of risk exposure is defined in terms of VaR, limits of strategy revision, stop loss and volumes in connection with exposure deriving from commercial activities, as well as exposure deriving from proprietary trading, exclusively managed by Eni Trade & Biofuels SpA and Eni Global Energy Markets SpA. Internal mandates to manage the commodity price risk provide for a mechanism of allocation of the Group’s maximum tolerable risk level to each business unit. In this framework, Eni Trade & Biofuels SpA and Eni Global Energy Markets SpA, in addition to managing risk exposure associated with their own commercial activity and proprietary trading, pool the requests for negotiating commodity derivatives and execute them in the marketplace.

According to the targets of financial structure included in the Financial Plan approved by the Board of Directors, Eni decided to retain a cash reserve in which the amount of strategic liquidity is identified, to allow for any extraordinary needs to be met. The reserve is managed by Eni’s finance department, with the aim of optimizing performance while ensuring maximum protection of capital and its immediate liquidity within the limits assigned. The management of strategic liquidity is part of the asset management pursued through transactions on own risk in view of optimizing financial returns, while respecting authorized risk levels, safeguarding the Company’s assets and retaining quick access to liquidity. The four different market risks, whose management and control have been summarized above, are described below.

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Market risk - Exchange rate

Exchange rate risk derives from the fact that Eni’s operations are conducted in currencies other than euro (mainly U.S. dollar). Revenues and expenses denominated in foreign currencies may be significantly affected by exchange rate fluctuations due to conversion differences on single transactions arising from the time lag existing between execution and definition of relevant contractual terms (economic risk) and conversion of foreign currency-denominated trade and financing payables and receivables (transactional risk). Exchange rate fluctuations affect the Group’s reported results and net equity as financial statements of subsidiaries denominated in currencies other than euro are translated from their functional currency into euro. Generally, an appreciation of U.S. dollar versus euro has a positive impact on Eni’s results of operations, and vice versa. Eni’s risk management objective is to minimize transactional exchange rate risk and optimize economic exchange rate risk associated with commodity price risk. The risk arising from the accrual of operating income in foreign currency or from the conversion of assets and liabilities of subsidiaries, which prepare financial statements in a currency other than euro, except for single transactions to be evaluated on a case-by-case basis.

Effective management of exchange rate risk is performed within Eni’s finance department, which pools Group companies’ positions, offsetting the exposures of opposite sign arising from business activities involved and hedging the residual exposure in the market, maximizing the benefits of the netting activity. To manage the residual exposure, the guidelines admit different derivatives, such as swaps, forwards and options. Such derivatives are evaluated at fair value based on standard market valuation algorithms and market prices provided by specialized public info-providers. The VaR resulting from the centralization of Eni's exchange rate risk positions within the Eni Corporate Finance Structures is calculated on a daily basis according to the parametric approach (variance/covariance), adopting a confidence level of 99% and a 1-day holding period.

Market risk - Interest rate

Changes in interest rates affect the market value of financial assets and liabilities of the Company valued at fair value and the level of finance expense and income.

Eni’s interest rate risk management policy is to minimize the risk in pursuit of the financial structure objectives defined and approved in management’s Financial Plan. Eni’s finance department pools borrowing requirements of the Group companies to manage net positions and fund portfolio developments consistent with the Financial Plan, thereby maintaining a level of risk exposure within prescribed limits. Eni enters interest rate derivative transactions to effectively manage the balance between fixed and floating rate debt. Such derivatives are evaluated at fair value based on market prices provided by specialized sources. VaR deriving from interest rate exposure is measured daily based on a variance/covariance model, with a 99% confidence level and a 1-day holding period.

Market risk - Commodity

Commodity price risk is identified as the possibility that fluctuations in the price of raw materials and basic products produce significant changes in Eni’s operating margins, determining an impact on the economic result such as compromising the targets defined in the four-year plan and in the budget. The commodity price risk arises in connection with the following exposures: (i) strategic exposure: exposures directly identified by the Board of Directors as a result of strategic investment decisions or outside the planning horizon of risk management. These exposures include, for example, exposures associated with the program for the production of oil&gas reserves, long-term gas supply contracts for the portion not balanced by sales contracts (already stipulated or expected), the margin deriving from the chemical transformation process, the refining margin and long-term storage functional to the logistic-industrial activities; (ii) commercial exposure: concerns the exposures related to components underlying the contractual arrangements of industrial and commercial (contracted exposure) activities normally related to the time horizon of the 2026-2030 industrial plan and budget, components not yet under contract but which will be with reasonable certainty (commitment exposure) and the related activities of risk management. Commercial exposures are characterized by a systematic risk management activity conducted based on risk/return assumptions by implementing one or more strategies and subjected to specific risk limits (VaR, revision strategy limits and stop loss). In particular, the commercial exposures include exposures subjected to asset-backed hedging activities, arising from the flexibility/optionality of assets; (iii) proprietary trading exposure: transactions carried out autonomously for speculative purposes in the short term and normally not aimed at delivery with the intention of exploiting favorable price movements, spreads and/or volatility implemented autonomously and carried out regardless of the exposures of the commercial portfolio or physical and contractual assets. They are usually carried out in the short term, not necessarily aimed at the delivery and carried out by using financial or similar instruments in accordance with specific limits of authorized risk (VaR, stop loss). Strategic risk is not subject to systematic activity of management/hedging that is eventually carried out only in case of specific market or business conditions. Because of the extraordinary nature, hedging activities related to strategic risks are delegated to the top management, previously authorized by the Board of Directors. With prior authorization from the Board of Directors, the exposures related to strategic risk can be used in combination with other commercial exposures in order to exploit opportunities for natural compensation between the risks (natural hedge) and consequently reduce the use of financial derivatives (by activating logics of internal market). With regard to exposures of commercial nature, Eni's risk management target is to optimize the "core" activities and preserve the economic/financial results. Eni manages the commodity price risk through the trading units (Eni Trade & Biofuels SpA and Eni Global Energy Markets SpA) and the exposure to commodity prices through Eni’s finance department by using financial derivatives traded on the regulated markets, MTF, OTF and financial derivatives traded over the counter (swaps, forward, contracts for differences and options on commodities) with the underlying commodities being crude oil, gas, refined products, power or emission certificates. Such financial derivatives are valued at fair value based on market prices provided from specialized sources and based on estimates provided by brokers or suitable valuation techniques. VaR deriving from commodity exposure is measured daily based on a historical simulation technique, with a 95% confidence level and a 1-day holding period.

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Market risk - Strategic liquidity

Market risk deriving from liquidity management is identified as the possibility that changes in prices of financial instruments (bonds, money market instruments and mutual investment funds) affect the value of these instruments in case of sale or when they are valued at fair value in the financial statements. The setting up and maintenance of the liquidity reserve are mainly aimed to guarantee proper financial flexibility. Liquidity should allow Eni to fund any extraordinary need (such as difficulty in access to credit, exogenous shock, macroeconomic environment, as well as merger and acquisitions) and must be dimensioned to provide a coverage of short-term debts and of medium and long-term finance debts due within a time horizon of 24 months. In order to manage the investment activity of the strategic liquidity, Eni defined a specific investment policy with aims and constraints in terms of the type of financial instruments that can be invested in, and operational limits, as well as governance guidelines regulating management and control systems. In particular, strategic liquidity management is regulated in terms of VaR (measured based on a parametrical methodology with a one-day holding period and a 99% confidence level), stop loss and other operating limits in terms of concentration, issuing entity, business segment, country of emission, duration, ratings and type of investing instruments in portfolio, aimed to minimize market and liquidity risks. Financial leverage or short selling is not allowed. As of 31 December 2025, the average rating of the Strategic liquidity investment portfolio was A/A-, in line compared to the end of 2024.

The following tables show amounts in terms of VaR, recorded in 2025 (compared with 2024), relating to interest rate and exchange rate risks in the first section and commodity price risk (aggregated by type of exposure). Regarding the management of strategic liquidity, the table reports the sensitivity to changes in the interest rate.

(Value at risk - parametric method variance/covariance; holding period: 1 day; confidence level: 99%)

| 2025 |  | 2024
(€ million) | High | Low | Average | At year end |  | High | Low | Average | At year end
Interest rate (a) | 10.29 | 4.45 | 7.48 | 4.45 |  | 13.03 | 3.92 | 5.95 | 7.50
Exchange rate (a) | 7.99 | 0.07 | 2.07 | 0.43 |  | 5.47 | 0.07 | 1.65 | 0.69

(a) Value at Risk deriving from interest and exchange rates exposures includes the following finance departments: Eni Corporate Finance Department and Banque Eni SA.

(Value at risk - Historic simulation method; holding period: 1 day; confidence level: 95%)

| 2025 |  | 2024
(€ million) | High | Low | Average | At year end |  | High | Low | Average | At year end
Commercial exposures - Management Portfolio (a) | 34.93 | 2.79 | 16.37 | 2.79 |  | 69.66 | 6.20 | 24.10 | 6.32
Trading (b) | 1.34 | 0.30 | 0.63 | 0.37 |  | 1.74 | 0.21 | 0.53 | 0.31

(a) Refers to Global Gas & LNG Portfolio business area, Power Generation & Marketing, REVT, Plenitude, Eni Trading & Biofuels, Eni Global Energy Markets (commercial portfolio). VaR is calculated on the so-called Statutory view, with a time horizon that coincides with the Balance Sheet year, including all the volumes delivered in the year and the relevant financial hedging derivatives. Consequently, during the year the VaR pertaining to GGP, Power G&M, REVT and Plenitude during the year presents a decreasing trend following the progressive reaching of the maturity of the positions within the annual horizon.

(b) Cross-commodity proprietary trading, through financial instruments, refers to Eni Trading & Biofuels SpA and Eni Global Energy Markets SpA and Eni Trading & Shipping Inc.

(Sensitivity - Dollar value of 1 basis point - DVBP)

| 2025 |  | 2024
(€ million) | High | Low | Average | At year end |  | High | Low | Average | At year end
Strategic liquidity - € Portfolio | 0.64 | 0.53 | 0.58 | 0.54 |  | 0.60 | 0.20 | 0.40 | 0.60

(Sensitivity - Dollar value of 1 basis point - DVBP)

| 2025 |  | 2024
($ million) | High | Low | Average | At year end |  | High | Low | Average | At year end
Strategic liquidity - US dollar Portfolio | 0.18 | 0.12 | 0.15 | 0.16 |  | 0.20 | 0.10 | 0.10 | 0.10

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Credit risk

Credit risk is the potential exposure of the Group to losses in case counterparties fail to fulfill obligations. Eni defined credit risk management policies consistent with the nature and characteristics of the counterparties of commercial and financial transactions regarding the centralized finance model. The Company adopted a model to quantify and control the credit risk based on the evaluation of the expected credit loss which represents the probability of default and the capacity to recover credits in default that is estimated through the so-called Loss Given Default. In the credit risk management and control model, credit exposures are distinguished by commercial nature, in relation to sales contracts on commodities related to Eni’s businesses, and by financial nature, in relation to the financial instruments used by Eni, such as deposits, derivatives and real estate securities.

Credit risk for commercial exposures

Credit risk arising from commercial counterparties is managed by the business units and by the specialized corporate finance and dedicated administration departments and is operated based on formal procedures for the assessment of commercial counterparties, the monitoring of credit exposures, credit recovery activities and disputes. At a corporate level, the general guidelines and methodologies for quantifying and controlling customer’s risk are defined, in particular the riskiness of commercial counterparties is assessed through an internal rating model that combines different default factors deriving from economic variables, financial indicators, payment experiences and information from specialized primary info providers. The probability of default related to State Entities or their closely related counterparties (e.g. National Oil Company), essentially represented by the probability of late payments, is determined by using the country risk premiums adopted for the purposes of the determination of the WACCs for the impairment of non-financial assets. Finally, for retail positions without specific ratings, risk is determined by distinguishing customers in homogeneous risk clusters based on historical series of data relating to payments, periodically updated.

Credit risk for financial exposures

Regarding credit risk arising from financial counterparties essentially deriving from current and strategic use of liquidity and derivative contracts, Eni has established internal policies providing exposure control and concentration through maximum credit risk limits corresponding to different classes of financial counterparties based on ratings provided for by primary credit rating agencies. Credit risk arising from financial counterparties is managed by Eni’s operating finance departments, Eni Global Energy Markets SpA, Eni Trade & Biofuels SpA and Eni Trading & Shipping Inc specifically for commodity derivatives transactions consistently with the Group centralized finance model. Eligible financial counterparties are closely monitored by each counterpart and by groups to which it belongs, to check exposures against the limits assigned daily and the Expected Credit Loss analysis and the concentration periodically.

Liquidity risk

Liquidity risk is the risk that suitable sources of funding for the Group may not be available (funding liquidity risk), or the Group is unable to sell its assets in the marketplace (asset liquidity risk). Such a situation would negatively affect Group results, as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. Eni’s risk management targets include the maintaining of an adequate level of financial resources readily available to deal with external shocks (drastic changes in the scenario, restrictions on access to capital markets, etc.) or to ensure an adequate level of operational flexibility for the development projects of the Company. The strategic liquidity reserve is employed in short-term marketable financial assets, favoring investments with a very low risk profile. At present, the Group believes to have access to more than sufficient funding to meet the current foreseeable borrowing requirements due to available cash on hand financial assets and borrowing facilities and the access to a wide range of funding opportunities which can be activated through the credit system and capital markets.

Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which €12.8 billion were drawn as of December 31, 2025.

In 2025, Standard & Poor’s assigned to the Group credit ratings of A- outlook Negative and A-2, respectively, for long and short-term debt; Moody's revised Eni's rating from Baa1 to A3 outlook Stable and assigned a rating of P-2 for short-term debt; Fitch assigned credit ratings A- outlook Stable and F 1, respectively for long and short-term debt. Eni’s credit rating is linked, in addition to the Company’s industrial fundamentals and trends in the trading environment, to the Italy’s sovereign rating.

As of December 31, 2025, available committed borrowing facilities amounted to €9 billion.

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Expected payments for financial debts, lease liabilities, trade and other payables

The table below summarizes the Group main contractual obligations for finance debt and lease liability repayments, including expected payments for interest charges and liabilities for derivative financial instruments.

| Maturity year
(€ million) | 2026 | 2027 | 2028 | 2029 | 2030 | 2031 and thereafter | Total
December 31, 2025 |  |  |  |  |  |  |
Financial liabilities | 7,982 | 2,793 | 5,492 | 1,944 | 2,139 | 7,908 | 28,258
Lease liabilities | 1,250 | 751 | 581 | 478 | 434 | 2,241 | 5,735
Fair value of derivative instruments | 827 | 41 | 23 | 14 | 12 | 56 | 973
| 10,059 | 3,585 | 6,096 | 2,436 | 2,585 | 10,205 | 34,966
Interest on finance debt | 811 | 699 | 595 | 418 | 360 | 2,529 | 5,412
Interest on lease liabilities | 302 | 244 | 206 | 176 | 150 | 553 | 1,631
| 1,113 | 943 | 801 | 594 | 510 | 3,082 | 7,043
Financial guarantees | 4 |  |  |  |  |  | 4
| Maturity year
(€ million) | 2025 | 2026 | 2027 | 2028 | 2029 | 2030 and thereafter | Total
December 31, 2024 |  |  |  |  |  |  |
Financial liabilities | 8,370 | 2,410 | 2,815 | 5,568 | 2,018 | 8,916 | 30,097
Lease liabilities | 1,261 | 781 | 663 | 572 | 468 | 2,688 | 6,433
Fair value of derivative instruments | 1,921 | 31 | 6 | 48 | 4 | 64 | 2,074
| 11,552 | 3,222 | 3,484 | 6,188 | 2,490 | 11,668 | 38,604
Interest on finance debt | 880 | 705 | 661 | 552 | 369 | 2,786 | 5,953
Interest on lease liabilities | 336 | 284 | 248 | 212 | 184 | 708 | 1,972
| 1,216 | 989 | 909 | 764 | 553 | 3,494 | 7,925
Financial guarantees | 1,106 |  |  |  |  |  | 1,106

Liabilities for leased assets including interest charges for €1,082 million (€925 million at December 31, 2024) pertained to the share of joint operators participating in unincorporated joint operation operated by Eni which will be recovered through a partner-billing process.

The €1,102 million decrease in financial guarantees was due to the termination of independent contracts issued to banks and the Mozambican state oil company ENH on behalf of the consortium of financiers with which the project financing for the development of the Coral discovery's gas reserves was structured.

The table below presents the timing of the expenditures for trade and other payables.

| Maturity year
(€ million) | 2026 | 2027 - 2030 | 2031 and thereafter | Total
December 31, 2025 |  |  |  |
Trade payables | 13,901 |  |  | 13,901
Other payables and advances | 6,360 | 74 | 111 | 6,545
| 20,261 | 74 | 111 | 20,446
| Maturity year
(€ million) | 2025 | 2026 - 2029 | 2030 and thereafter | Total
December 31, 2024 |  |  |  |
Trade payables | 15,170 |  |  | 15,170
Other payables and advances | 6,922 | 59 | 121 | 7,102
| 22,092 | 59 | 121 | 22,272

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Expected payments under contractual obligations 23

In addition to lease, financial, trade and other liabilities represented in the balance sheet, the Company is subject to non-cancellable contractual obligations or obligations, the cancellation of which requires the payment of a penalty. These obligations will require cash settlements in future reporting periods. These liabilities are valued based on the net cost for the company to fulfill the contract, which consists of the lowest amount between the costs for the fulfillment of the contractual obligation and the contractual compensation/penalty in the event of non-performance.

The Company’s main contractual obligations at the balance sheet date comprise take-or-pay clauses contained in the Company’s gas supply contracts or shipping arrangements, whereby the Company obligations consist of off-taking minimum quantities of product or service or, in case of failure, paying the corresponding cash amount that entitles the Company the right to collect the product or the service in future years. The amounts due were calculated on the basis of the assumptions for gas prices and services included in the 2026-2030 industrial plan approved by the Company’s management and for subsequent years on the basis of management’s long-term assumptions.

The table below summarizes the Group principal contractual obligations for the main existing contractual obligations as of the balance sheet date, shown on an undiscounted basis. Amounts expected to be paid in 2026 for decommissioning oil&gas assets and for remediation activities are based on management’s estimates and do not represent financial obligations at the closing date.

| Maturity year
(€ million) | 2026 | 2027 | 2028 | 2029 | 2030 | 2031 and thereafter | Total
Decommissioning liabilities (a) | 911 | 748 | 581 | 539 | 565 | 10,362 | 13,706
Environmental liabilities | 812 | 563 | 438 | 341 | 319 | 1,099 | 3,572
Purchase obligations (b) | 16,750 | 13,397 | 12,393 | 11,372 | 9,068 | 62,467 | 125,447
- Gas |  |  |  |  |  |  |
. take-or-pay contracts | 14,757 | 12,643 | 11,756 | 11,138 | 8,901 | 62,230 | 121,425
. ship-or-pay contracts | 632 | 271 | 254 | 225 | 159 | 211 | 1,752
- Other purchase obligations | 1,361 | 483 | 383 | 9 | 8 | 26 | 2,270
Other obligations | 6 | 15 |  |  |  |  | 21
- Memorandum of intent - Val d’Agri | 6 | 15 |  |  |  |  | 21
Total (c) | 18,479 | 14,723 | 13,412 | 12,252 | 9,952 | 73,928 | 142,746

(a) Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of production life of fields, well-plugging, removal of the structures and site restoration.

(b) Represents any agreement to purchase goods or services that is enforceable and legally binding. For take-or-pay contracts with Gazprom, please refer to the section "Other commitments and risks".

(c) Expected payments under contractual obligations comprise obligations for site abandonment and restoration costs directly associated with assets held for sale for €404 million.

Capital investment and capital expenditure commitments

In the 2026-2030 industrial plan, Eni expects investments and capital expenditures of €29 billion. The table below summarizes Eni’s full-life capital expenditure commitments for property, plant and equipment and capital projects at the closing date. A project is considered to be committed when it has received the appropriate level of internal management approval and for which procurement contracts have usually already been awarded or are being awarded.

The amounts shown in the table below include committed expenditures to execute certain environmental projects.

| Maturity year
(€ million) | 2026 | 2027 | 2028 | 2029 | 2030 | 2031 and thereafter | Total
Committed projects | 6,250 | 4,847 | 3,932 | 2,871 | 1,984 | 304 | 20,188

23 Contractual obligations related to employee benefits are indicated in note 22 - Provisions for employee benefits.

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Other information about financial instruments

| 2025 |  | 2024
| Carrying amount | Income (expense) recognized in |  | Carrying amount | Income (expense) recognized in
(€ million) | Profit and loss account | OCI |  | Profit and loss account | OCI
Financial instruments at fair value with effects recognized in profit and loss account |  |  |  |  |  |  |
Financial assets at fair value through profit or loss (a) | 6,991 | 235 |  |  | 6,797 | 388 |
Non-hedging and trading derivatives (b) | (18) | 559 |  |  | (1,119) | (73) |
Other investments valued at fair value (c) | 1,329 | 242 | (30) |  | 1,395 | 227 | 62
Receivables and payables and other assets/liabilities valued at amortized cost |  |  |  |  |  |  |
Trade receivables and other (d) | 13,216 | (18) |  |  | 17,753 | (106) |
Financing receivables (e) | 4,756 | (49) |  |  | 4,238 | 233 |
Securities (a) | 63 | 1 |  |  | 62 | 1 |
Trade payables and other (a) | 20,446 |  |  |  | 22,273 | (153) |
Financing payables (f) | 28,502 | (296) |  |  | 30,390 | (1,176) |
Net assets (liabilities) for hedging derivatives (g) | (83) | (262) | 865 |  | 7 | (95) | (912)

(a) Income or expense were recognized in the profit and loss account within "Finance income (expense)".

(b) In the profit and loss account, economic effects were recognized as income within "Other operating income (loss)" for €641 million (loss for €352 million in 2024) and in the "Finance income (expense)".

(c) Income or expense were recognized in the profit and loss account within "Income (expense) from investments - Dividends".

(d) Income or expense were recognized in the profit and loss account as net impairments within "Net (impairments) reversals of trade and other receivables" for €11 million (net impairments for €168 million in 2024) and as expense within "Finance income (expense)" for €7 million (income for €62 million in 2024), including interest income calculated on the basis of the effective interest rate of €26 million (interest income for €27 million in 2024).

(e) In the profit and loss account, income or expense were recognized as income within "Finance income (expense)", including interest income calculated on the basis of the effective interest rate of €222 million (interest income for €175 million in 2024) and net reversals for €1 million (net impairments for €22 million in 2024).

(f) In the profit and loss account, income or expense were recognized as expense within "Finance income (expense)", including interest expense calculated on the basis of the effective interest rate of €861 million (interest expense for €897 million in 2024).

(g) In the profit and loss account, income or expense were recognized within "Sales from operations", "Purchase, services and other" and “Finance income (expense)".

Disclosures about the offsetting of financial instruments

(€ million) | Gross amount of financial assets and liabilities | Gross amount of financial assets and liabilities subject to offsetting | Net amount of financial assets and liabilities
December 31, 2025 |  |  |
Financial assets |  |  |
Trade and other receivables | 17,017 | 4,581 | 12,436
Other current assets | 5,076 | 1,133 | 3,943
Other non-current assets | 2,852 | 13 | 2,839
Financial liabilities |  |  |
Trade and other liabilities | 24,842 | 4,581 | 20,261
Other current liabilities | 5,172 | 1,133 | 4,039
Other non-current liabilities | 3,403 | 13 | 3,390
December 31, 2024 |  |  |
Financial assets |  |  |
Trade and other receivables | 21,330 | 4,429 | 16,901
Other current assets | 5,182 | 1,520 | 3,662
Other non-current assets | 4,012 | 1 | 4,011
Financial liabilities |  |  |
Trade and other liabilities | 26,521 | 4,429 | 22,092
Other current liabilities | 6,569 | 1,520 | 5,049
Other non-current liabilities | 4,450 | 1 | 4,449

The offsetting of financial assets and liabilities related to: (i) receivables and payables pertaining to the Exploration & Production segment towards State entities for €4,581 million (€4,429 million at December 31, 2024); (ii) other current and non-current assets and liabilities for derivative financial instruments of €1,133 million (€1,508 million at December 31, 2024) and other assets and liabilities for €13 million (same amount as of December 31, 2024).

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Legal Proceedings

Eni is a party in a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business. Based on information available to date, taking into account the existing risk provisions disclosed in note 21 — Provisions and that in some instances it is not possible to make a reliable estimate of contingency losses, Eni believes that the foregoing will likely not have a material adverse effect on the Group Consolidated Financial Statements.

In addition to proceedings arising in the ordinary course of business referred to above, Eni is party to other proceedings, and a description of the most significant proceedings currently pending is provided in the following paragraphs. Generally, and unless otherwise indicated, these legal proceedings have not been provisioned because Eni has not determined that a negative outcome is probable or because the amount of the provision cannot be estimated reliably.

1. Environment, health and safety

1.1 Criminal proceedings in the matters of environment, health and safety

(i) Eni Rewind SpA – Illegal landfill in Minciaredda area – Porto Torres site. In 2015, the Public Prosecutor of Sassari initiated a criminal case for alleged crimes of unauthorized landfill management and environmental disaster concerning the landfill area, near the western border of the Porto Torres site (Minciaredda area), managed by Eni Rewind which was charged of being liable pursuant to Legislative Decree No. 231/01. This decree states the responsibility of legal entities for the crimes committed by their employees acting on behalf of them. The remediation and clean-up plan of the site filed by Eni Rewind was granted the necessary administrative authorization in July 2018. Upon conclusion of the investigations, the judge of the preliminary hearing resolved that natural persons allegedly liable of environmental crimes and the legal entity would stand trial. The court also resolved that Eni Rewind would be sued for civil liability. The region of Sardegna and other territorial administrations and NGOs were admitted in the proceeding as civil plaintiffs. Subsequently, Eni Rewind was acquitted due to the inability to proceed with the action against it pursuant to Legislative Decree No. 231/01 and definitively excluded from the criminal trial.

In the context of the criminal proceedings against the managers of Eni Rewind, however, on November 13, 2022, the Court of Sassari pronounced an acquittal sentence for the non-existence of the crime of illegal waste and for not having committed the crime of environmental disaster.

Due to the effects of the acquittal, the damage compensation claimed by the civil parties against the defendants and Eni Rewind were rejected. Since the public prosecutor and the civil parties have filed an appeal against the first instance sentence, the judgement is still pending against the Second Instance Court

(ii) Raffineria di Gela SpA and Eni Mediterranea Idrocarburi SpA – Alleged environmental disaster. A criminal proceeding is pending in relation to crimes allegedly committed by the managers of the Raffineria di Gela SpA and Eni Mediterranea Idrocarburi SpA relating to environmental disaster, unauthorized waste disposal and unauthorized spill of industrial wastewater. Raffineria di Gela SpA has been prosecuted for administrative offence pursuant to Legislative Decree No. 231/01. This criminal proceeding initially regarded soil pollution allegedly caused by spills from 14 tanks of the refinery storage, which had not been provided with double bottoms, and pollution of the sea water near the coastal area adjacent to the site due to the failure of the barrier system implemented as part of the clean-up activities conducted at the site. The Public Prosecutor of Gela then merged into this proceeding with the other investigations related to the pollution that occurred at the other sites of the Gela refinery as well as hydrocarbon spills at facilities of Eni Mediterranea Idrocarburi SpA. A first instance acquittal was issued in favor of the defendants and the Company. The proceeding was appealed by the Gela Public Prosecutor's Office. The case is pending to the First Instance Court of Caltanissetta.

(iii) Val d’Agri. In March 2016, the Public Prosecutors of Potenza started a criminal investigation into alleged illegal handling of waste material produced at the Viggiano oil center (COVA), part of the Eni operated Val d’Agri oil complex. The Prosecutors ordered the house arrest of 5 Eni employees and the seizure of certain plants functional to the production activity of the Val d’Agri complex which, consequently, was shut down. From the commencement of the investigation, Eni has carried out several technical and environmental surveys, with the support of independent experts of international standing, who found full compliance of the plant and the industrial process with the requirements of the applicable laws, as well as with best available technologies and best international practices. The Company implemented certain corrective measures to upgrade plants which were intended to address the claims made by the Public Prosecutor about an alleged operation of blending which would have occurred during normal plant functioning. Those corrective measures were favorably reviewed by the Public Prosecutor. The Company restarted the plant in August 2016. In relation to the criminal proceeding, the Public Prosecutor’s Office requested the indictment of all the defendants for alleged illegal trafficking of waste, violation of the prohibition of mixing waste, unauthorized management of waste and other violations, and the Company for administrative offenses pursuant to Legislative Decree No. 231/01. The trial started in November 2017. At the conclusion of the preliminary hearings, the Court of Potenza, on March 10, 2021, acquitted all the defendants in relation to the allegation of false statements in an administrative deed, while in relation to the alleged administrative offenses, the Court found that there was no need to proceed due to the statute of limitations. Finally, in relation to the alleged crime of illegal trafficking of waste, the Court acquitted two former employees of the Southern District for not having committed the crime, convicted six former officials of the same District with suspension of the sentence and sentenced Eni pursuant to Legislative Decree No. 231/01 to pay a fine of €700,000, with the contextual confiscation of a sum of €44,248,071 deemed to constitute the unfair profit obtained from the crime, from which Eni will deduct the amount incurred for the plant upgrade carried out in 2016. Following the filing of the merits of the sentence by the Court, an appeal was promptly filed against all the condemnations. On February 19, 2026, the Court of Potenza issued a judgment of acquittal against Eni, pursuant to Legislative Decree No. 231/01, and its employees, also revoking the confiscation which had been ordered as an alleged unjust profit from the crime.

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(iv) Proceeding Val d’Agri – Tank spill. In February 2017, following the detection of an oil leak from one of the tanks of the COVA, a criminal proceeding for alleged environmental disaster commenced against some former COVA officers, the Operation Managers in charge since 2011 and the HSE Manager in charge at the time of the accident. Eni was investigated too, in relation to the same alleged crimes pursuant to Legislative Decree No. 231/01. In the same year, the Company promptly equipped all COVA tanks with double bottoms, complied with all regulatory requirements, carried out all necessary remediation and safety measures to ensure continuity of oil activities, after a brief shutdown, and provided compensation for damages to all the landlords of areas close to the COVA, which were affected by a spillover.

The Public Prosecutor, at the conclusion of the preliminary investigations, required the indictment for the employees and for Eni pursuant to Legislative Decree No. 231/01 At the outcome of the preliminary hearing the judge issued a sentence not to prosecute the Company for the events up to 2015 because the fact was not envisaged by the law as a crime to claim a legal entity liable for. With reference to the events after 2015, the judge acknowledged the nullity of the request for indictment, thus returning the documents to the Public Prosecutor.

Finally, the judge of the preliminary hearing approved to put on trial two Eni employees before the Court of Potenza, with the allegation of unnamed disaster. Several parties filed an application to bring a civil action and pending assessment of the requests for exclusion presented by the defense with respect to the latter, the Court issued a summons decree from Eni, as civilly liable and Eni duly reconstituted itself. The two proceedings against natural persons - i.e., the ordinary trial and the immediate trial - were then combined by the Court into a single trial, currently pending in the initial phase.

As regards the Company as an entity pursuant to Legislative Decree No. 231/01, the Public Prosecutor issued a new request for indictment, at the end of which the judge ordered the judgment against Eni SpA. The Court annulled this decree due to the indeterminacy of the indictment against the Company, returning the documents to the judge of preliminary hearing, remanding the trial to the preliminary stage, where the Public Prosecutor added the charges. Following the hearing, the judge ordered the Company to be sent for trial before the Court of Potenza.

(v) Raffineria di Gela SpA and Eni Mediterranea Idrocarburi SpA – Waste management of the landfill Camastra. In June 2018, the Public Prosecutor of Palermo (Sicily) notified Eni’s subsidiaries Raffineria di Gela SpA and Eni Mediterranea Idrocarburi SpA of a criminal proceeding relating to allegations of unlawful disposal of industrial waste resulting from the reclaiming activities of soil, which were discharged at a landfill owned by a third party. The Prosecutor charged the then chief executive officers of the two subsidiaries, and the legal entities have been charged with the liability pursuant to Legislative Decree No. 231/01. The alleged wrongdoing related to the willful falsification of the waste certification for purpose of discharging at the landfill. The charges against the CEO of the Refinery of Gela SpA and the company itself were dismissed, while a request to put on trial the CEO of Eni Mediterranea Idrocarburi SpA and the company was approved. The proceeding was transferred to the Court of Agrigento for territorial jurisdiction. On November 26, 2025, following the preliminary hearing, the Court of Agrigento issued a ruling acquitting EniMed’s acting CEO and the company itself, pursuant to Legislative Decree No. 231/01.

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(vi) Versalis SpA – Preventive seizure at the Priolo Gargallo plant. In February 2019, the Court of Syracuse at the request of the Public Prosecutor of Siracusa ordered the seizure of the Priolo/Gargallo plant as part of an ongoing investigation concerning the dangerous disposal of materials and environmental pollution, by the former plant manager of Priolo, as well as of Versalis, pursuant to Legislative Decree No. 231/01. The Public Prosecutor’s thesis, according to the consultants, is that the seized plants had points of emissions that do not comply with the Best Available Techniques (BAT), therefore resulting in violation of the applicable legislation, which determined the annulment of the seizure of the plants in March 2019, evaluating the plant improvements made by Versalis even before the seizure. In March 2021, a notice of conclusion of the preliminary investigations was thus notified, with the formulation by the Public Prosecutor of the allegations already previously stated. At present there is no news of further procedural developments.

(vii) Versalis SpA – Seizure of the treatment plant managed by IAS SpA – Priolo Gargallo. By the end of February 2022, the Public Prosecutor of Syracuse commenced a proceeding relating to alleged crimes of environmental disaster and violation of the legislation on discharges in relation to the industrial waste discharge system of the Versalis plant at the Priolo treatment plant managed by IAS SpA against two former directors of the Versalis plant in Priolo, as well as an employee of Versalis, having then a managerial role in Priolo Servizi. The legal entities Versalis, Priolo Servizi and the other co-located companies were under investigation pursuant to Legislative Decree 231/01.

On June 15, 2022, the Judge for Preliminary Investigations ordered the seizure of the reclamation plant and the shareholding of IAS SpA, with the appointment of a judicial administrator of the assets subject to seizure. Subsequently, the investigations were enlarged to the current manager of the Versalis Plant and to the CEO of Priolo Servizi, who was an employee of Versalis SpA. Versalis SpA challenged the ‘Integrated Environmental Authorization' (“AIA”) issued to IAS before the Regional Administrative Court of Catania only for the part in which the provision is interpreted as imposing new and different limits on discharge, compared to those contained in the authorizations originally granted to the Eni’s subsidiary. In the meantime, the AIA issued for the management of the reclamation plant by IAS has been suspended by the Region of Sicily. Versalis therefore challenged before the TAR the provision to initiate a review of its AIA and, with a separate appeal, the provision of suspension of the AIA of IAS by the Region of Sicily. At the same time, the Public Prosecutor of Syracuse raised the question before the Third Instance Court which, following the hearing on May 7, 2024, declared the constitutional illegitimacy of the provision in the part in which it does not provide for the measures indicated therein to apply for a period of time not exceeding thirty-six months. The order by the judge of preliminary investigations of Syracuse denying authorization to continue production was subsequently revoked by the Court, allowing the petrochemical plant and wastewater treatment plant to operate normally. Meanwhile, the criminal proceeding is ongoing.

(viii) Eni Rewind SpA and Versalis SpA – Mantua. Environmental crime investigation. With regard to the Mantua site, where the company is executing duly authorized environmental activities, in August and September 2020, the Public Prosecutor notified the conclusion of a preliminary investigation relating to several criminal proceedings. Several employees of Eni’s subsidiaries Versalis SpA and Eni Rewind SpA as well as of a third-party company Edison SpA, were notified of being under investigation. Furthermore, the above-mentioned legal entities were being investigated pursuant to Legislative Decree No. 231/01. The Public Prosecutor is alleging, with respect to some specific areas related to the Mantua industrial hub, the crimes of unauthorized waste management, environmental damage and pollution, omitted communication of environmental contamination and omitted clean-up. Following the filing of defense briefs addressed to the investigating authority, the case has been dismissed against some individuals and archived. The Public Prosecutor’s Office then requested the indictment of the remaining defendants. During the Preliminary Hearing, the MITE, the Province of Mantua, the Municipality of Mantua and Mincio Regional Park were allowed in the trial as plaintiffs, while the companies Eni Rewind, Versalis and Edison were instead sued as civil parties and therefore they appeared in court. The Preliminary Hearing Phase ended with the provision of GUP, which ordered the indictment of all the defendants and of the above-mentioned companies, with the exception of a former employee of Versalis and of two Edison employees. The proceeding is pending on the trial phase.

(ix) Eni SpA R&M Depot of Civitavecchia – Criminal proceedings for groundwater pollution. In the period in which Eni was in charge of the Civitavecchia storage hub (2008-2018), pending the approval of a characterization plan of the environmental status of the site, the Company, in coordination with public authorities, adopted measures to preserve the safety of the groundwaters and to pursue the clean-up process of the site until its disposal.

The Public Prosecutor of Civitavecchia contested, among others, the former manager of the Eni fuel storage hub of Civitavecchia, the alleged crime of environmental pollution. Eni is under investigation pursuant to Legislative Decree No. 231/01. The first instance proceeding is underway.

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(x) Eni SpA R&M Genoa Pegli storage hub – Criminal proceeding for crude oil spill – September 2022. Following a crude oil spill that occurred at the Genoa Pegli depot on September 27, 2022, the Public Prosecutor's Office of Genoa instituted criminal proceedings for the alleged crime of culpable environmental disaster, charged against four Eni employees, while the Company is charged with an administrative offense pursuant Legislative Decree No. 231/01. The proceeding is pending in the preliminary investigation phase.

(xi) Sannazzaro Refinery – Proceeding in relation to alleged criminal environmental pollution and discharge – Public Prosecutor's Office of Pavia. A criminal proceeding is pending for alleged crimes of environmental pollution and lack of remediation against some pro-tempore directors and HSE managers of the refinery located at Sannazzaro de' Burgondi who are under investigation, as well as Eni SpA pursuant to the Legislative Decree no. 231/2001, in relation to the alleged crime of environmental pollution on site, with a seizure of the sewage treatment plant (TAE), and possible expansion of the area affected by possible pollution beyond the site's hydraulic barriers.

On November 28, 2023, the TAE plant was released from seizure. The Prosecutor's Office has ordered three unrepeatable technical investigations, during which there are further complaints regarding further environmental complaints. At the conclusion of the preliminary investigation phase, the allegations raised were confirmed.

(xii) Eni SpA – Pomezia depot – Involuntary environmental pollution. A criminal proceeding is ongoing concerning an alleged crime of pollution of groundwater underlying the fuel depot in Pomezia attributable, according to the indictment, to product leaks from the tanks.

The Public Prosecutor's Office has appointed its consultants to carry out a technical review of the site to verify the state of environmental contamination at the tanks. As a result of these assessments, two Eni's employees as well as Eni SpA pursuant to Legislative Decree no. 231/01 were notified of being under investigation for the alleged crime. Subsequently, the Public Prosecutor issued a request for indictment and, following the preliminary hearing, the trial was issued. The proceeding is pending at the stage of initiation of the first instance judgement.

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(xiii) Eni SpA – Calenzano depot – explosion. The proceeding concerns the fatal accident which caused the death of five contractors of Eni due to an explosion occurred during the carrying out of operations at the fuel storage site in Calenzano (Florence) on December 9, 2024, and the consequential order of seizure of the site from the Judicial authorities. The proceeding was initially charged against unknown persons for aggravated multiple involuntary manslaughter, willful omission of precautions against accidents at work and unnamed disaster. The Public Prosecutor's Office appointed a pool of technical consultants to ascertain dynamics and causes of the event and identify any responsibilities and, in the course of the investigations carried out so far, several perquisitions were executed with the acquisition of all the requested documentation spontaneously delivered by the Company. Recently, the Public Prosecutor's Office has notified a notice of investigation against the Employer and Manager of the Calenzano storage hub and other Managers and operators of technical operational areas related to the activities of the site, as well as two employees of a supplier, for the alleged crime of complicity in multiple involuntary manslaughter, complicity in multiple negligent personal injuries and complicity in unnamed negligent disaster, as well as against Eni SpA pursuant to Legislative Decree 231/01. At the same time, the Public Prosecutor's Office has requested a probatory incident from the Judge for Preliminary Investigations to carry out an expert assessment.

The Company is collecting all requests for compensation in relation to any material and non-material damage that has occurred for their settlement, regardless of any aspect of the merits of the matter. A provision has been accrued considering an estimate of the damage resulting from the event. The case is still pending in the preliminary investigation phase.

(xiv) Enimed SpA – attempted environmental pollution. The investigation involves the last three CEOs of Enimed SpA and its employees who, since 2020, have held the positions of HSE and Permitting Manager, OPEM and TECEM Manager, Central Manager, Field Manager, and Plant Manager, as well as Enimed pursuant to Legislative Decree 231/01, for the alleged crime of complicity in attempted environmental pollution for having allegedly failed, each within their respective areas of responsibility, to adopt the appropriate precautions necessary to prevent the environmental dispersion, which did not occur, of the so-called fluxing product. On January 14, 2025, the Public Prosecutor's Office od Gela issued a notice of conclusion of the preliminary investigations and subsequently requested indictment. The proceedings are pending at the preliminary hearing stage.

1.2 Civil and administrative proceedings in the matters of environment, health, safety and antitrust

(i) Republic of Kazakhstan / Eni SpA, Agip Karachaganak BV et al. The Republic of Kazakhstan (“Rok”) promoted an international arbitration against the consortium of international oil companies that manage the Karachaganak fields, pursuant to the Final Production Sharing Agreement which governs the project activities (Eni’s share 29.25%). Rok is claiming a revision of the cost recovery of the companies in the period 2010-2020 and formally started the proceedings in March 2023 with the appointment of an arbitrator. In April 2024, Rok presented its statements of claim, and the proceeding is now underway. Regarding some of the objections raised by RoK, the arbitral tribunal issued a partial award partly in favor of RoK and partly in favor of the consortium, without quantification. Eni is evaluating the merit of these requests and therefore it is not possible to reliably estimate the outcome of the proceedings.

(ii) Republic of Kazakhstan / Agip Caspian Sea BV et al. The Republic of Kazakhstan (“Rok”) promoted a further international arbitration, pursuant to the North Caspian Sea Production Sharing Agreement “NCSPSA” against the Contractor (Eni’s share 16.67%). The Claims advanced by the Republic refer to alleged violations of the NCSPSA, including cost recovery exceptions and failure to pursue development opportunities. In February 2026, the consortium initiated an ICSID arbitration to protect its investment in the face of RoK's complaints regarding sulfur management. Eni is continuing to evaluate the merit of the arbitration claims in light of the available investigative evidence and, therefore, it is not possible to estimate the outcome of the proceedings.

(iii) Novamont SpA – Proceedings by the Italian Antitrust Authority against Novamont SpA and Eni SpA for alleged abuse of dominant position in the market of bioplastics. In 2024, ACGM initiated a proceeding against Novamont SpA, also notifying Eni SpA, for alleged abuse of dominant position in the bioplastics market, specifically bio compounds to produce plastic bags for large-scale retailers. On June 24, 2025, AGCM, confirming the charges formalized at the conclusion of the investigation against Novamont and Eni SpA, the latter for the period following the date of acquisition of control (October 18, 2023), imposed an administrative fine of €32 million (of which approximately €2 million jointly and severally between the two companies) for alleged abuses of dominant position in the relevant markets between January 1, 2018, and December 31, 2023. AGCM warned Novamont and Eni to cease their alleged behavior in violation of antitrust rules and provide proof of this to the Authority within a specified deadline. The Company believes to have valid arguments supporting the correctness of its actions to be asserted in the subsequent stages of opposition to the AGCM's decision; therefore, an appeal has been filed with the Regional Administrative Court of Lazio. A provision has been set aside to address this dispute.

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(iv) Eni Rewind SpA – Versalis SpA – Eni SpA (R&M) – Augusta Harbor. The complex administrative dispute relating to the environmental status of the Augusta harbor commenced in September 2017 with a formal notice issued by the Ministry of the Environment against the companies operating at the Priolo petrochemical hub, including Eni Rewind, Polimeri Europa (now Versalis) and Eni (R&M), to present projects for sediments removal from the harbor on the basis of an alleged assessment of responsibility as per a ruling of the Regional Administrative Court of Catania in 2012. The Ministry on various occasions reiterated its own assessment of the environmental responsibility of the companies co-located at the Priolo hub with respect to the pollution of the harbor and warned them against carrying out remediation activities. Following various meetings held with the Ministry of the Environment, Eni Rewind offered to define and to plan for certain environmental remediation activities based on updated environmental data. The Eni’s subsidiary also commenced activities to identify the persons responsible for the pollution of the harbor and their respective shares of liability.

In September 2020 Eni Rewind took part in the Investigation Services Conference convened by the Ministry of the Environment and the competent bodies and presented a review of the environmental status of the Rada which stated that pollution was attributable to industrial activities of prior periods and that it would not spread into the surrounding environment.

Between the end of 2023 and the beginning of 2024, the Catania Regional Administrative Court issued a ruling on all the appeals presented by the operators, deeming them as inadmissible, because the injunction does not constitute an act suitable for having legal efficacy with respect to the appellants. The Court did not take a position on the existence of the pollution or otherwise did not make any conclusion about responsibility regarding the pollution of the harbor, limiting itself to highlighting the fact that the proceeding administration believes that the pollution is matter of fact. For this reason, on June 27, 2024, the Group companies challenged the TAR sentences limited to an interpretation of the same as confirming the existence of a final judgment on the responsibility for the contamination.

(v) Val d’Agri – Eni / Vibac. In September 2019 a claim was brought in the Court of Potenza against Eni. The plaintiffs are 80 people living in different municipalities of the Val d’Agri area, who are complaining of economic, non-economic, biological and moral damages, all deriving from the presence of Eni’s oil facilities in the territory. The Judge has been asked to ascertain Eni's responsibility for causing emissions of polluting substances into the atmosphere. The plaintiffs have also requested that Eni be ordered to interrupt any polluting activity and be allowed to resume industrial activities on condition that all the necessary remediation measures be implemented to eliminate all of the alleged dangerous situations. Finally, they are asking Eni for compensation for damages. At the end of the trial phase, the Judge submitted to the parties the proposal for an extra-judicial settlement, fixing a deadline to present further proposals on the matter.

The parties did not adhere to the conciliatory proposal. The Judge deemed the case ripe for a decision and set the hearing to clarify the conclusions for July 10, 2026.

(vi) Eni Rewind SpA / Province of Vicenza – Clean-up process for Trissino site. On May 7, 2019, the Province of Vicenza issued a warning, imposing on certain individuals and companies such as MITENI SpA in bankruptcy, Mitsubishi and ICI the obligation to clean-up the Trissino site where MITENI carried out its industrial activity. Based on the analysis carried out by administrative parties, significant concentrations of substances considered highly toxic and carcinogenic were allegedly discovered in groundwater and in surface water at this site. The analysis carried out by the Province of Vicenza with the direct involvement of the Istituto Superiore di Sanità reported the presence of these substances in the blood of about 53,000 people in the area. The Province warned some individuals, including a former employee who served between 1988 and 1996 as CEO of EniChem, a company that was subsequently acquired by Eni Rewind.

Eni Rewind was summoned as the “successor” of EniChem in several appeals before the Regional Administrative Court as the majority shareholder of MITENI, as well as liable for the potential contamination of Trissino plant (together with other subjects). The Province extended the proceeding also to Eni Rewind, which filed a counterclaim for having its position taken out of the procedure.

Eni Rewind appealed to a Regional Administrative Court against the Province claims and orders. Eni Rewind is carrying out environmental interventions and has made itself available to carry out - as part of the project approved by the territorial administrations in charge- further anti-pollution interventions on a voluntary basis and without giving any acquiescence with respect to the liability charges for the pollution by chemical agents. The Province extended the identification of the person responsible for the pollution also to Manifatture Lane Marzotto & Figli Spa which challenged the relevant provision before the Regional Administrative Court. This act was also challenged by ICI3 and Eni Rewind in the part in which, unlike what was ordered by the Province towards the other companies identified as responsible for the pollution, it does not order Manifatture Lane Marzotto & Figli SpA to carry out the environmental interventions. With sentences issued in May 2024, the Regional Administrative Court ruled on the appeals brought by ICI3 and Mitsubishi regarding the measure to identify the person responsible for the pollution. The administrative judge rejected the appeals, deeming the Province’s actions legitimate. Similarly, with a ruling dated December 27, 2024, the Regional Administrative Court also rejected Eni Rewind's appeal, confirming the identification measures adopted by the Province as responsible for the pollution. The Company appealed the sentence. Discussions are underway with the companies involved to reach a transaction agreement regarding cleanup and remediating costs of the site.

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(vii) Eni SpA – Greenpeace Onlus, ReCommon APS and others – Climate dispute. On May 9, 2023, the NGOs Greenpeace Onlus and ReCommon APS, together with 12 private citizens, summoned Eni, the Ministry of Economy and Finance (MEF) and an Italian agency, Cassa Depositi e Prestiti (CDP), before the Civil Court of Rome based on allegations of climate change responsibility. The plaintiffs claimed economic losses and other damages and requested that Eni revise its decarbonisation strategy (for example by reducing by 45% its emissions by 2030 compared to 2020 levels, or other appropriate measures to comply with the Paris Agreement) as well as the cessation of any harmful conducts.

The parties appeared in Court, promptly filing deeds and documents. On June 10, 2024, the plaintiffs promoted a separate proceeding for the settlement of jurisdiction, remitting the final decision regarding the jurisdiction of the Court of Rome seized of the merits proceedings to the Third Instance Court. On July 11, 2024, the Court of Rome ordered the suspension of the proceedings on the merits until the definition of the jurisdiction regulation proposed by the plaintiffs. Eni appeared before the Third Instance Court. On January 30, 2026, the judge rejected the plaintiff's request to open an investigation phase. The proceeding is ongoing.

(viii) Eni SpA – NAOC / Egbema Voice of Freedom Association - Request for compensation for damages. On November 30, 2023, Eni SpA was notified of a summons relating to a claim advanced by Pastor Nicholas Evaristus Ukaonu, by the Advocates for Community Alternatives association and by the Egbema Voice of Freedom association, for alleged damages deriving from constructions created by NAOC in Nigeria in the territory of the communities represented by the associations. The Pastor and the associations ask for joint compensation from Eni and NAOC for approximately €48 million in addition to the execution of works which, according to the plaintiff, would be necessary to avoid and contain flooding caused by constructions created by NAOC. The application submitted reiterates complaints made in past years, including in 2017 before the National Contact Point envisaged by the OECD Guidelines addressed to Multinational enterprises, where an ad hoc conciliation procedure was initiated which ended with an agreement between the parties. The first hearing was held on December 10, 2024. At the hearing the judge unsuccessfully attempted conciliation and subsequently each party recalled what was deduced in the documents and Eni requested that the case be decided without further preliminary investigation. The Judge reserved the sentence.

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(ix) Eni Rewind SpA / Calabria Region – Province and Municipality of Crotone – WWF Italy – ARCI and others (Regional Administrative Court of Catanzaro). A decree of the Ministry of the Environment of August 1, 2024 n. 27 ordered the beginning of excavations for the execution of the reclamation of the Site of National Interest of Crotone upon the occurrence of certain conditions and ordered the Calabria Region to start the procedure for removing the constraint from Single Regional Authorization Provision (“PAUR”), which authorized the construction of the D15 - preliminary deposit and D9 plants. Several public entities, as well as the WWF and ARCI associations have challenged the decree with a precautionary application before the Regional Administrative Court. The constraint imposed by the Region in the PAUR obliges Eni Rewind to dispose of waste outside the regional territory; various checks carried out by the Company and confirmed by public entities have confirmed that the only authorized plant capable of receiving hazardous waste from the reclamation is in Crotone. This conclusion was also substantially confirmed by scouting among foreign operators (provided for by the ministerial decree) from which it emerged that only 2 entities (out of almost 30 contacted) are available to accept the hazardous waste coming from the reclamation of the site of Crotone, in a context characterized by regulatory, administrative, timing and logistical uncertainties that are not compatible with the reclamation timetable. The Region's resistance to removing the restrictions has so far prevented the start of remediation activities at the site. WWF and ARCI also challenged the order of the Ministry (dated September 24, 2024) requiring Eni Rewind to commence remediation activities. The Company carried out all the preparatory activities for the beginning of the work, implementing the provisions of the Decree. In January 2025, the local authorities warned Eni Rewind and the company in charge of the Crotone landfill not to sign the waste disposal contract and therefore, the remediation activities have yet to start. Eni Rewind (and Edison) appealed against these warnings to the Regional Administrative Court, which requested a report on the environmental remediation plan from the Ministry. The ruling of the Regional Administrative Court of June 2025, while supporting the institutions’ position, does not represent a negative development, since the Ministry has initiated a procedure aimed at defining the modalities for the continuation of the environmental interventions.

(x) Eni SpA – Proceedings by the Italian Antitrust Authority against Eni SpA for alleged collusion on fixing the price of the "bio component" of automotive fuels. A proceeding is pending before the Italian Antitrust Authority (AGCM), which involves Eni SpA and, since January 1, 2023, its subsidiary Enilive SpA, which took over the parent company in managing the retail fuel sales business, for alleged collusion with competitors in the Italian retail market of automotive fuel aimed at fixing the cost of the bio component of fuels sold in Italy, in violation of antitrust regulations. The Authority believes that the agreement was implemented through information exchanges and other initiatives with a view to coordinating final sales prices. The Authority formalized the charges against Eni and its subsidiary upon conclusion of the preliminary investigation. The Company filed its defense briefs. On September 26, 2025, the AGCM imposed a significant fine to Eni for alleged collusive commercial practices in violation of the competition laws. Eni believes that the findings of the Authority are groundless and that the Company has always been conducting the business in a transparent way and in full compliance with applicable competition rules. On November 25, 2025, Eni filed a judicial appeal with the Regional Administrative Court of Lazio. Risk provision has been accrued for this proceeding.

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2. Settled proceedings

(i) Eni Rewind SpA – Crotone omitted clean-up. The criminal proceeding initiated in 2017 by the Public Prosecutor of Crotone regarding alleged crimes related to site remediation activities carried out by Eni Rewind was dismissed without any charges being filed against Eni.

(ii) Eni SpA – Fatal accident Ancona offshore platform. The criminal proceeding relating to a fatal accident that occurred on an Eni platform in 2019 involving two contractors concluded with the definitive acquittal of Eni employees under investigation and of the entity itself under investigation pursuant to Legislative Decree No. 231/01.

(iii) Raffineria di Gela SpA and Eni Rewind SpA – Groundwater pollution survey and reclamation process of the Gela site. The criminal proceedings brought by the Gela Public Prosecutor's Office against the subsidiaries Eni Rewind SpA / Raffineria di Gela SpA and some of their employees have been concluded. The charges related to alleged crimes of environmental pollution, omitted clean-up, negligent personal injury and illegal waste management, in connection with the decommissioning and clean-up of several abandoned areas of the Gela Refinery, carried out by Eni Rewind, including on behalf of other co-located companies. The Gela Court acquitted all defendants on the grounds that the facts were unfounded. The ruling was not appealed and is therefore final.

(iv) Eni SpA – Eni Rewind SpA – Raffineria di Gela SpA – Claim for preventive technical inquiry and judgments on the merits. The civil proceeding seeking compensation for the alleged causality between certain pathologies and the alleged industrial pollution at the Gela site was concluded without any charges being filed against Eni.

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Assets under concession arrangements

Eni operates under concession arrangements mainly in the Exploration & Production segment and in the Enilive business line. In the Exploration & Production segment, contractual clauses governing mineral concessions, licenses and exploration permits regulate the access of Eni to hydrocarbon reserves. Such clauses can differ in each country. In particular, mineral concessions, licenses and permits are granted by the legal owners and, generally, entered into with government entities, State oil companies and, in some legal contexts, private owners. Pursuant to the assignment of mineral concessions, Eni sustains all the operational risks and costs related to the exploration and development activities and it is entitled to the productions realized. In respect of the mining concessions received, Eni pays royalties in accordance with the tax legislation in force in the country and is required to pay income taxes deriving from the exploitation of the concession. In production sharing agreement and service contracts, realized productions are defined based on contractual agreements with State oil companies, which hold the concessions. Such contractual agreements regulate the recovery of costs incurred for the exploration, development and operating activities (Cost Oil) and give entitlement to the own portion of the realized productions (Profit Oil). In the Enilive business line, several service stations and other auxiliary assets of the distribution service are located in the motorway areas and they are granted by the motorway concession operators following a public tender for the sub-concession of the supplying of oil products distribution service and other auxiliary services. In exchange for the granting of the services described above, Eni provides to the motorway companies fixed and variable royalties based on quantities sold. At the end of the concession period, all non-removable assets are transferred to the grantor of the concession for no consideration.

Environmental regulations

In the future, Eni will sustain significant expenses in relation to compliance with environmental, health and safety laws and regulations and for reclaiming, safety and remediation works of areas previously used for industrial production and dismantled sites. In particular, regarding the environmental risk, management does not currently expect any material adverse effect upon Eni’s Consolidated Financial Statements, taking account of ongoing remediation actions, existing insurance policies and the environmental risk provision accrued in the Consolidated Financial Statements. However, management believes that it is possible that Eni may incur material losses or significant responsibilities because, at the current state of knowledge, it is impossible to forecast the effects of future developments taking into account, among other things, the following aspects: (i) the possibility of as yet unknown contamination; (ii) the results of ongoing surveys and other possible effects of statements required by Legislative Decree 152/2006; (iii) new developments in environmental regulation (i.e. Law No. 68/2015 on crimes against the environment and European Directive 2015/2193 on medium combustion plants); (iv) the effect of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, as against other potentially responsible parties with respect to such litigation and the possible insurance recoveries.

Emission trading

From 2021, the fourth phase of the European Union Emissions Trading Scheme (EU-ETS) came in force. The award of free emission allowances is performed based on emission benchmarks defined at European level specific to each industrial segment, except for the electric power generation sector that is not eligible for allocations for no consideration. At the same time, emissions trading (UK ETS) was introduced in the United Kingdom, the rules of which are largely similar to those of the EU-ETS. This regulatory scheme implies for Eni’s plants subject to emission trading a lower assignment of emission permits compared to the emissions recorded in the relevant year and, consequently, the necessity of covering the amounts in excess by purchasing the relevant emission allowances on the open market. In 2025, the emissions of carbon dioxide from Eni’s plants were higher than the free allowances assigned to Eni. Against emissions of carbon dioxide amounting to approximately 16.4 million tonnes, Eni was awarded free emission allowances of 5.1 million tonnes, determining a deficit of 11.3 million tonnes. This deficit was entirely covered through the purchase of emission allowances in the open market, with delivery in 2026.

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29 Revenues and other income

Sales from operations

(€ million) | Exploration & Production | Global Gas & LNG Portfolio and Power | Refining and Chemicals | Enilive | Plenitude | Corporate and Other activities | Total
2025 |  |  |  |  |  |  |
Sales from operations | 37,109 | 13,102 | 5,223 | 16,337 | 10,118 | 262 | 82,151
Sales of crude oil | 27,394 |  | 7 |  |  |  | 27,401
Sales of oil products | 4,316 |  | 1,526 | 15,818 |  |  | 21,660
Sales of natural gas and LNG | 4,899 | 9,982 | 1 |  | 3,640 |  | 18,522
Sales of petrochemical products |  |  | 2,954 |  |  |  | 2,954
Sales of power |  | 2,534 | 1 |  | 3,994 |  | 6,529
Sales of other products | 49 | 2 | 370 | 88 | 77 | 63 | 649
Services | 451 | 584 | 364 | 431 | 2,407 | 199 | 4,436
Products sales and service revenues | 37,109 | 13,102 | 5,223 | 16,337 | 10,118 | 262 | 82,151
Transfer of goods/services |  |  |  |  |  |  |
Goods/Services transferred in a specific moment | 36,694 | 12,945 | 5,169 | 16,337 | 10,111 | 138 | 81,394
Goods/Services transferred over a period of time | 415 | 157 | 54 |  | 7 | 124 | 757
2024 |  |  |  |  |  |  |
Sales from operations | 38,875 | 15,061 | 5,881 | 18,670 | 10,124 | 186 | 88,797
Sales of crude oil | 28,151 |  |  |  |  |  | 28,151
Sales of oil products | 4,058 |  | 1,518 | 18,165 |  |  | 23,741
Sales of natural gas and LNG | 6,039 | 12,480 | 2 |  | 3,620 |  | 22,141
Sales of petrochemical products | 253 |  | 3,667 |  |  |  | 3,920
Sales of power |  | 2,244 | 1 |  | 4,073 |  | 6,318
Sales of other products | 40 | 16 | 326 | 62 | 67 | 7 | 518
Services | 334 | 321 | 367 | 443 | 2,364 | 179 | 4,008
Products sales and service revenues | 38,875 | 15,061 | 5,881 | 18,670 | 10,124 | 186 | 88,797
Transfer of goods/services |  |  |  |  |  |  |
Goods/Services transferred in a specific moment | 38,557 | 14,963 | 5,844 | 18,670 | 10,124 | 61 | 88,219
Goods/Services transferred over a period of time | 318 | 98 | 37 |  |  | 125 | 578
2023 |  |  |  |  |  |  |
Sales from operations | 37,961 | 19,468 | 6,188 | 18,877 | 11,040 | 183 | 93,717
Sales of crude oil | 25,685 |  |  |  |  |  | 25,685
Sales of oil products | 5,219 |  | 1,847 | 18,442 |  |  | 25,508
Sales of natural gas and LNG | 5,881 | 16,638 |  |  | 4,431 |  | 26,950
Sales of petrochemical products | 766 |  | 3,619 |  |  |  | 4,385
Sales of power |  | 2,420 |  |  | 4,832 |  | 7,252
Sales of other products | 44 | 38 | 305 | 28 | 91 | 3 | 509
Services | 366 | 372 | 417 | 407 | 1,686 | 180 | 3,428
Products sales and service revenues | 37,961 | 19,468 | 6,188 | 18,877 | 11,040 | 183 | 93,717
Transfer of goods/services |  |  |  |  |  |  |
Goods/Services transferred in a specific moment | 37,626 | 19,383 | 6,147 | 18,645 | 11,040 | 64 | 92,905
Goods/Services transferred over a period of time | 335 | 85 | 41 | 232 |  | 119 | 812

(€ million) | 2025 | 2024 | 2023
Revenues associated with contract liabilities at the beginning of the period | 287 | 87 | 642
Revenues associated with performance obligations totally or partially satisfied in previous years | (128) | 7 | 1,087

As a result of international sanctions against Russian upstream companies, joint operators of Eni in operated projects, in application of the contractual clauses that regulate the related JOA, Eni has taken over the ownership of the rights and obligations of the sanctioned partner, thus proceeding to acquire the production shares, revenues of €87 million, costs pertaining to the partner and suspending the economic margin of the operations.

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Sales from operations by industry segment and geographic area of destination are disclosed in note 35 – Segment information and information by geographic area.

Sales from operations with related parties are disclosed in note 36 – Transactions with related parties.

Other income and revenues

(€ million) | 2025 | 2024 | 2023
Gains from sale of assets and businesses | 25 | 48 | 27
Other proceeds | 1,453 | 2,369 | 1,072
| 1,478 | 2,417 | 1,099

Other proceeds include: (i) €160 million (€194 million and €121 million in 2024 and 2023, respectively) related to the recovery of the cost share of right-of-use assets pertaining to partners of unincorporated joint operations operated by Eni; (ii) in 2024, €1,048 million relating to the agreement with an Italian operator to share environmental expenses which provides Eni with a reimbursement for past and future costs already allocated to environmental provision.

Other income and revenues with related parties are disclosed in note 36 – Transactions with related parties.

30 Costs

Purchase, services and other charges

(€ million) | 2025 | 2024 | 2023
Production costs - raw, ancillary and consumable materials and goods | 51,014 | 54,204 | 58,170
Production costs - services | 12,433 | 12,217 | 11,512
Lease expense and other | 1,356 | 1,512 | 1,432
Net provisions for contingencies | 1,117 | 1,397 | 1,369
Other expenses | 1,694 | 2,073 | 1,746
| 67,614 | 71,403 | 74,229
less: |  |  |
- capitalized direct costs associated with self-constructed assets - tangible assets | (368) | (227) | (367)
- capitalized direct costs associated with self-constructed assets - intangible assets | (190) | (62) | (26)
| 67,056 | 71,114 | 73,836

Purchase, services and other charges included geological and geophysical expenses of Exploration & Production segment for €174 million (€186 million and €205 million in 2024 and 2023, respectively).

Costs incurred in connection with research and development activities and technological improvement expensed through profit and loss, as they did not meet the requirements to be recognized as long-lived assets, amounted to €207 million (€178 million and €166 million in 2024 and 2023, respectively).

Royalties on the extraction rights of hydrocarbons amounted to €984 million (€1,122 million and €1,138 million in 2024 and 2023, respectively).

Charges to provisions related to: (i) environmental provisions for €559 million (€848 million and €559 million in 2024 and 2023, respectively); (ii) reversal of decommissioning provisions for €9 million (net additions of €300 million and €305 million in 2024 and 2023, respectively); (iii) a €268 million increase in legal proceedings provisions (net additions of €40 million and net reversals of €87 million in 2024 and 2023, respectively). More information is provided in note 21 – Provisions. Net additions to provisions by segment are disclosed in note 35 – Segment information and information by geographical area.

Information about leases is disclosed in note 13 – Right-of-use assets and lease liabilities.

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Payroll and related costs

(€ million) | 2025 | 2024 | 2023
Wages and salaries | 2,620 | 2,665 | 2,427
Social security contributions | 541 | 527 | 497
Cost related to employee benefit plans | 64 | 96 | 156
Other costs | 135 | 123 | 196
| 3,360 | 3,411 | 3,276
less: |  |  |
- capitalized direct costs associated with self-constructed assets - tangible assets | (116) | (139) | (131)
- capitalized direct costs associated with self-constructed assets - intangible assets | (15) | (10) | (9)
| 3,229 | 3,262 | 3,136

Other costs comprised provisions for redundancy incentives of €70 million (€66 million and €56 million in 2024 and 2023, respectively) and costs for defined contribution plans of €110 million (€104 million and €102 million in 2024 and 2023, respectively).

Cost related to employee benefit plans are described in note 22 – Provisions for employee benefits.

Costs with related parties are disclosed in note 36 – Transactions with related parties.

Average number of employees

The average number of employees of the companies included in the consolidation area, and the breakdown by category is reported as follows:

| 2025 | 2024 | 2023
(number) | Subsidiaries | Joint operations | Subsidiaries | Joint operations | Subsidiaries | Joint operations
Senior managers | 902 | 18 | 933 | 19 | 944 | 19
Junior managers | 9,315 | 89 | 9,257 | 90 | 9,157 | 84
Employees | 15,965 | 452 | 16,086 | 431 | 15,810 | 420
Workers | 5,414 | 266 | 5,719 | 282 | 5,937 | 294
| 31,596 | 825 | 31,995 | 822 | 31,848 | 817

The average number of employees was calculated as the average between the number of employees at the beginning and the end of the year.

The average number of senior managers included managers employed in foreign countries, whose position is comparable to a senior manager’s status.

Long-term share-based incentive plan for Eni’s managers

The main terms of the incentive plans for Eni executives with shares whose awards are in place at the end of the 2025 financial year are set out below.

Two long-term incentive plans, 2020-2022 and 2023-2025, ratified by the Shareholders' Meeting, are in place. These plans provide for the award of up to 20 million and 16 million treasury shares, respectively, each divided into three annual awards, which are intended for Eni's CEO and the executives of Eni and its subsidiaries who qualify as “senior managers deemed critical for the business”, selected among those who are in charge of tasks directly linked to the Group results or of strategic clout to the business. The Plans provide the granting of Eni shares for no consideration to eligible managers after a three-year vesting period under the condition that they would remain in office until vesting.

The vesting characteristics of the Plans are linked to the achievement of the objectives established by the Company in terms of financial results, appreciation of the shares compared to a group of Eni's competitors ("Peer Group") and achievement of certain environmental sustainability and emissions reduction KPIs.

Depending on the performance of the parameters mentioned above, the number of shares that will vest free of charge after three years may range between 0% and 180% of the initial award. The plans include lock-up and claw back clauses.

The number of shares awarded at the grant date upon achievement of the vesting conditions was 5.78 shares, with a weighted average fair value of €10.6 per share.

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The estimation of the fair value was calculated by adopting specific valuation techniques regarding the different performance parameters provided by the plans (stochastic method), taking into account the fair value of the Eni share at the grant date, reduced by dividends expected along the vesting period, considering the volatility of the stock, the forecasts relating to the trend of the performance parameters, as well as the lower value attributable to the shares considering the lock-up clause.

The costs related to the long-term monetary incentive plan, recognized as a component of the payroll cost with counterpart in equity reserves as they pertain to company employees, amounted to €20 million (€23 million and €20 million in 2024 and 2023, respectively).

Employee Stock Ownership Plan

The Shareholders' Meeting held on May 15, 2024, authorized the adoption of an Employee Stock Ownership Plan, with the aim of strengthening motivation and retention across the company and participation in the growth of corporate value, in line with the interests of the shareholders. The Plan provides for three annual awards in the period 2024-2026 intended for employees of Eni and its subsidiaries.

For 2025, Eni has awarded shares for no consideration to employees in Italy (as in 2024) and abroad. A three-year lock-up period applies to each award.

At the grant date (November 27, 2025), a total of 3,289,345 shares were issued, and at the 2024 grant date (November 27, 2024), 3,102,700 shares.

Costs relating to the Employee Stock Ownership Plan, recognized as a component of payroll cost amounted to €15 million (€1 million in 2024) with counterpart in equity reserves.

Compensation for key management personnel

Compensation, including contributions and collateral expenses, of personnel holding key positions in planning, directing and controlling the Eni Group subsidiaries, including executive and non-executive officers, general managers and managers with strategic responsibilities in office during the year consisted of the following:

(€ million) | 2025 | 2024 | 2023
Wages and salaries | 24 | 39 | 35
Post-employment benefits | 2 | 4 | 3
Other long-term benefits | 16 | 23 | 19
| 42 | 66 | 57

Compensation of Directors and Statutory Auditors of Eni SpA

Compensation of Directors amounted to €11.8 million, €12.9 million and €13.9 million in 2025, 2024 and 2023, respectively. Compensation of Statutory Auditors amounted to €0.5 million, €0.5 million and €0.6 million in 2025, 2024 and 2023, respectively.

Compensation included emoluments and social security benefits and social assistance due for the office as Director or Statutory Auditor held at the parent company Eni SpA or other Group subsidiaries, which was recognized as a cost to the Group.

31 Finance income (expense)

(€ million) | 2025 | 2024 | 2023
Finance income | 7,196 | 7,715 | 7,417
Finance expense | (8,170) | (8,980) | (8,113)
Net finance income (expense) from financial assets at fair value through profit or loss | 235 | 388 | 284
Income (expense) from derivative financial instruments | (80) | 278 | (61)
Finance income (expense) | (819) | (599) | (473)

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The analysis of finance income (expense) was as follows:

(€ million) | 2025 | 2024 | 2023
Finance income (expense) related to net borrowings |  |  |
Interest and other finance expense on ordinary bonds | (774) | (827) | (667)
Net finance income (expense) on financial assets held for trading | 243 | 367 | 250
Net expenses on other financial assets valued at fair value with effects on profit and loss | (8) | 21 | 34
Interest and other expense due to banks and other financial institutions | (252) | (358) | (207)
Interest on lease liabilities | (348) | (314) | (267)
Interest from banks | 191 | 294 | 356
Interest and other income on financial receivables and securities held for non-operating purposes | 205 | 161 | 14
| (743) | (656) | (487)
Exchange differences | 133 | (38) | 255
Income (expense) from derivative financial instruments | (80) | 278 | (61)
Other finance income (expense) |  |  |
Interest and other income on financing receivables and securities held for operating purposes | 39 | 44 | 153
Capitalized finance expense | 122 | 222 | 94
Finance expense due to the passage of time (accretion discount) (a) | (250) | (261) | (341)
Other finance income (expense) | (40) | (188) | (86)
| (129) | (183) | (180)
| (819) | (599) | (473)

(a) The item relates to the increase in provisions for contingencies that are shown at present value in non-current liabilities.

Information about leases is disclosed in note 13 – Right-of-use assets and lease liabilities.

The analysis of derivative financial instruments is disclosed in note 24 – Derivative financial instruments and hedge accounting.

Finance income (expense) with related parties is disclosed in note 36 – Transactions with related parties.

32 Income (expense) from investments

Share of profit (loss) of equity-accounted investments

More information is provided in note 16 – Investments.

Share of profit or loss of equity accounted investments by industry segment is disclosed in note 35 – Segment information and information by geographical area.

Other gain (loss) from investments

(€ million) | 2025 | 2024 | 2023
Dividends | 242 | 227 | 255
Net gain (loss) on disposals | 77 | 562 | 430
Other net income (expense) | 107 | 195 | 423
| 426 | 984 | 1,108

Dividend income primarily related to Nigeria LNG Ltd for €156 million (€166 million in 2024 and €179 million in 2023) and to Saudi European Petrochemical Co 'IBN ZAHR' for €21 million (€22 million in 2024 and €55 million in 2023).

Gains on disposals referred: (i) for €46 million to the capital gain realized from the sale to Global Infrastructure Partners of 49.99% of the capital of Eni CCUS Holding Ltd, which operates, through its subsidiaries Liverpool Bay and Bacton projects in the United Kingdom and the L10-CCS project in the Netherlands; (ii) for €32 million in the capital gain realized from the sale of 1.27% of the capital of Ithaca Energy Plc through an accelerated bookbuilding process aimed at institutional investors.

Other net income referred for €86 million to a capital gain generated by the allocation of the purchase price of an additional share in E&E Algeria Touat BV and for €27 million to gains from the fair value measurement of the stake retained in Eni CCUS Holding Ltd.

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Gains on disposals for 2024 referred for €371 million to the capital gain realized from the sale of the 100% stake of Nigerian Agip Oil Co Ltd to Oando Plc and €166 million in the capital gain realized from the sale of 10% of the capital of Saipem SpA through an accelerated bookbuilding process aimed at institutional investors. These gains included the realization of effects recognized in comprehensive income for €9 million.

Other net income for 2024 referred for €118 million to the fair value measurement on Ithaca Energy Plc business combination.

Gains on disposals for 2023 referred to the capital gain realized from the sale to Snam of the 49.9% stake of SeaCorridor Srl and other net income for 2023 referred to the capital gain from the fair value measurement of the retained share of SeaCorridor Srl.

33 Income taxes

(€ million) | 2025 | 2024 | 2023
Current taxes |  |  |
- Italian subsidiaries | 6 | (255) | 97
- subsidiaries of the Exploration & Production segment - outside Italy | 3,671 | 4,946 | 5,349
- other subsidiaries - outside Italy | 128 | 22 | 185
| 3,805 | 4,713 | 5,631
Net deferred taxes |  |  |
- Italian subsidiaries | (379) | (1,433) | (137)
- subsidiaries of the Exploration & Production segment - outside Italy | (279) | 294 | (22)
- other subsidiaries - outside Italy | (127) | 151 | (104)
| (785) | (988) | (263)
| 3,020 | 3,725 | 5,368

Current income taxes of Italian subsidiaries include foreign taxes for €118 million.

In 2023, Italy substantively enacted Pillar Two Model Rules, effective as from January 1, 2024, through Legislative Decree 209/2023 as mandated by EU Directive 2022/2523. The Pillar Two rules are designed to ensure large multinational enterprises (meeting certain conditions) pay a minimum level of tax on the income arising in each jurisdiction where they operate. The impact of Pillar Two rules on current income taxes for 2025 and 2024 was immaterial. Eni has applied the exception, as set out in the amendments to IAS 12 Income Taxes, to recognizing and disclosing information about deferred tax assets and liabilities related to Pillar Two income taxes.

The reconciliation between the statutory tax charge calculated by applying the Italian statutory tax rate of 24% (same amount in 2024 and 2023) and the effective tax charge is the following:

(€ million) | 2025 | 2024 | 2023
Profit (loss) before taxation | 5,778 | 6,489 | 10,228
Tax rate (IRES) (%) | 24.0 | 24.0 | 24.0
Statutory corporation tax charge (credit) on profit or loss | 1,387 | 1,557 | 2,455
Increase (decrease) resulting from: |  |  |
- higher tax charges related to subsidiaries outside Italy | 1,692 | 3,452 | 3,036
- Italian regional income tax (IRAP) | 56 | (15) | 91
- tax effect on reserve distribution | 50 | 147 | 106
- impact pursuant to foreign tax effects of Italian entities | 47 | 108 | 14
- effect due to the tax regime provided for intercompany dividends | 46 | 82 | 7
- tax effects related to previous years | 9 | 6 | 48
- effect of the valuation of the investments under the equity method | (30) | (30) | (26)
- impact pursuant to (reversal) impairment of deferred tax assets | (260) | (1,470) | (221)
- effect of gains from sale / business combination |  | (38) | (96)
- other adjustments | 23 | (74) | (46)
| 1,633 | 2,168 | 2,913
Effective tax charge | 3,020 | 3,725 | 5,368

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The higher tax charges at non-Italian subsidiaries related to the Exploration & Production segment for €1,653 million (€3,403 million and €3,026 million in 2024 and 2023, respectively).

Group’s effective tax rate amounted to 52.3% (57.4% in 2024 and 52.5% in 2023). This amount is due to the greater weight on consolidated pre-tax profit from the results obtained in foreign Exploration & Production jurisdictions with tax rates higher than the Group average.

34 Earnings (loss) per share

Basic earnings per ordinary share are calculated by dividing profit for the period attributable to Eni’s shareholders by the weighted average number of ordinary shares issued and outstanding during the period, excluding treasury shares.

Diluted earnings per share are calculated by dividing the profit of the period attributable to Eni’s shareholders by the weighted average number of shares fully diluted, excluding treasury shares, and including the number of potential shares to be issued. As of December 31, 2025, the shares that could be potentially issued related to the estimation of new shares that will vest in connection with the 2023-2025 long-term monetary incentive plans and the convertible bond issued in 2023.

In determining basic and diluted earnings per share, the net profit for the period attributable to Eni is adjusted to take into account the remuneration of perpetual subordinated bonds and the convertible bond, net of tax effect, calculated by using the amortized cost method.

Reconciliation of basic and diluted earnings per share was as follows:

|  | 2025 | 2024 | 2023
Weighted average number of shares used for basic earnings per share |  | 3,024,753,353 | 3,167,006,396 | 3,303,766,512
Potential shares to be issued for ILT incentive plan |  | 6,350,799 | 6,369,161 | 6,352,583
Potential shares to be issued for Sustainability-linked bond |  | 56,975,836 | 56,975,836 | 17,014,702
Weighted average number of shares used for diluted earnings per share |  | 3,088,079,988 | 3,230,351,393 | 3,327,133,797
Eni’s profit | (€ million) | 2,608 | 2,624 | 4,771
Remuneration of subordinated perpetual bonds net of tax effect | (€ million) | (237) | (132) | (109)
Eni’s profit for basic earnings per share | (€ million) | 2,371 | 2,492 | 4,662
Remuneration of Sustainability-linked bond net of tax effect | (€ million) | 31 | 31 | 9
Eni’s profit for diluted earnings per share | (€ million) | 2,402 | 2,523 | 4,671
Basic earnings per share | (€ per share) | 0.78 | 0.79 | 1.41
Diluted earnings per share | (€ per share) | 0.78 | 0.78 | 1.40

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35 Segment information and information by geographic area

Segment information

Eni's segment information is determined on the basis of the operating segments whose results are periodically reviewed by the Chief Operating Decision Maker (the CEO) for performance evaluation and resource allocation decisions.

For financial reporting purposes, consistent with applicable accounting standards, management has considered that the decision-making processes for resource allocation and the CEO's assessment of financial/industrial performance are conducted at a lower level of aggregation than the groupings described. Therefore, in compliance with the provisions of IFRS 8, which regulates the segment reporting, Eni’s reportable segments as of December 31, 2025, have been defined as follows considering the operating segments that flow into the three groupings:

 Exploration & Production: exploration, development and production of crude oil, condensates and natural gas. The business also engages in oil and products trading activities, designed to perform supply-balancing transactions on the market for refining and stabilize or hedge commercial margins.

 Global Gas & LNG Portfolio (GGP) and Power: wholesale supply and marketing of natural gas via pipeline, international transport activities, and the purchase and marketing of equity and third-party LNG. It includes gas trading activities finalized to hedging and stabilizing commercial margins, as well as optimizing the gas asset portfolio. The results of the Power business operating which involves the generation and wholesale of electricity from thermoelectric plants, which offers similar economic returns given the similar industrial dynamics related to gas and electricity demand have been included in this reportable segment. It includes trading of CO 2 emission certificates and forward electricity sales for the purposes of hedging and optimizing margins.

 Refining and Chemicals: processing crude oil for the production of conventional fuels, carried out by the "Refining" operating segment, and the production of petroleum-based chemicals, carried out by the subsidiary Versalis and its subsidiaries. These activities have been combined into a single reportable segment because they offer similar economic returns, exposure to common market dynamics, and common industrial process structures. Versalis is active in the production of bioplastics through its subsidiary Novamont and in compounding chemistry.

 Enilive: engages in the manufacturing of biofuels from renewable raw materials and in retail marketing activities of traditional and biofuels through an extensive network of refueling outlets, also providing non-fuel products and services to drivers with a view to sustainable mobility. It also engages in wholesale fuels, bitumen and lubricants.

 Plenitude: engages in the retail sales of gas, electricity and related services, production and wholesale of electricity from renewable energy plants, and is also building and managing a network of charging points for electric vehicles.

 Corporate and Other activities: includes the main business support functions, in particular holding, central treasury, IT, human resources, real estate services, captive insurance activities, research and development, new technologies, business digitalization and the environmental remediation activity managed by the subsidiary Eni Rewind. The segment also includes activities related to CCUS, agri-business, forest conservation and bioenergy production projects, currently under development.

​Segment information presented to the CEO (the Chief Operating Decision Maker, ex IFRS 8) includes: revenues, operating profit and directly attributable assets and liabilities.

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Segment Information

(€ million) | Exploration & Production | Global Gas & LNG Portfolio and Power | Refining and Chemicals | Enilive | Plenitude | Total reportable segments | Corporate and Other activities | Adjustments of intragroup profits | Total
2025 |  |  |  |  |  |  |  |  |
Sales from operations including intersegment sales | 50,367 | 17,120 | 18,179 | 19,120 | 10,168 | 114,954 |  |  |
- less: intersegment sales | (13,258) | (4,018) | (12,956) | (2,783) | (50) | (33,065) |  |  |
Sales from operations | 37,109 | 13,102 | 5,223 | 16,337 | 10,118 | 81,889 | 262 |  | 82,151
Operating profit | 6,302 | 1,770 | (2,485) | 499 | 153 | 6,239 | (1,499) | 270 | 5,010
Net provisions for contingencies | (335) | 93 | (346) | (42) | (43) | (673) | (491) | 47 | (1,117)
Depreciation and amortization | (6,061) | (279) | (146) | (294) | (451) | (7,231) | (153) | 35 | (7,349)
Impairments of tangible and intangible assets and right-of-use assets | (1,135) | (17) | (482) | (60) | (7) | (1,701) | (96) |  | (1,797)
Reversals of tangible and intangible assets and right-of-use assets | 54 | 35 | 31 | 60 |  | 180 | 35 |  | 215
Write-off of tangible and intangible assets | (30) |  | (1) |  | (2) | (33) |  |  | (33)
Share of profit (loss) of equity-accounted investments | 1,116 | 32 | 120 | (53) | (33) | 1,182 | (21) |  | 1,161
Identifiable assets (a) | 60,407 | 4,988 | 6,377 | 6,117 | 13,622 | 91,511 | 2,630 | (253) | 93,888
Unallocated assets (b) |  |  |  |  |  |  |  |  | 43,181
Equity-accounted investments | 7,562 | 417 | 2,354 | 796 | 1,139 | 12,268 | 887 |  | 13,155
Identifiable liabilities (a) | 19,934 | 4,691 | 4,153 | 3,303 | 5,490 | 37,571 | 5,239 | (90) | 42,720
Unallocated liabilities (b) |  |  |  |  |  |  |  |  | 41,562
Capital expenditure in tangible and intangible assets | 6,678 | 109 | 663 | 468 | 764 | 8,682 | 587 | (40) | 9,229
2024 |  |  |  |  |  |  |  |  |
Sales from operations including intersegment sales | 54,440 | 18,876 | 21,210 | 21,139 | 10,179 | 125,844 |  |  |
- less: intersegment sales | (15,565) | (3,815) | (15,329) | (2,469) | (55) | (37,233) |  |  |
Sales from operations | 38,875 | 15,061 | 5,881 | 18,670 | 10,124 | 88,611 | 186 |  | 88,797
Operating profit | 6,715 | (909) | (1,681) | 282 | 1,307 | 5,714 | (371) | (105) | 5,238
Net provisions for contingencies | (282) | (11) | (478) | (48) | (81) | (900) | (484) | (13) | (1,397)
Depreciation and amortization | (6,353) | (267) | (161) | (284) | (424) | (7,489) | (144) | 33 | (7,600)
Impairments of tangible and intangible assets and right-of-use assets | (2,385) | (195) | (458) | (117) | (1) | (3,156) | (51) |  | (3,207)
Reversals of tangible and intangible assets and right-of-use assets | 182 | 94 | 3 |  | 5 | 284 | 23 |  | 307
Write-off of tangible and intangible assets | (576) |  |  |  | (3) | (579) | (1) |  | (580)
Share of profit (loss) of equity-accounted investments | 904 | 44 | 73 | (43) | (47) | 931 | (65) |  | 866
Identifiable assets (a) | 67,572 | 7,421 | 7,228 | 5,893 | 13,588 | 101,702 | 2,712 | (457) | 103,957
Unallocated assets (b) |  |  |  |  |  |  |  |  | 42,982
Equity-accounted investments | 8,348 | 488 | 2,621 | 899 | 1,019 | 13,375 | 775 |  | 14,150
Identifiable liabilities (a) | 20,627 | 7,230 | 4,253 | 2,995 | 5,883 | 40,988 | 4,881 | (49) | 45,820
Unallocated liabilities (b) |  |  |  |  |  |  |  |  | 45,471
Capital expenditure in tangible and intangible assets | 6,055 | 110 | 632 | 416 | 887 | 8,100 | 408 | (23) | 8,485
2023 |  |  |  |  |  |  |  |  |
Sales from operations including intersegment sales | 55,773 | 24,168 | 23,061 | 21,780 | 11,102 | 135,884 |  |  |
- less: intersegment sales | (17,812) | (4,700) | (16,873) | (2,903) | (62) | (42,350) |  |  |
Sales from operations | 37,961 | 19,468 | 6,188 | 18,877 | 11,040 | 93,534 | 183 |  | 93,717
Operating profit | 8,693 | 2,626 | (2,121) | 585 | (659) | 9,124 | (948) | 81 | 8,257
Net provisions for contingencies | (354) | (206) | (352) | (33) | (73) | (1,018) | (339) | (12) | (1,369)
Depreciation and amortization | (6,271) | (295) | (142) | (261) | (404) | (7,373) | (140) | 34 | (7,479)
Impairments of tangible and intangible assets and right-of-use assets | (1,419) | (14) | (732) | (38) | (7) | (2,210) | (52) |  | (2,262)
Reversals of tangible and intangible assets | 376 | 52 | 6 |  |  | 434 | 26 |  | 460
Write-off of tangible and intangible assets | (531) |  |  |  | (5) | (536) | 1 |  | (535)
Share of profit (loss) of equity-accounted investments | 1,012 | 49 | 381 | (38) | (55) | 1,349 | (13) |  | 1,336
Identifiable assets (a) | 64,504 | 7,688 | 7,186 | 6,081 | 12,692 | 98,151 | 1,891 | (378) | 99,664
Unallocated assets (b) |  |  |  |  |  |  |  |  | 42,942
Equity-accounted investments | 6,780 | 534 | 2,724 | 858 | 664 | 11,560 | 1,070 |  | 12,630
Identifiable liabilities (a) | 21,461 | 6,637 | 3,910 | 2,900 | 5,436 | 40,344 | 4,578 | (56) | 44,866
Unallocated liabilities (b) |  |  |  |  |  |  |  |  | 44,096
Capital expenditure in tangible and intangible assets | 7,135 | 119 | 556 | 428 | 636 | 8,874 | 360 | (19) | 9,215

(a) Include assets/liabilities directly associated with the generation of operating profit. Does not include financial assets and liabilities, investments, income tax assets and liabilities.

(b) Include assets/liabilities not directly associated with the generation of operating profit.

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Information by geographic area

Identifiable assets and investments by geographic area of origin

(€ million) | Italy | Other European Union | Rest of Europe | Americas | Asia | Africa | Other areas | Total
2025 |  |  |  |  |  |  |  |
Identifiable assets (a) | 26,971 | 8,662 | 2,531 | 5,796 | 18,460 | 29,859 | 1,609 | 93,888
Capital expenditure in tangible and intangible assets | 1,829 | 673 | 388 | 260 | 2,486 | 3,476 | 117 | 9,229
2024 |  |  |  |  |  |  |  |
Identifiable assets (a) | 29,787 | 7,704 | 4,709 | 6,470 | 21,232 | 32,624 | 1,431 | 103,957
Capital expenditure in tangible and intangible assets | 2,009 | 673 | 308 | 556 | 1,519 | 3,276 | 144 | 8,485
2023 |  |  |  |  |  |  |  |
Identifiable assets (a) | 30,026 | 6,962 | 5,124 | 7,658 | 17,855 | 30,928 | 1,111 | 99,664
Capital expenditure in tangible and intangible assets | 2,006 | 485 | 235 | 609 | 1,471 | 4,105 | 304 | 9,215

(a) Include assets directly associated with the generation of operating profit.

Sales from operations by geographic area of destination

(€ million) | 2025 | 2024 | 2023
Italy | 28,647 | 30,994 | 33,450
Other European Union | 15,979 | 15,975 | 18,271
Rest of Europe | 14,866 | 16,493 | 18,476
Americas | 6,215 | 7,908 | 7,004
Asia | 9,675 | 9,114 | 7,404
Africa | 6,731 | 8,285 | 9,057
Other areas | 38 | 28 | 55
| 82,151 | 88,797 | 93,717

36 Transactions with related parties

In the ordinary course of its business, Eni enters into transactions mainly regarding:

a) Purchase, sale and supply of goods and services and the provision of financing to joint ventures, associates and non-consolidated subsidiaries;

b) purchase, sale and supply of goods and services to entities controlled by the Italian Government;

c) contributions to Eni Foundation and Eni Enrico Mattei Foundation, non-corporate entities attributable to Eni, which pursue humanitarian, cultural, and research initiatives. Transactions with these entities are immaterial.

There were no material transactions involving Directors, Statutory Auditors or their affiliates.

Transactions with related parties were conducted in the interest of the Group and, with exception of those with entities whose aim is to develop humanitarian, cultural, and scientific initiatives, are related to the ordinary course of Eni’s business.

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Transactions and balances with related parties

| December 31, 2025 |  | 2025
(€ million) | Receivables and other assets | Payables and other liabilities | Guarantees |  | Revenues | Costs | Other operating (expense) income
Joint ventures and associates |  |  |  |  |  |  |
Agiba Petroleum Co | 3 | 135 |  |  | 1 | 333 |
Cardón IV SA | 1 | 134 |  |  | 4 |  |
Coral FLNG SA | 12 |  | 1,247 |  | 21 |  |
Eni CCUS Holding | 118 |  | 1,218 |  |  |  |
Azule Group | 119 | 361 | 2,939 |  | 93 | 1,643 |
Saipem Group | 41 | 136 | 9 |  | 9 | 536 |
SeaCorridor Group | 67 | 19 |  |  | 2 | 266 |
Vårgrønn Group | 1 |  | 678 |  | 1 |  |
In Salah Gas Ltd |  | 57 |  |  |  | 279 |
Ithaca Energy Plc | 146 | 73 |  |  | 12 | 535 | (553)
Karachaganak Petroleum Operating BV | 27 | 119 |  |  | 2 | 992 |
Lotte Versalis Elastomers Co Ltd | 8 | 13 |  |  | 3 | 61 |
Mellitah Oil & Gas BV | 56 | 241 |  |  | 10 | 1,031 |
Petrobel Belayim Petroleum Co | 13 | 470 |  |  | 5 | 778 |
Societe' Centrale Electrique du Congo SA | 91 |  |  |  | 79 |  |
Società Oleodotti Meridionali SpA | 22 | 500 |  |  | 25 | 16 |
St. Bernard Renewables Llc | 1 |  | 98 |  | 1 | 9 |
Vår Energi ASA | 26 | 1,321 | 1,948 |  | 61 | 5,523 | (1)
Other (*) | 78 | 65 | 26 |  | 108 | 224 |
| 830 | 3,644 | 8,163 |  | 437 | 12,226 | (554)
Unconsolidated entities controlled by Eni |  |  |  |  |  |  |
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) | 170 | 1 |  |  | 9 |  |
VME Oilfield Chemicals Llc |  |  | 112 |  |  |  |
Other | 19 | 10 | 21 |  | 21 | 14 |
| 189 | 11 | 133 |  | 30 | 14 |
| 1,019 | 3,655 | 8,296 |  | 467 | 12,240 | (554)
Entities controlled by the Government |  |  |  |  |  |  |
Cassa Depositi e Prestiti Group | 22 | 19 |  |  |  | 87 |
Enel Group | 89 | 183 |  |  | 45 | 650 | 66
Italgas Group | 2 | 190 |  |  | 7 | 718 |
Snam Group | 110 | 247 |  |  | 77 | 1,086 |
Terna Group | 62 | 75 |  |  | 266 | 343 | 5
GSE - Gestore Servizi Energetici | 112 | 100 |  |  | 2,147 | 1,861 | 219
ITA Airways - Italia Trasporto Aereo SpA | 3 |  |  |  | 99 |  |
Other (*) | 23 | 51 |  |  | 97 |  |
| 423 | 865 |  |  | 2,738 | 4,745 | 290
Other related parties |  | 4 |  |  | 1 | 39 |
Groupement Sonatrach – Eni «GSE» | 216 | 307 |  |  | 52 | 729 |
Total | 1,658 | 4,831 | 8,296 |  | 3,258 | 17,753 | (264)

(*) Each individual amount included herein was lower than €50 million.

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| December 31, 2024 |  | 2024
(€ million) | Receivables and other assets | Payables and other liabilities | Guarantees |  | Revenues | Costs | Other operating (expense) income
Joint ventures and associates |  |  |  |  |  |  |
Agiba Petroleum Co | 4 | 126 |  |  |  | 256 |
Cardón IV SA | 1 | 77 |  |  | 4 | (2) |
Coral FLNG SA | 12 |  | 1,411 |  | 15 | (3) |
Azule Group | 59 | 399 | 3,343 |  | 76 | 2,290 |
Saipem Group | 41 | 186 | 9 |  | 52 | 1,253 |
SeaCorridor Group | 105 | 27 |  |  | 1 | 242 |
Vårgrønn Group | 1 |  | 886 |  |  |  |
Ithaca Energy Plc | 188 | 76 |  |  |  | 366 | (138)
Karachaganak Petroleum Operating BV | 31 | 292 |  |  |  | 1,198 |
Lotte Versalis Elastomers Co Ltd | 6 | 14 |  |  | 3 | 51 |
Mellitah Oil & Gas BV | 56 | 52 |  |  | 11 | 523 |
Mozambique Rovuma Venture SpA | 26 | 2 |  |  | 31 | 53 |
Petrobel Belayim Petroleum Co | 23 | 509 |  |  |  | 562 |
Società Oleodotti Meridionali SpA | 12 | 491 |  |  | 16 | 11 |
Société Centrale Electrique du Congo SA | 97 |  |  |  | 104 |  |
Vår Energi ASA | 30 | 828 | 1,918 |  | 48 | 5,047 | (57)
Other (*) | 37 | 71 | 120 |  | 74 | 187 |
| 729 | 3,150 | 7,687 |  | 435 | 12,034 | (195)
Unconsolidated entities controlled by Eni |  |  |  |  |  |  |
Eni BTC Ltd |  |  | 195 |  |  |  |
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) | 161 | 3 |  |  | 10 |  |
Other | 16 | 7 | 11 |  | 27 | 18 |
| 177 | 10 | 206 |  | 37 | 18 |
| 906 | 3,160 | 7,893 |  | 472 | 12,052 | (195)
Entities controlled by the Government |  |  |  |  |  |  |
Cassa Depositi e Prestiti Group | 3 | 25 |  |  |  | 65 |
Enel Group | 33 | 153 |  |  | 46 | 798 | (28)
Italgas Group | 1 | 186 |  |  | 5 | 612 |
Snam Group | 196 | 436 |  |  | 219 | 1,342 |
Terna Group | 104 | 116 |  |  | 386 | 350 | 10
GSE - Gestore Servizi Energetici | 201 | 110 |  |  | 1,805 | 1,548 | 414
ITA Airways - Italia Trasporto Aereo SpA | 13 |  |  |  | 238 |  |
Other (*) | 23 | 66 |  |  | 71 |  |
| 574 | 1,092 |  |  | 2,770 | 4,715 | 396
Other related parties | 1 | 3 |  |  | 2 | 37 |
Groupement Sonatrach – Eni «GSE» | 316 | 316 |  |  | 32 | 599 |
Total | 1,797 | 4,571 | 7,893 |  | 3,276 | 17,403 | 201

(*) Each individual amount included herein was lower than €50 million.

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| December 31, 2023 |  | 2023
(€ million) | Receivables and other assets | Payables and other liabilities | Guarantees |  | Revenues | Costs | Other operating (expense) income
Joint ventures and associates |  |  |  |  |  |  |
Agiba Petroleum Co | 1 | 194 |  |  |  | 308 |
Cardón IV SA | 24 | 142 |  |  | 4 | 1 |
Coral FLNG SA | 4 |  | 1,327 |  | 6 |  |
Azule Group | 113 | 475 | 3,156 |  | 86 | 2,146 |
Saipem Group | 5 | 235 | 9 |  | 6 | 768 |
SeaCorridor Group | 29 | 29 |  |  | 1 | 357 |
Vårgrønn Group |  |  | 1,321 |  |  |  |
Karachaganak Petroleum Operating BV | 17 | 250 |  |  |  | 1,183 |
Mellitah Oil & Gas BV | 49 | 20 |  |  | 16 | 517 |
Petrobel Belayim Petroleum Co | 58 | 885 |  |  |  | 870 |
Società Oleodotti Meridionali SpA | 11 | 473 |  |  | 19 | 12 |
Société Centrale Electrique du Congo SA | 74 |  |  |  | 79 |  |
Vår Energi ASA | 51 | 764 | 2,013 |  | 58 | 4,487 | (165)
Other (*) | 62 | 73 | 19 |  | 83 | 203 |
| 498 | 3,540 | 7,845 |  | 358 | 10,852 | (165)
Unconsolidated entities controlled by Eni |  |  |  |  |  |  |
Eni BTC Ltd |  |  | 183 |  |  |  |
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) | 152 | 4 | 1 |  | 12 |  |
Other | 13 | 10 | 12 |  | 13 | 30 |
| 165 | 14 | 196 |  | 25 | 30 |
| 663 | 3,554 | 8,041 |  | 383 | 10,882 | (165)
Entities controlled by the Government |  |  |  |  |  |  |
Cassa Depositi e Prestiti Group | 5 | 33 |  |  | 2 | 69 |
Enel Group | 95 | 168 |  |  | 93 | 497 | (109)
Italgas Group | 1 | 149 |  |  | 8 | (20) |
Snam Group | 245 | 352 |  |  | 1,157 | 1,625 |
Terna Group | 85 | 61 |  |  | 400 | 317 | 8
GSE - Gestore Servizi Energetici | 230 | 219 |  |  | 2,104 | 1,875 | 283
ITA Airways - Italia Trasporto Aereo SpA | 5 |  |  |  | 238 |  |
Other (*) | 11 | 68 |  |  | 52 | 38 |
| 677 | 1,050 |  |  | 4,054 | 4,401 | 182
Other related parties | 1 | 2 |  |  | 1 | 36 |
Groupement Sonatrach – Eni «GSE» | 222 | 212 |  |  | 40 | 569 |
Total | 1,563 | 4,818 | 8,041 |  | 4,478 | 15,888 | 17

(*) Each individual amount included herein was lower than €50 million.

The most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned:

 Eni’s share of expenses incurred to develop oil fields billed by Agiba Petroleum Co, Karachaganak Petroleum Operating BV, Mellitah Oil & Gas BV, Petrobel Belayim Petroleum Co, Groupement Sonatrach - Eni «GSE» and, limited to Karachaganak Petroleum Operating BV, purchase of crude oil by Eni Trade & Biofuels SpA; costs recovered from Eni associates are billed on the basis of costs incurred;

 the residual debt relating to the payment of the consideration for the repurchase of Cardón IV trade receivables towards the state company PDVSA;

 supply of upstream specialist services and a guarantee issued on a pro-quota basis granted to Coral FLNG SA on behalf of the Consortium TJS for the contractual obligations assumed following the award of the EPCIC contract for the construction of a floating gas liquefaction plant;

 guarantees issued to Eni CCUS Holding in connection with the sale of the CCUS assets in the United Kingdom and the Netherlands;

 supply of upstream specialist services, purchase of crude oil and issue of guarantees against leasing contracts of FPSO vessels to Azule Group;

 engineering, construction and drilling services by Saipem Group mainly for the Exploration & Production segment;

 acquisition of transport services from SeaCorridor Group;

 guarantees issued to Vårgrønn Group mainly in relation to the participation in the Dogger Bank offshore wind project;

 the sale of gas to In Salah Gas Ltd;

 receivables relating to the business combination carried out in 2024, the purchase of crude oil and condensate and the execution of commodity derivative contracts from Ithaca Energy Plc Group;

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 the purchase of elastomers from Lotte Versalis Elastomers Co Ltd;

 advances received from Società Oleodotti Meridionali SpA for the infrastructure upgrade of the crude oil transport system at the Taranto refinery;

 the sale of gas to Société Centrale Electrique du Congo SA;

 guarantees issued pro rata on behalf of St. Bernard Renewables LLC in favor of suppliers for feedstock purchasing transactions;

 guarantees issued in compliance with contractual agreements in the interest of Vår Energi ASA, the supply of upstream specialist services and maritime transport, the purchase of crude oil, condensates and gas and the realized part of forward contracts for the purchase of gas;

 services for environmental restoration to Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation).

The most significant transactions with entities controlled by the Italian Government concerned:

 activities aimed at ensuring operation, upgrading and efficiency of the plants provided to Ansaldo group (Cassa Depositi e Prestiti);

 sale of fuel and combustibles, sale and purchase of gas, acquisition of power distribution services and fair value of derivative financial instruments with Enel Group;

 acquisition of distribution, transportation and storage services with Snam Group and Italgas Group on the basis of the tariffs set by the Italian Regulatory Authority for Energy, Networks and Environment, as well as, from the Snam Group, the receivable for divestment relating to the sale of the 49.9% share capital of SeaCorridor Srl and the purchase and sale of natural gas for granting the system balancing on the basis of prices referred to the quotations of the main energy commodities;

 acquisition of electricity transmission services and sale and purchase of electricity for granting the system balancing based on prices referred to the quotations of the main energy commodities, and derivatives on commodities entered to hedge the price risk related to the utilization of transport capacity rights with Terna Group;

 sale and purchase of electricity, gas, environmental certificates, fair value of derivative financial instruments, sale of oil products and storage capacity with GSE - Gestore Servizi Energetici (Energy Services Operator) for the setting-up of a specific stock held by the Organismo Centrale di Stoccaggio Italiano (OCSIT) according to the Legislative Decree No. 249/12; the contribution to cover the charges deriving from the performance of OCSIT functions and activities and the contribution paid to GSE for the use of biomethane and other advanced biofuels in the transport sector;

 the sale of jet fuel to ITA Airways - Italia Trasporto Aereo SpA.

Transactions with other related parties concerned:

 provisions to pension funds managed by Eni of €25 million and debts for contributions to be paid for €3 million;

 costs for contributions paid to the Supplementary Healthcare Fund for Managers of Eni Group Companies (FISDE) for €5 million and debts for contributions to be paid for €1 million;

 contributions and service provisions to Eni Enrico Mattei Foundation for €4 million and to Eni Foundation for €5 million, and revenues from the Eni Foundation for €1 million.

Financing transactions and balances with related parties

| December 31, 2025 |  | 2025
(€ million) | Receivables and cash and cash equivalents | Payables | Guarantees |  | Finance incomes and derivative financial instruments | Finance Expenses | Gain on disposals
Joint ventures and associates |  |  |  |  |  |  |
Coral FLNG SA | 417 |  |  |  | 20 |  |
E&E Algeria Touat BV |  | 56 |  |  |  |  |
Eni CCUS Holding | 123 |  |  |  |  |  |
Saipem Group |  | 247 |  |  |  | 11 |
Mozambique Rovuma Venture SpA | 2,318 | 91 |  |  | 147 | 11 |
Other (*) | 70 | 57 | 4 |  | 45 | 49 |
| 2,928 | 451 | 4 |  | 212 | 71 |
Unconsolidated entities controlled by Eni |  |  |  |  |  |  |
Other (*) | 41 | 55 |  |  | 2 | 1 |
| 41 | 55 |  |  | 2 | 1 |
Entities controlled by the Government |  |  |  |  |  |  |
Cassa Depositi e Prestiti Group |  | 52 |  |  |  | 2 |
Other |  | 35 |  |  | 1 | 3 | (18)
|  | 87 |  |  | 1 | 5 | (18)
Total | 2,969 | 593 | 4 |  | 215 | 77 | (18)

(*) Each individual amount included herein was lower than €50 million.

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| December 31, 2024 |  | 2024
(€ million) | Receivables and cash and cash equivalents | Payables | Guarantees |  | Finance incomes and derivative financial instruments | Finance Expenses | Gain on disposals
Joint ventures and associates |  |  |  |  |  |  |
Coral FLNG SA | 522 |  |  |  | 24 |  |
Coral South FLNG DMCC |  |  | 1,539 |  |  | (1) |
Saipem Group |  | 222 |  |  | 1 |  |
Mozambique Rovuma Venture SpA | 1,769 | 58 |  |  | 132 | 11 |
Pengerang Biorefinery Sdn Bhd | 60 |  |  |  |  |  |
Other | 37 | 39 | 2 |  | 38 | 41 |
| 2,388 | 319 | 1,541 |  | 195 | 51 |
Unconsolidated entities controlled by Eni |  |  |  |  |  |  |
Other | 40 | 36 |  |  | 2 | 2 |
| 40 | 36 |  |  | 2 | 2 |
Entities controlled by the Government |  |  |  |  |  |  |
Cassa Depositi e Prestiti Group |  | 53 |  |  |  |  |
Other |  | 7 |  |  | 1 | 4 | (12)
|  | 60 |  |  | 1 | 4 | (12)
Other related parties |  | 4 |  |  |  |  |
Total | 2,428 | 419 | 1,541 |  | 198 | 57 | (12)

| December 31, 2023 |  | 2023
(€ million) | Receivables and cash and cash equivalents | Payables | Guarantees |  | Finance incomes and derivative financial instruments | Finance Expenses | Gain on disposals
Joint ventures and associates |  |  |  |  |  |  |
Coral FLNG SA | 453 |  |  |  | 15 |  |
Coral South FLNG DMCC |  |  | 1,448 |  |  |  |
Saipem Group |  | 56 |  |  |  | 8 |
Mozambique Rovuma Venture SpA | 1,339 | 170 |  |  | 101 |  |
Other | 49 | 13 | 1 |  | 39 | 14 | 1
| 1,841 | 239 | 1,449 |  | 155 | 22 | 1
Unconsolidated entities controlled by Eni |  |  |  |  |  |  |
Other | 7 | 38 |  |  | 1 | 1 |
| 7 | 38 |  |  | 1 | 1 |
Entities controlled by the Government |  |  |  |  |  |  |
Cassa Depositi e Prestiti Group |  | 56 |  |  |  | 2 |
Snam Group |  |  |  |  |  |  | 443
Other | 14 | 2 |  |  |  | 3 | 1
| 14 | 58 |  |  |  | 5 | 444
Total | 1,862 | 335 | 1,449 |  | 156 | 28 | 445

The most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned:

 a financing loan granted to Coral FLNG SA for the construction of a floating gas liquefaction plant in Area 4 offshore Mozambique;

 a cash deposit with Group finance companies for E&E Algeria Touat BV;

 a financing loan granted by Eni UK to Bacton CCS, part of the Eni CCS Holding group, as part of the agreement with GIP;

 a bank debt guarantee issued on behalf of Coral South FLNG DMCC as part of the project financing of the Coral FLNG development project;

 liabilities for leased assets towards Saipem Group related to long-term contracts for the use of drilling rigs

 a financing loan granted to Mozambique Rovuma Venture SpA for the development of gas reserves offshore Mozambique;

The most significant transactions with entities controlled by the Italian Government concerned:

 finance debt for the realization of charging infrastructures for electric vehicles with Cassa e Depositi e Prestiti Group.

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Impact of transactions and positions with related parties on the balance sheet, profit and loss account and statement of cash flows

The impact of transactions and positions with related parties on the balance sheet accounts consisted of the following:

| December 31, 2025 | December 31, 2024
(€ million) | Total | Related parties | Impact % | Total | Related parties | Impact %
Other current financial assets | 3,710 | 2,357 | 63.53 | 1,085 | 48 | 4.42
Trade and other receivables | 12,436 | 1,375 | 11.06 | 16,901 | 1,601 | 9.47
Other current assets | 3,943 | 76 | 1.93 | 3,662 | 54 | 1.47
Other non-current financial assets | 1,109 | 612 | 55.18 | 3,215 | 2,380 | 74.03
Other non-current assets | 2,839 | 207 | 7.29 | 4,011 | 142 | 3.54
Short-term debt | 4,929 | 265 | 5.38 | 4,238 | 136 | 3.21
Current portion of long-term debt | 3,434 | 128 | 3.73 | 4,582 | 21 | 0.46
Current portion of non-current lease liabilities | 1,263 | 108 | 8.55 | 1,279 | 152 | 11.88
Trade and other payables | 20,261 | 4,283 | 21.14 | 22,092 | 4,017 | 18.18
Other current liabilities | 4,039 | 86 | 2.13 | 5,049 | 34 | 0.67
Long-term debt | 20,139 | 52 | 0.26 | 21,570 | 79 | 0.37
Non-current lease liabilities | 4,437 | 40 | 0.90 | 5,174 | 31 | 0.60
Other non-current liabilities | 3,390 | 462 | 13.63 | 4,449 | 520 | 11.69

The impact of transactions with related parties on the profit and loss accounts consisted of the following:

| 2025 | 2024 | 2023
(€ million) | Total | Related parties | Impact % | Total | Related parties | Impact % | Total | Related parties | Impact %
Sales from operations | 82,151 | 2,973 | 3.62 | 88,797 | 2,997 | 3.38 | 93,717 | 4,322 | 4.61
Other income and revenues | 1,478 | 285 | 19.28 | 2,417 | 279 | 11.54 | 1,099 | 156 | 14.19
Purchases, services and other | (67,056) | (17,769) | 26.50 | (71,114) | (17,404) | 24.47 | (73,836) | (15,885) | 21.51
Net (impairments) reversals of trade and other receivables | (11) | (1) | 9.09 | (168) | (2) | 1.19 | (249) | 5 | ..
Payroll and related costs | (3,229) | 17 | .. | (3,262) | 3 | .. | (3,136) | (8) | 0.26
Other operating income (expense) | 641 | (264) | .. | (352) | 201 | .. | 478 | 17 | 3.56
Finance income | 7,196 | 215 | 2.99 | 7,715 | 198 | 2.57 | 7,417 | 155 | 2.09
Finance expense | (8,170) | (77) | 0.94 | (8,980) | (57) | 0.63 | (8,113) | (28) | 0.35
Derivative financial instruments | (80) |  |  | 278 |  |  | (61) | 1 | ..
Other income (expense) from investments | 426 | (18) | .. | 984 | (12) | .. | 1,108 | 445 | 40.16

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Main cash flows with related parties are provided below:

(€ million) | 2025 | 2024 | 2023
Revenues and other income | 3,258 | 3,276 | 4,478
Costs and other expenses | (15,198) | (15,056) | (13,539)
Other operating income (loss) | (264) | 201 | 17
Net change in trade and other receivables and payables | 691 | (61) | 1,916
Net interests | 138 | 132 | 117
Net cash provided from operating activities | (11,375) | (11,508) | (7,011)
Capital expenditure in tangible and intangible assets | (2,555) | (2,347) | (2,349)
Disposal of investments |  |  | 440
Net change in accounts payable and receivable in relation to investments | 93 | (292) | 504
Change in financial receivables | (719) | (501) | (290)
Net cash used in investing activities | (3,181) | (3,140) | (1,695)
Change in financial and lease liabilities | (407) | (20) | (162)
Net cash used in financing activities | (407) | (20) | (162)
Change in cash and cash equivalents |  | (3) | (7)
Total financial flows to related parties | (14,963) | (14,671) | (8,875)

The impact of cash flows with related parties consisted of the following:

| 2025 | 2024 | 2023
(€ million) | Total | Related parties | Impact % | Total | Related parties | Impact % | Total | Related parties | Impact %
Net cash provided from operating activities | 13,330 | (11,375) | .. | 13,092 | (11,508) | .. | 15,119 | (7,011) | ..
Net cash used in investing activities | (9,298) | (3,181) | 34.21 | (9,817) | (3,140) | 31.99 | (9,365) | (1,695) | 18.10
Net cash used in financing activities | (3,596) | (407) | 11.32 | (5,380) | (20) | 0.37 | (5,668) | (162) | 2.86

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37 Other information about investments

Information on Eni’s investments as of December 31, 2025

The following section provides information about Eni’s consolidated subsidiaries as of December 31, 2025.

CONSOLIDATED SUBSIDIARIES

EXPLORATION & PRODUCTION

IN ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Eni Marine Services SpA | San Donato Milanese (MI) | Italy |  | Eni SpA | 100.00 |  | 100.00 |
Eni Mediterranea Idrocarburi SpA | Gela (CL) | Italy |  | Eni SpA | 100.00 |  | 100.00 |
Eni Mozambico SpA | San Donato Milanese (MI) | Mozambique |  | Eni SpA | 100.00 |  | 100.00 |
Eni Natural Energies Mozambico Srl | San Donato Milanese (MI) | Mozambique |  | Eni Natural Energies SpA | 100.00 |  | 100.00 |
Eni Natural Energies SpA | San Donato Milanese (MI) | Italy |  | Eni SpA | 100.00 |  | 100.00 |
EniProgetti SpA | Venezia Marghera (VE) | Italy |  | Eni SpA | 100.00 |  | 100.00 |
Eni Trade & Biofuels SpA | Rome | Italy |  | Eni SpA | 100.00 |  | 100.00 |
Floaters SpA | San Donato Milanese (MI) | Italy |  | Eni SpA | 100.00 |  | 100.00 |
Società Petrolifera Italiana SpA | San Donato Milanese (MI) | Italy |  | Eni SpA | 99.96 |  | 99.96 |
|  |  |  | Third parties | 0.04 |  |  |

OUTSIDE ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Agip Caspian Sea BV | Amsterdam (Netherlands) | Kazakhstan |  | Eni International BV | 100.00 |  | 100.00 |
Agip Energy and Natural Resources (Nigeria) Ltd | Abuja (Nigeria) | Nigeria |  | Eni International BV | 95.00 |  | 100.00 |
|  |  |  | Eni Oil Holdings BV | 5.00 |  |  |
Agip Karachaganak BV | Amsterdam (Netherlands) | Kazakhstan |  | Eni International BV | 100.00 |  | 100.00 |
Burren Energy (Bermuda) Ltd | Hamilton (Bermuda) | United Kingdom |  | Burren Energy Plc | 100.00 |  | 100.00 |
Burren Energy Congo Ltd | Road Town (British Virgin Islands) | Republic of the Congo |  | Burren En. (Berm) Ltd | 100.00 |  | 100.00 |
Burren Energy India Ltd | London (United Kingdom) | United Kingdom |  | Burren Energy Plc | 100.00 |  | 100.00 |
Burren Energy Plc | London (United Kingdom) | United Kingdom |  | Eni UK Holding Plc | 99.99 |  | 100.00 |
|  |  |  | Eni UK Ltd | (..) |  |  |
Eni Abu Dhabi BV | Amsterdam (Netherlands) | United Arab Emirates |  | Eni International BV | 100.00 |  | 100.00 |
Eni Albania BV | Amsterdam (Netherlands) | Albania |  | Eni Netherlands Hold. BV | 100.00 |  | 100.00 |
Eni Algeria Exploration BV | Amsterdam (Netherlands) | Algeria |  | Eni International BV | 100.00 |  | 100.00 |
Eni Algeria Production BV | Amsterdam (Netherlands) | Algeria |  | Eni International BV | 100.00 |  | 100.00 |
Eni Ambalat Ltd | London (United Kingdom) | Indonesia |  | Eni Indonesia Ltd | 100.00 |  | 100.00 |
Eni America Ltd | Dover (USA) | USA |  | Eni UHL Ltd | 100.00 |  | 100.00 |
Eni Argentina Exploración y Explotación SA | Buenos Aires (Argentina) | Argentina |  | Eni International BV | 95.00 |  | 100.00 |
|  |  |  | Eni Oil Holdings BV | 5.00 |  |  |
Eni Arguni I Ltd | London (United Kingdom) | Indonesia |  | Eni Indonesia Ltd | 100.00 |  | 100.00 |
Eni Australia BV | Amsterdam (Netherlands) | Australia |  | Eni International BV | 100.00 |  | 100.00 |
Eni Australia Ltd | London (United Kingdom) | Australia |  | Eni International BV | 100.00 |  | 100.00 |

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Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Eni BB Petroleum Inc | Dover (USA) | USA |  | Eni Petroleum Co Inc | 100.00 |  | 100.00 |
Eni BTC Ltd | London (United Kingdom) | United Kingdom |  | Eni International BV | 100.00 |  | 100.00 |
Eni Bukat Ltd | London (United Kingdom) | Indonesia |  | Eni Indonesia Ltd | 100.00 |  | 100.00 |
Eni Canada Holding Ltd | Calgary (Canada) | Canada |  | Eni International BV | 100.00 |  | 100.00 |
Eni China BV | Amsterdam (Netherlands) | China |  | Eni International BV | 100.00 |  | 100.00 |
Eni Congo SAU | Pointe-Noire (Republicof the Congo) | Republic of the Congo |  | Eni E&P Holding BV | 100.00 |  | 100.00 |
Eni Côte d'Ivoire Ltd | London (United Kingdom) | Ivory Coast |  | Eni Lasmo Plc | 100.00 |  | 100.00 |
Eni Cyprus Ltd | Nicosia (Cyprus) | Cyprus |  | Eni International BV | 100.00 |  | 100.00 |
Eni East Ganal Ltd | London (United Kingdom) | Indonesia |  | Eni Indonesia Ltd | 100.00 |  | 100.00 |
Eni East Med BV | Amsterdam (Netherlands) | Netherlands |  | Eni International BV | 100.00 |  | 100.00 |
Eni East Sepinggan Ltd | London (United Kingdom) | Indonesia |  | Eni Indonesia Ltd | 100.00 |  | 100.00 |
Eni Energy Alam El Shawish BV | The Hague (Netherlands) | Egypt |  | Eni En. E&P Hold. NL BV | 100.00 |  | 100.00 |
Eni Energy Arguni I BV | The Hague (Netherlands) | Indonesia |  | Eni En. E&P Hold. NL BV | 100.00 |  | 100.00 |
Eni Energy Ashrafi BV | The Hague (Netherlands) | Egypt |  | Eni En. E&P Hold. NL BV | 100.00 |  | 100.00 |
Eni Energy Australia Pty Ltd | Perth (Australia) | Australia |  | Eni En. Holding NL BV | 100.00 |  | 100.00 |
Eni Energy Bonaparte Pty Ltd | Perth (Australia) | Australia |  | Eni En. Australia Pty Ltd | 100.00 |  | 100.00 |
Eni Energy E&P Holding Netherlands BV | The Hague (Netherlands) | Netherlands |  | Eni En. Holding NL BV | 100.00 |  | 100.00 |
Eni Energy East Ganal BV | The Hague (Netherlands) | Indonesia |  | Eni En. E&P Hold. NL BV | 100.00 |  | 100.00 |
Eni Energy East Sepinggan BV | The Hague (Netherlands) | Indonesia |  | Eni En. E&P Hold. NL BV | 100.00 |  | 100.00 |
Eni Energy Egypt BV | The Hague (Netherlands) | Egypt |  | Eni En. E&P Hold. NL BV | 100.00 |  | 100.00 |
Eni Energy Facilities Netherlands BV | The Hague (Netherlands) | Netherlands |  | Eni Energy NL BV | 100.00 |  | 100.00 |
Eni Energy Germany BV | The Hague (Netherlands) | Germany |  | Eni Energy NL BV | 100.00 |  | 100.00 |
Eni Energy Group Holdings Ltd | London (United Kingdom) | United Kingdom |  | Eni En. Group Midco Ltd | 100.00 |  | 100.00 |
Eni Energy Group Ltd | London (United Kingdom) | United Kingdom |  | Eni International BV | 100.00 |  | 100.00 |

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Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Eni Energy Group Midco Ltd | London (United Kingdom) | United Kingdom |  | Eni Energy Group Ltd | 100.00 |  | 100.00 |
Eni Energy Holding Netherlands BV | The Hague (Netherlands) | Netherlands |  | Eni International BV | 100.00 |  | 100.00 |
Eni Energy Hydrogen BV | The Hague (Netherlands) | Netherlands |  | Eni Energy NL BV | 100.00 |  | 100.00 |
Eni Energy Jakarta BV | The Hague (Netherlands) | Indonesia |  | Eni En. E&P Hold. NL BV | 100.00 |  | 100.00 |
Eni Energy Muara Bakau BV | The Hague (Netherlands) | Indonesia |  | Eni En. E&P Hold. NL BV | 100.00 |  | 100.00 |
Eni Energy Netherlands Administration BV | The Hague (Netherlands) | Netherlands |  | Eni Energy NL BV | 100.00 |  | 100.00 |
Eni Energy Netherlands BV | The Hague (Netherlands) | Netherlands |  | Eni En. E&P Hold. NL BV | 100.00 |  | 100.00 |
Eni Energy North Ganal BV | The Hague (Netherlands) | Indonesia |  | Eni En. E&P Hold. NL BV | 100.00 |  | 100.00 |
Eni Energy North West El Amal BV | The Hague (Netherlands) | Egypt |  | Eni En. E&P Hold. NL BV | 100.00 |  | 100.00 |
Eni Energy Participation Netherlands BV | The Hague (Netherlands) | Netherlands |  | Eni Energy NL BV | 100.00 |  | 100.00 |
Eni Energy Russia BV | Amsterdam (Netherlands) | Netherlands |  | Eni International BV | 100.00 |  | 100.00 |
Eni Energy Touat Holding BV | The Hague (Netherlands) | Netherlands |  | Eni En. E&P Hold. NL BV | 100.00 |  | 100.00 |
Eni Energy West Ganal BV | The Hague (Netherlands) | Indonesia |  | Eni En. E&P Hold. NL BV | 100.00 |  | 100.00 |
Eni Exploration & Production Holding BV | Amsterdam (Netherlands) | Netherlands |  | Eni International BV | 100.00 |  | 100.00 |
Eni Ganal Deepwater Ltd | Hamilton (Bermuda) | Indonesia |  | Eni Lasmo Plc | 100.00 |  | 100.00 |
Eni Ganal Ltd | London (United Kingdom) | Indonesia |  | Eni Indonesia Ltd | 100.00 |  | 100.00 |
Eni Gas & Power LNG Australia BV | Amsterdam (Netherlands) | Australia |  | Eni International BV | 100.00 |  | 100.00 |
Eni Ghana Exploration and Production Ltd | Accra (Ghana) | Ghana |  | Eni International BV | 100.00 |  | 100.00 |
Eni GoM Llc | Dover (USA) | USA |  | Eni Marketing Inc | 100.00 |  | 100.00 |
Eni Hewett Ltd | Aberdeen (United Kingdom) | United Kingdom |  | Eni UK Ltd | 100.00 |  | 100.00 |
Eni In Amenas Ltd | Aberdeen (United Kingdom) | Algeria |  | Eni Algeria Expl.BV | 100.00 |  | 100.00 |
Eni In Salah Ltd | Nassau (Bahamas) | Algeria |  | Eni IS Exploration Ltd | 60.48 |  | 100.00 |
|  |  |  | Eni Algeria Expl.BV | 39.52 |  |  |
Eni Indonesia Ltd | London (United Kingdom) | Indonesia |  | Eni ULX Ltd | 100.00 |  | 100.00 |

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Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Eni Indonesia Ots 1 Ltd | George Town (Cayman Islands) | Indonesia |  | Eni Indonesia Ltd | 100.00 |  | 100.00 |
Eni International NA NV Sàrl | Luxembourg (Luxembourg) | United Kingdom |  | Eni International BV | 100.00 |  | 100.00 |
Eni Investments Plc | London (United Kingdom) | United Kingdom |  | Eni SpA | 99.99 |  | 100.00 |
|  |  |  | Eni UK Ltd | (..) |  |  |
Eni Iraq BV | Amsterdam (Netherlands) | Iraq |  | Eni International BV | 100.00 |  | 100.00 |
Eni IS Exploration Ltd | London (United Kingdom) | United Kingdom |  | Eni Algeria Expl.BV | 100.00 |  | 100.00 |
Eni Isatay BV | Amsterdam (Netherlands) | Kazakhstan |  | Eni International BV | 100.00 |  | 100.00 |
Eni JPDA 03-13 Ltd | London (United Kingdom) | Australia |  | Eni International BV | 100.00 |  | 100.00 |
Eni JPDA 06-105 Pty Ltd | Perth (Australia) | Australia |  | Eni International BV | 100.00 |  | 100.00 |
Eni Kenya BV | Amsterdam (Netherlands) | Kenya |  | Eni Netherlands Hold. BV | 100.00 |  | 100.00 |
Eni Lasmo Plc | London (United Kingdom) | United Kingdom |  | Eni Investments Plc | 99.99 |  | 100.00 |
|  |  |  | Eni UK Ltd | (..) |  |  |
Eni LNS Ltd | London (United Kingdom) | United Kingdom |  | Eni UK Ltd | 100.00 |  | 100.00 |
Eni Makassar Ltd | Hamilton (Bermuda) | Indonesia |  | Eni Lasmo Plc | 100.00 |  | 100.00 |
Eni Marketing Inc | Dover (USA) | USA |  | Eni Petroleum Co Inc | 100.00 |  | 100.00 |
Eni México S. de RL de CV | Mexico City (Mexico) | Mexico |  | Eni International BV | 99.69 |  | 100.00 |
|  |  |  | Eni Oil Holdings BV | 0.31 |  |  |
Eni Middle East Ltd | London (United Kingdom) | United Arab Emirates |  | Eni ULT Ltd | 100.00 |  | 100.00 |
Eni Mozambique LNG Holding BV | Amsterdam (Netherlands) | Netherlands |  | Eni International BV | 100.00 |  | 100.00 |
Eni Muara Bakau BV | Amsterdam (Netherlands) | Indonesia |  | Eni International BV | 100.00 |  | 100.00 |
Eni Natural Energies Congo SAU | Pointe-Noire (Republic of the Congo) | Republic of the Congo |  | Eni Natural Energies SpA | 100.00 |  | 100.00 |
Eni Natural Energies Côte d'Ivoire SA | Abidjan (Ivory Coast) | Ivory Coast |  | Eni Natural Energies SpA | 100.00 |  | 100.00 |
Eni Natural Energies Kenya EPZ Ltd | Kinango (Kenya) | Kenya |  | Eni Natural Energies SpA | 100.00 |  | 100.00 |

F-116

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Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Eni Natural Energies Vietnam Llc | Ho Chi Minh City (Vietnam) | Vietnam |  | Eni Natural Energies SpA | 100.00 |  | 100.00 |
Eni North Africa BV | Amsterdam (Netherlands) | Libya |  | Eni International BV | 100.00 |  | 100.00 |
Eni North Ganal Ltd | London (United Kingdom) | Indonesia |  | Eni Indonesia Ltd | 100.00 |  | 100.00 |
Eni Oil & Gas Inc | Dover (USA) | USA |  | Eni America Ltd | 100.00 |  | 100.00 |
Eni Oil Algeria Ltd | London (United Kingdom) | Algeria |  | Eni Lasmo Plc | 100.00 |  | 100.00 |
Eni Oil Holdings BV | Amsterdam (Netherlands) | Netherlands |  | Eni ULX Ltd | 100.00 |  | 100.00 |
Eni Oman BV | Amsterdam (Netherlands) | Oman |  | Eni International BV | 100.00 |  | 100.00 |
Eni Peri Mahakam Ltd | London (United Kingdom) | Indonesia |  | Eni Indonesia Ltd | 100.00 |  | 100.00 |
Eni Petroleum Co Inc | Dover (USA) | USA |  | Eni SpA | 60.06 |  | 100.00 |
|  |  |  | Eni International BV | 39.94 |  |  |
Eni Petroleum US Llc | Dover (USA) | USA |  | Eni BB Petroleum Inc | 100.00 |  | 100.00 |
EniProgetti Egypt Ltd | Cairo (Egypt) | Egypt |  | EniProgetti SpA | 99.00 |  | 100.00 |
|  |  |  | Eni SpA | 1.00 |  |  |
Eni Qatar BV | Amsterdam (Netherlands) | Qatar |  | Eni International BV | 100.00 |  | 100.00 |
Eni RAK BV | Amsterdam (Netherlands) | United Arab Emirates |  | Eni Netherlands Hold. BV | 100.00 |  | 100.00 |
Eni Rapak Deepwater Ltd | Hamilton (Bermuda) | Indonesia |  | Eni Lasmo Plc | 100.00 |  | 100.00 |
Eni Rapak Ltd | London (United Kingdom) | Indonesia |  | Eni Indonesia Ltd | 100.00 |  | 100.00 |
Eni Rovuma Basin BV | Amsterdam (Netherlands) | Mozambique |  | Eni Mozamb. LNG H. BV | 100.00 |  | 100.00 |
Eni Sharjah BV | Amsterdam (Netherlands) | United Arab Emirates |  | Eni International BV | 100.00 |  | 100.00 |
Eni Timor 22-23 BV | Amsterdam (Netherlands) | East Timor |  | Eni International BV | 100.00 |  | 100.00 |
Eni TNS Ltd | Aberdeen (United Kingdom) | United Kingdom |  | Eni UK Ltd | 100.00 |  | 100.00 |
Eni Trading & Shipping Inc | Dover (USA) | USA |  | Eni Petroleum Co Inc | 100.00 |  | 100.00 |
Eni Transporte y Suministro México S. de RL de CV | Mexico City (Mexico) | Mexico |  | Eni International BV | 99.90 |  | 100.00 |
|  |  |  | Eni Oil Holdings BV | 0.10 |  |  |
Eni Tunisia BV | Amsterdam (Netherlands) | Tunisia |  | Eni Netherlands Hold. BV | 100.00 |  | 100.00 |
Eni Turkmenistan Ltd | Hamilton (Bermuda) | Turkmenistan |  | Burren En. (Berm) Ltd | 100.00 |  | 100.00 |

F-117

Table of Contents

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Eni UHL Ltd | London (United Kingdom) | United Kingdom |  | Eni ULT Ltd | 100.00 |  | 100.00 |
Eni UK Holding Plc | London (United Kingdom) | United Kingdom |  | Eni Lasmo Plc | 99.99 |  | 100.00 |
|  |  |  | Eni UK Ltd | (..) |  |  |
Eni UK Ltd | London (United Kingdom) | United Kingdom |  | Eni International BV | 100.00 |  | 100.00 |
Eni ULT Ltd | London (United Kingdom) | United Kingdom |  | Eni Lasmo Plc | 100.00 |  | 100.00 |
Eni ULX Ltd | London (United Kingdom) | United Kingdom |  | Eni ULT Ltd | 100.00 |  | 100.00 |
Eni US Operating Co Inc | Dover (USA) | USA |  | Eni Petroleum Co Inc | 100.00 |  | 100.00 |
Eni USA Gas Marketing Llc | Dover (USA) | USA |  | Eni Marketing Inc | 100.00 |  | 100.00 |
Eni USA Inc | Dover (USA) | USA |  | Eni Oil & Gas Inc | 100.00 |  | 100.00 |
Eni Venezuela BV | Amsterdam (Netherlands) | Venezuela |  | Eni Venezuela E&P H. | 100.00 |  | 100.00 |
Eni Venezuela E&P Holding SA | Bruxelles (Belgium) | Belgium |  | Eni International BV | 100.00 |  | 100.00 |
Eni Vietnam BV | Amsterdam (Netherlands) | Vietnam |  | Eni International BV | 100.00 |  | 100.00 |
Eni West Ganal Ltd | London (United Kingdom) | Indonesia |  | Eni Indonesia Ltd | 100.00 |  | 100.00 |
Eni West Timor Ltd | London (United Kingdom) | Indonesia |  | Eni Indonesia Ltd | 100.00 |  | 100.00 |
Export LNG Ltd | Hong Kong (Hong Kong) | Hong Kong |  | Eni SpA | 100.00 |  | 100.00 |
First Calgary Petroleums LP | Wilmington (USA) | Algeria |  | Eni Canada Hold. Ltd | 99.99 |  | 100.00 |
|  |  |  | FCP Partner Co ULC | 0.01 |  |  |
First Calgary Petroleums Partner Co ULC | Calgary (Canada) | Canada |  | Eni Canada Hold. Ltd | 100.00 |  | 100.00 |
Ieoc Production BV | Amsterdam (Netherlands) | Egypt |  | Eni International BV | 100.00 |  | 100.00 |
Lasmo Sanga Sanga Ltd | Hamilton (Bermuda) | Indonesia |  | Eni Lasmo Plc | 100.00 |  | 100.00 |
Nigerian Agip Exploration Ltd | Abuja (Nigeria) | Nigeria |  | Eni International BV | 99.99 |  | 100.00 |
|  |  |  | Eni Oil Holdings BV | 0.01 |  |  |
Production North Sea Netherlands Ltd | Wilmington (USA) | Netherlands |  | Eni Energy NL BV | 100.00 |  | 100.00 |
PT Eni Natural Energies Indonesia | Jakarta (Indonesia) | Indonesia |  | Eni Natural Energies SpA | 99.99 |  | 100.00 |
|  |  |  | ENE Italia | 0.01 |  |  |

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GLOBAL GAS & LNG PORTFOLIO

IN ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Eni Global Energy Markets SpA | Rome | Italy |  | Eni SpA | 100.00 |  | 100.00 |
LNG Shipping SpA | San Donato Milanese (MI) | Italy |  | Eni SpA | 100.00 |  | 100.00 |

OUTSIDE ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Eni España Comercializadora de Gas SAU | Madrid (Spain) | Spain |  | Eni SpA | 100.00 |  | 100.00 |
Eni G&P Trading BV | Amsterdam (Netherlands) | Turkey |  | Eni Netherlands Hold. BV | 100.00 |  | 100.00 |
Eni Gas Liquefaction BV | Amsterdam (Netherlands) | Netherlands |  | Eni Netherlands Hold. BV | 100.00 |  | 100.00 |

Power

IN ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
EniPower SpA | San Donato Milanese (MI) | Italy |  | Eni SpA | 51.00 |  | 51.00 |
|  |  |  | Third parties | 49.00 |  |  |
EniPower Mantova SpA | San Donato Milanese (MI) | Italy |  | EniPower SpA | 86.50 |  | 44.12 |
|  |  |  | Third parties | 13.50 |  |  |

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Table of Contents

REFINING AND CHEMICALS

Refining

IN ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Ecofuel SpA | San Donato Milanese (MI) | Italy |  | Eni SpA | 100.00 |  | 100.00 |

OUTSIDE ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Eni Abu Dhabi Refining & Trading BV | Amsterdam (Netherlands) | Netherlands |  | Eni International BV | 100.00 |  | 100.00 |

Chemicals

IN ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Versalis SpA | San Donato Milanese (MI) | Italy |  | Eni SpA | 100.00 |  | 100.00 |
Finproject SpA | Morrovalle (MC) | Italy |  | Versalis SpA | 100.00 |  | 100.00 |
Novamont SpA | Novara | Italy |  | Versalis SpA | 100.00 |  | 100.00 |
Versalis Oilfield Solutions Srl (former Rewave Srl) | San Donato Milanese (MI) | Italy |  | Versalis SpA | 100.00 |  | 100.00 |

OUTSIDE ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
BioBag Americas Inc | Dunedin (USA) | USA |  | BioBag International | 100.00 |  | 100.00 |
BioBag International AS | Indre Østfold (Norway) | Norway |  | Novamont SpA | 100.00 |  | 100.00 |
Dagöplast AS | Hiiumaa (Estonia) | Estonia |  | BioBag International | 100.00 |  | 100.00 |
Dunastyr Polisztirolgyártó Zártkörûen Mûködõ Részvénytársaság | Budapest (Hungary) | Hungary |  | Versalis SpA | 96.34 |  | 100.00 |
|  |  |  | Versalis Deutsch. GmbH | 1.83 |  |  |
|  |  |  | Versalis International SA | 1.83 |  |  |
Finproject India Pvt Ltd | Jaipur (India) | India |  | Versalis Asia Pacific | 99.99 |  | 100.00 |
|  |  |  | Finproject SpA | (..) |  |  |
Finproject Romania Srl | Valea Lui Mihai (Romania) | Romania |  | Finproject SpA | 100.00 |  | 100.00 |
Foam Creations (2008) Inc | Quebec City (Canada) | Canada |  | Finproject SpA | 100.00 |  | 100.00 |
Foam Creations México SA de CV | León (Mexico) | Mexico |  | Foam Creations (2008) | 53.23 |  | 100.00 |
|  |  |  | Finproject SpA | 46.77 |  |  |
Novamont France SAS | Paris (France) | France |  | Novamont SpA | 100.00 |  | 100.00 |
Novamont Iberia SLU | Cornellà de Llobregat (Spain) | Spain |  | Novamont SpA | 100.00 |  | 100.00 |
Novamont North America Inc | Shelton (USA) | USA |  | Novamont SpA | 100.00 |  | 100.00 |
Versalis Americas Inc | Dover (USA) | USA |  | Eni Petroleum Co Inc | 100.00 |  | 100.00 |
Versalis Asia Pacific Pte Ltd | Singapore (Singapore) | Singapore |  | Versalis SpA | 100.00 |  | 100.00 |
Versalis Congo Sarlu | Pointe-Noire (Republic of the Congo) | Republic of the Congo |  | Versalis Oilfield S. Srl | 100.00 |  | 100.00 |
Versalis Deutschland GmbH | Eschborn (Germany) | Germany |  | Versalis SpA | 100.00 |  | 100.00 |
Versalis France SAS | Mardyck (France) | France |  | Versalis SpA | 100.00 |  | 100.00 |
Versalis International Côte d'Ivoire Sarlu | Abidjan (Ivory Coast) | Ivory Coast |  | Versalis Oilfield S. Srl | 100.00 |  | 100.00 |

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Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Versalis International SA | Bruxelles (Belgium) | Belgium |  | Versalis SpA | 59.00 |  | 100.00 |
|  |  |  | Versalis Deutsch. GmbH | 23.71 |  |  |
|  |  |  | Dunastyr Zrt | 14.43 |  |  |
|  |  |  | Versalis France | 2.86 |  |  |
Versalis Kimya Ticaret Limited Sirketi | Istanbul (Turkey) | Turkey |  | Versalis International SA | 100.00 |  | 100.00 |
Versalis México S. de RL de CV | Mexico City (Mexico) | Mexico |  | Versalis Oilfield S. Srl | 99.99 |  | 100.00 |
|  |  |  | Versalis SpA | (..) |  |  |
Versalis Pacific Trading (Shanghai) Co Ltd | Shanghai (China) | China |  | Versalis Asia Pacific | 100.00 |  | 100.00 |
Versalis UK Ltd | London (United Kingdom) | United Kingdom |  | Versalis SpA | 100.00 |  | 100.00 |

ENILIVE AND PLENITUDE

Enilive

IN ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Enilive SpA | Rome | Italy |  | Eni SpA | 70.00 |  | 70.00 |
|  |  |  | Third parties | 30.00 |  |  |
Bioraffineria di Gela SpA | Gela (CL) | Italy |  | Enilive SpA | 100.00 |  | 70.00 |
Enimoov SpA | Rome | Italy |  | Enilive SpA | 100.00 |  | 70.00 |

OUTSIDE ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Aten Oil SLU | Madrid (Spain) | Spain |  | Enilive Iberia SLU | 100.00 |  | 70.00 |
Eni Energy (Shanghai) Co Ltd | Shanghai (China) | China |  | Enilive SpA | 100.00 |  | 70.00 |
Enilive Austria GmbH | Wien (Austria) | Austria |  | Enilive SpA | 75.00 |  | 70.83 |
|  |  |  | Enilive Deutsch. GmbH | 25.00 |  |  |
Enilive Benelux BV | Rotterdam (Netherlands) | Netherlands |  | Enilive SpA | 100.00 |  | 70.00 |
Enilive Deutschland GmbH | Munich (Germany) | Germany |  | Enilive SpA | 89.00 |  | 73.30 |
|  |  |  | Eni International BV | 11.00 |  |  |
Enilive France Sàrl | Lyon (France) | France |  | Enilive SpA | 100.00 |  | 70.00 |
Enilive Iberia SLU | Alcobendas (Spain) | Spain |  | Enilive SpA | 100.00 |  | 70.00 |
Enilive Marketing Austria GmbH | Wien (Austria) | Austria |  | Enimoov Austria GmbH | 99.99 |  | 70.83 |
|  |  |  | Enilive SpA | (..) |  |  |
Enilive Schmiertechnik GmbH | Wurzburg (Germany) | Germany |  | Enilive Deutsch. GmbH | 100.00 |  | 73.30 |
Enilive Suisse SA | Lausanne (Switzerland) | Switzerland |  | Enilive SpA | 100.00 |  | 70.00 |
Enilive US Inc | Dover (USA) | USA |  | Enilive SpA | 100.00 |  | 70.00 |
Enimoov Austria GmbH | Wien (Austria) | Austria |  | Enilive Austria GmbH | 100.00 |  | 70.83 |

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Table of Contents

Plenitude

IN ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Eni Plenitude SpA Società Benefit | Milan | Italy |  | Eni SpA | 70.00 |  | 70.00 |
|  |  |  | Third parties | 30.00 |  |  |
Agrikroton Srl - Società Agricola | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Enerkall Srl | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Eni Plenitude Miniwind Srl | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Eni Plenitude Renewables Italy SpA | Milan | Italy |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Eni Plenitude Società Agricola Bio Srl | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Eni Plenitude Solar II Srl | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Eni Plenitude Storage Italy Srl | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Evolvere Venture SpA | Milan | Italy |  | Plen. En. Serv. SpA | 100.00 |  | 70.00 |
Fotovoltaica Pietramontecorvino Srl | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
FV4P Srl | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Gemsa Solar Srl | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
GPC Due Srl | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Green Parity Srl | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Lugo Società Agricola Srl | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Plenitude Energy Services SpA | Milan | Italy |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Plenitude On The Road Srl (former Be Charge Srl) | Milan | Italy |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Società Agricola Casemurate Srl | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Società Agricola Forestale Pianura Verde Srl | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Società Agricola L'Albero Azzurro Srl | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Timpe Muzzunetti 2 Srl | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 70.00 |  | 49.00 |
|  |  |  | Third parties | 30.00 |  |  |
Wind Salandra Srl | Cesena (FC) | Italy |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |

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OUTSIDE ITALY |  |  |  |  |  |  |  |
Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Adriaplin Podjetje za distribucijo zemeljskega plina doo Ljubljana | Ljubljana (Slovenia) | Slovenia |  | Eni Plenitude SpA SB | 51.00 |  | 35.70 |
|  |  |  | Third parties | 49.00 |  |  |
Aleria Solar SAS | Bastia (France) | France |  | Eni Plen. Op. Fr. SAS | 100.00 |  | 70.00 |
Almazara Solar SLU | Madrid (Spain) | Spain |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Alpinia Solar SLU | Madrid (Spain) | Spain |  | Eni Plen. Ren. Lux. Sàrl | 100.00 |  | 70.00 |
Argenta Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Argon SAS | Argenteuil (France) | France |  | Eni Plen. Op. Fr. SAS | 100.00 |  | 70.00 |
Armadura Solar SLU | Madrid (Spain) | Spain |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Athies-Samoussy Solar PV1 SAS | Argenteuil (France) | France |  | Krypton SAS | 100.00 |  | 70.00 |
Athies-Samoussy Solar PV2 SAS | Argenteuil (France) | France |  | Krypton SAS | 100.00 |  | 70.00 |
Athies-Samoussy Solar PV3 SAS | Argenteuil (France) | France |  | Krypton SAS | 100.00 |  | 70.00 |
Athies-Samoussy Solar PV4 SAS | Argenteuil (France) | France |  | Xenon SAS | 100.00 |  | 70.00 |
Athies-Samoussy Solar PV5 SAS | Argenteuil (France) | France |  | Xenon SAS | 100.00 |  | 70.00 |
Atlante Solar SLU | Madrid (Spain) | Spain |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Azursol Est SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Azursol Sud SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Belle Magiocche Solaire SAS | Bastia (France) | France |  | Eni Plen. Op. Fr. SAS | 100.00 |  | 70.00 |
Boceto Solar SLU | Madrid (Spain) | Spain |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Brazoria Class B Member Llc | Dover (USA) | USA |  | Eni New Energy US Inc | 100.00 |  | 70.00 |
Brazoria County Solar Project Llc | Dover (USA) | USA |  | Brazoria HoldCo Llc | 100.00 |  | 66.05 |
Brazoria HoldCo Llc | Dover (USA) | USA |  | Brazoria Class B | 94.36 |  | 66.05 |
|  |  |  | Third parties | 5.64 |  |  |
Brown Chapel Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
BT Kellam Solar Llc | Austin (USA) | USA |  | Kellam Tax Eq. Partn. | 100.00 |  | 65.73 |
Burlington Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Cattlemen Class A Llc | Dover (USA) | USA |  | Eni New Energy US Inc | 100.00 |  | 70.00 |
Centrale Eolienne de la Verte Epine SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Eolienne de l'Orvin SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Eolienne des Ailes de Foulzy SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Eolienne de Viersat SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Eolienne du Pays entre Madon et Moselle SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 91.00 |  | 63.70 |
|  |  |  | Third parties | 9.00 |  |  |
Centrale Eolienne la Garenne SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Eolienne Largeasse SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Eolienne le Mont de Malan SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Eolienne les Hauts Chemins SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Eolienne Neo Avel SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Eolienne Terrajeaux SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Photovoltaique de Mer SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Antugnac 2 SAS | Levallois-Perret (France) | France |  | Plen. Prod. France SAS | 100.00 |  | 70.00 |
Centrale Solaire Arue 1 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Arue 2 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Arue 3 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Cessieu Nord Isere SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Corbas 1 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |

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Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Centrale Solaire Corbas 3 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Helys SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 60.00 |  | 42.00 |
|  |  |  | Third parties | 40.00 |  |  |
Centrale Solaire le Bernardan 2 SAS | Levallois-Perret (France) | France |  | Plen. Prod. France SAS | 100.00 |  | 70.00 |
Centrale Solaire les Huchanes SAS | Levallois-Perret (France) | France |  | Plen. Prod. France SAS | 100.00 |  | 70.00 |
Centrale Solaire Morcenx 1 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Morcenx 2 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Morhange 2 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 6 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 8 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 9 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 10 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 11 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 12 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 18 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 19 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 20 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 21 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 24 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 26 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 28 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 31 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 34 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 38 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 43 SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Orion 50 SAS | Levallois-Perret (France) | France |  | Plen. Prod. France SAS | 100.00 |  | 70.00 |
Centrale Solaire Poullignac SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 86.51 |  | 60.55 |
|  |  |  | Third parties | 13.49 |  |  |
Centrale Solaire Saint Avit SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrale Solaire Valenciennes Aerodrome SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Centrales Solaires Delta SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Chapitel Solar SLU | Madrid (Spain) | Spain |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Chimney Creek Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Corazon Energy Class B Llc | Dover (USA) | USA |  | Eni New Energy US Inc | 100.00 |  | 70.00 |
Corazon Energy Llc | Dover (USA) | USA |  | Corazon Tax Eq. Part. Llc | 100.00 |  | 66.81 |
Corazon Tax Equity Partnership Llc | Dover (USA) | USA |  | Corazon En. Class B Llc | 95.45 |  | 66.81 |
|  |  |  | Third parties | 4.55 |  |  |
Cornisa Solar SLU | Madrid (Spain) | Spain |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Daviess County Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Delta Stockage SAS | Levallois-Perret (France) | France |  | Plen. Prod. France SAS | 70.00 |  | 49.00 |
|  |  |  | Third parties | 30.00 |  |  |
Eagle Springs Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Ekain Renovables SLU | Madrid (Spain) | Spain |  | Eni Plen. T. S. Spain | 100.00 |  | 70.00 |
Emery Bull Creek Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Enera Conseil SAS | Levallois-Perret (France) | France |  | Eni Plenitude France SAS | 100.00 |  | 70.00 |
Energías Ambientales de Outes SLU | Madrid (Spain) | Spain |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |

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Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Eni New Energy US Holding Llc | Dover (USA) | USA |  | Eni New Energy US Inc | 99.00 |  | 70.00 |
|  |  |  | Eni New Energy US Inv.Inc | 1.00 |  |  |
Eni New Energy US Inc | Dover (USA) | USA |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Eni New Energy US Investing Inc | Dover (USA) | USA |  | Eni New Energy US Inc | 100.00 |  | 70.00 |
Eni Plenitude France SAS (former Eni Gas & Power France SA) | Levallois-Perret (France) | France |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Eni Plenitude Iberia SLU | Santander (Spain) | Spain |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Eni Plenitude Investment Colombia SAS | Bogotà (Colombia) | Colombia |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Eni Plenitude Investment Spain SLU | Madrid (Spain) | Spain |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Eni Plenitude Operations France SAS | Argenteuil (France) | France |  | Eni Plen. Ren. Lux. Sàrl | 100.00 |  | 70.00 |
Eni Plenitude Renewables Australia Pty Ltd (former Eni New Energy Australia Pty Ltd) | Perth (Australia) | Australia |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Eni Plenitude Renewables Batchelor Pty Ltd (former Eni New Energy Batchelor Pty Ltd) | Perth (Australia) | Australia |  | Eni Plen Ren Aus. Pty Ltd | 100.00 |  | 70.00 |
Eni Plenitude Renewables France SAS | Argenteuil (France) | France |  | Eni Plen. Ren. Lux. Sàrl | 100.00 |  | 70.00 |
Eni Plenitude Renewables Hellas Single Member SA | Athens (Greece) | Greece |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Eni Plenitude Renewables Holding BV (former Eni Energy Solutions BV) | Amsterdam (Netherlands) | Netherlands |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Eni Plenitude Renewables Katherine Pty Ltd (former Eni New Energy Katherine Pty Ltd) | Perth (Australia) | Australia |  | Eni Plen Ren Aus. Pty Ltd | 100.00 |  | 70.00 |
Eni Plenitude Renewables Luxembourg Sàrl | Luxembourg (Luxembourg) | Luxembourg |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Eni Plenitude Renewables Manton Dam Pty Ltd (former Eni New Energy Manton Dam Pty Ltd) | Perth (Australia) | Australia |  | Eni Plen Ren Aus. Pty Ltd | 100.00 |  | 70.00 |
Eni Plenitude Renewables Spain SLU | Madrid (Spain) | Spain |  | Eni Plenitude SpA SB | 63.67 |  | 70.00 |
|  |  |  | Eni Plen. Ren. Lux. Sàrl | 30.05 |  |  |
|  |  |  | Energías Amb. de Outes | 6.28 |  |  |
Eni Plenitude Rooftop France SAS | Argenteuil (France) | France |  | Eni Plen. Ren. Lux. Sàrl | 100.00 |  | 70.00 |
Eni Plenitude Technical Services Colombia SAS | Bogotà (Colombia) | Colombia |  | Eni Plen. Ren. Italy SpA | 60.00 |  | 42.00 |
|  |  |  | Third parties | 40.00 |  |  |
Eni Plenitude Technical Services Romania Srl | Cluj-Napoca (Romania) | Romania |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Eni Plenitude Technical Services Spain SLU | Madrid (Spain) | Spain |  | Eni Plen. Ren. Italy SpA | 100.00 |  | 70.00 |
Eolica Cuellar de la Sierra SLU | Madrid (Spain) | Spain |  | Eni Plen. Inv. Spain SLU | 100.00 |  | 70.00 |
Eoliennes Chemin Vert SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Eoliennes Courcome SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Estanque Redondo Solar SLU | Madrid (Spain) | Spain |  | Eni Plen. Ren. Lux. Sàrl | 100.00 |  | 70.00 |
Five Mile Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Flat Bayou Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Fortaleza Solar SLU | Madrid (Spain) | Spain |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Fotovoltaica Fotozar 5 SLU | Madrid (Spain) | Spain |  | Eni Plen. Ren. Spain SLU | 100.00 |  | 70.00 |
Fotovoltaica Fotozar 6 SLU | Madrid (Spain) | Spain |  | Eni Plen. Ren. Spain SLU | 100.00 |  | 70.00 |
Garita Solar SLU | Madrid (Spain) | Spain |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Gas Supply Company Thessaloniki - Thessalia SA | Thessaloniki (Greece) | Greece |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Golden Acres Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |

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Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Granville Invest SLU | Madrid (Spain) | Spain |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Guajillo Energy Storage Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Hanks Crossing Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Holding Lanas Solar Sàrl | Argenteuil (France) | France |  | Eni Plen. Op. Fr. SAS | 100.00 |  | 70.00 |
Huisache Solar Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Inveese SAS | Bogotá (Colombia) | Colombia |  | Eni Plen. Inv. Colombia | 75.00 |  | 52.50 |
|  |  |  | Third parties | 25.00 |  |  |
Kellam Solar Class B Llc | Dover (USA) | USA |  | Eni New Energy US Inc | 100.00 |  | 70.00 |
Kellam Tax Equity Partnership Llc | Dover (USA) | USA |  | Kellam Solar Class B | 93.90 |  | 65.73 |
|  |  |  | Third parties | 6.10 |  |  |
Killington SLU | Madrid (Spain) | Spain |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Krypton SAS | Argenteuil (France) | France |  | Eni Plen. Op. Fr. SAS | 100.00 |  | 70.00 |
Ladronera Solar SLU | Madrid (Spain) | Spain |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Lanas Solar SAS | Argenteuil (France) | France |  | Holding Lanas Solar Sàrl | 100.00 |  | 70.00 |
Lone Pine Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Maristella Directorship SLU | Madrid (Spain) | Spain |  | Eni Plen. Ren. Spain SLU | 100.00 |  | 70.00 |
Membrio Solar SLU | Lodosa (Spain) | Spain |  | Eni Plen. Ren. Lux. Sàrl | 100.00 |  | 70.00 |
Miburia Trade SLU | Madrid (Spain) | Spain |  | Eni Plen. T. S. Spain | 100.00 |  | 70.00 |
Muddy Creek Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Olea Solar SLU | Madrid (Spain) | Spain |  | Eni Plen. Ren. Lux. Sàrl | 100.00 |  | 70.00 |
Parc Eolien des Avaloirs SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
Plenitude Kazakhstan Llp (former Arm Wind Llp) | Astana (Kazakhstan) | Kazakhstan |  | Eni Plen. Ren. Hold. BV | 100.00 |  | 70.00 |
Plenitude Production France SAS | Levallois-Perret (France) | France |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Plenitude Zephyr France SAS | Levallois-Perret (France) | France |  | Plen. Prod. France SAS | 100.00 |  | 70.00 |
Plumlee SLU | Madrid (Spain) | Spain |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
POP Solar SAS | Argenteuil (France) | France |  | Eni Plen. Ren. Lux. Sàrl | 100.00 |  | 70.00 |
Quiver River Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Renopool 1 SLU | Madrid (Spain) | Spain |  | Eni Plen. Ren. Spain SLU | 100.00 |  | 70.00 |
Richwood Invest SLU | Madrid (Spain) | Spain |  | Eni Plenitude SpA SB | 100.00 |  | 70.00 |
Sandrini 100 Class B Member Llc | Dover (USA) | USA |  | Eni New Energy US Inc | 100.00 |  | 70.00 |
Sandrini 200 Class B Member Llc | Dover (USA) | USA |  | Eni New Energy US Inc | 100.00 |  | 70.00 |
Sandrini BESS Class B Member Llc | Dover (USA) | USA |  | Eni New Energy US Inc | 100.00 |  | 70.00 |
SASU PV Les Poulettes SAS | Levallois-Perret (France) | France |  | Plen. Zephyr France SAS | 100.00 |  | 70.00 |
SKGRPV1 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |
SKGRPV2 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |

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Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
SKGRPV3 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |
SKGRPV4 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |
SKGRPV5 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |
SKGRPV6 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |
SKGRPV7 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |
SKGRPV8 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |
SKGRPV9 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |
SKGRPV12 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |
SKGRPV13 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |
SKGRPV14 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |
SKGRPV15 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |
SKGRPV16 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |
SKGRPV17 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |
SKGRPV19 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |
SKGRPV20 Single Member Private Company | Athens (Greece) | Greece |  | Eni Plen. Renew. Hellas | 100.00 |  | 70.00 |
South Triangle Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Tallahatchie Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Tantalio Renovables SLU | Madrid (Spain) | Spain |  | Eni Plen. Ren. Spain SLU | 100.00 |  | 70.00 |
Timber Road Blue Harvest Class A Llc | Dover (USA) | USA |  | Eni New Energy US Inc | 100.00 |  | 70.00 |
Turner Creek Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Watertown Energy Llc | Dover (USA) | USA |  | Eni New Energy US H. Llc | 100.00 |  | 70.00 |
Wind Grower SLU | Ourense (Spain) | Spain |  | Eni Plen. T. S. Spain | 100.00 |  | 70.00 |
Wind Hero SLU | Ourense (Spain) | Spain |  | Eni Plen. T. S. Spain | 100.00 |  | 70.00 |
Xenon SAS | Argenteuil (France) | France |  | Eni Plen. Op. Fr. SAS | 100.00 |  | 70.00 |

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CORPORATE AND OTHER ACTIVITIES

Corporate and financial companies

IN ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Agenzia Giornalistica Italia SpA | Rome | Italy |  | Eni SpA | 100.00 |  | 100.00 |
D-Share SpA | San Donato Milanese (MI) | Italy |  | AGI SpA | 100.00 |  | 100.00 |
EniBioCh4in Aprilia Srl | San Donato Milanese (MI) | Italy |  | EniBioCh4in SpA | 100.00 |  | 85.00 |
EniBioCh4in Grupellum Società Agricola Srl | San Donato Milanese (MI) | Italy |  | EniBioCh4in SpA | 98.00 |  | 83.30 |
|  |  |  | Third parties | 2.00 |  |  |
EniBioCh4in Jonica Srl | San Donato Milanese (MI) | Italy |  | EniBioCh4in SpA | 100.00 |  | 85.00 |
EniBioCh4in Pannellia BioGas Srl Società Agricola | San Donato Milanese (MI) | Italy |  | EniBioCh4in SpA | 100.00 |  | 85.00 |
EniBioCh4in Po Energia Srl Società Agricola | San Donato Milanese (MI) | Italy |  | EniBioCh4in SpA | 100.00 |  | 85.00 |
EniBioCh4in Quadruvium Srl Società Agricola | San Donato Milanese (MI) | Italy |  | EniBioCh4in SpA | 100.00 |  | 85.00 |
EniBioCh4in SpA | San Donato Milanese (MI) | Italy |  | Enilive SpA | 50.00 |  | 85.00 |
|  |  |  | Eni SpA | 50.00 |  |  |
Eni Corporate University SpA | San Donato Milanese (MI) | Italy |  | Eni SpA | 100.00 |  | 100.00 |
Eni Insurance SpA | Rome | Italy |  | Eni SpA | 100.00 |  | 100.00 |
EniServizi SpA | San Donato Milanese (MI) | Italy |  | Eni SpA | 100.00 |  | 100.00 |
Eniverse Ventures Srl | San Donato Milanese (MI) | Italy |  | Eni SpA | 100.00 |  | 100.00 |
Enivibes Srl | Vimodrone (MI) | Italy |  | Eniverse | 76.00 |  | 76.00 |
|  |  |  | Third parties | 24.00 |  |  |
Servizi Aerei SpA | San Donato Milanese (MI) | Italy |  | Eni SpA | 100.00 |  | 100.00 |

OUTSIDE ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Banque Eni SA | Bruxelles (Belgium) | Belgium |  | Eni International BV | 99.90 |  | 100.00 |
|  |  |  | Eni Oil Holdings BV | 0.10 |  |  |
Eni International BV | Amsterdam (Netherlands) | Netherlands |  | Eni SpA | 100.00 |  | 100.00 |
Eni International Resources Ltd | London (United Kingdom) | United Kingdom |  | Eni SpA | 99.99 |  | 100.00 |
|  |  |  | Eni UK Ltd | (..) |  |  |
Eni Netherlands Holding BV | Amsterdam (Netherlands) | Netherlands |  | Eni International BV | 100.00 |  | 100.00 |
Eni Next Llc | Dover (USA) | USA |  | Eni Petroleum Co Inc | 100.00 |  | 100.00 |

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Other activities

IN ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Eni Rewind SpA | San Donato Milanese (MI) | Italy |  | Eni SpA | 99.99 |  | 100.00 |
|  |  |  | Third parties | (..) |  |  |

JOINT OPERATIONS

EXPLORATION & PRODUCTION

OUTSIDE ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
NOGAT BV | The Hague (Netherlands) | Netherlands |  | Eni En. Holding NL BV | 15.00 |  | 15.00 |
|  |  |  | Third parties | 85.00 |  |  |

GLOBAL GAS & LNG PORTFOLIO AND POWER

OUTSIDE ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Blue Stream Pipeline Co BV | Amsterdam (Netherlands) | Russia |  | Eni International BV | 50.00 |  | 74.62 | (a)
|  |  |  | Third parties | 50.00 |  |  |
Damietta LNG (DLNG) SAE | Damietta (Egypt) | Egypt |  | Eni Gas Liquef. BV | 50.00 |  | 50.00 |
|  |  |  | Third parties | 50.00 |  |  |
DLNG Service SAE | Damietta (Egypt) | Egypt |  | Damietta LNG | 98.00 |  | 50.00 |
|  |  |  | Eni Gas Liquef. BV | 1.00 |  |  |
|  |  |  | Third parties | 1.00 |  |  |
GreenStream BV | Amsterdam (Netherlands) | Libya |  | Eni North Africa BV | 50.00 |  | 50.00 |
|  |  |  | Third parties | 50.00 |  |  |

(a) Equity ratio equal to the Eni's working interest.

POWER

IN ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Società EniPower Ferrara Srl | San Donato Milanese (MI) | Italy |  | EniPower SpA | 51.00 |  | 26.01 |
|  |  |  | Third parties | 49.00 |  |  |

REFINING AND CHEMICALS

Refining

IN ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Costiero Gas Livorno SpA | Livorno | Italy |  | Ecofuel SpA | 65.00 |  | 65.00 |
|  |  |  | Third parties | 35.00 |  |  |
Raffineria di Milazzo ScpA | Milazzo (ME) | Italy |  | Eni SpA | 50.00 |  | 50.00 |
|  |  |  | Third parties | 50.00 |  |  |

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OUTSIDE ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Supermetanol CA | Jose Puerto La Cruz (Venezuela) | Venezuela |  | Ecofuel SpA | 34.51 |  | 50.00 | (a)
|  |  |  | Supermetanol CA | 30.07 |  |  |
|  |  |  | Third parties | 35.42 |  |  |

(a) Equity ratio equal to the Eni's working interest.

ENILIVE AND PLENITUDE

ENILIVE

OUTSIDE ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
Bayernoil Raffineriegesellschaft mbH | Vohburg (Germany) | Germany |  | Enilive Deutsch. GmbH | 20.00 |  | 14.66 |
|  |  |  | Third parties | 80.00 |  |  |

CORPORATE AND OTHER ACTIVITIES

Other activities

IN ITALY

Company name | Registered office | Country of operation |  | Shareholders | % Ownership |  | % Equity ratio |
HEA SpA | Bologna | Italy |  | Eni Rewind SpA | 50.00 |  | 50.00 |
|  |  |  | Third parties | 50.00 |  |  |

Information on Eni’s consolidated subsidiaries with significant non-controlling interest

The following section provides information about economic, equity and financial data, gross of intragroup elisions, relating to Enilive Group, 70% owned by Eni, the Plenitude Group, 70% owned by Eni, and EniPower group, 51% owned by Eni. The ownership of the non-controlling interest corresponds to voting rights.

| Enilive Group | Plenitude Group | EniPower Group
(€ million) | 2025 | 2025 | 2024 | 2025 | 2024
Non controlling interest (%) | 30.00 | 30.00 | 7.58 | 49.00 | 49.00
Current assets | 5,607 | 3,725 | 4,571 | 851 | 695
Non-current assets | 4,683 | 12,053 | 11,185 | 927 | 934
Current liabilities | 5,605 | 4,482 | 4,626 | 839 | 709
Non-current liabilities | 1,786 | 5,351 | 5,156 | 29 | 31
Revenues | 19,120 | 10,168 | 10,179 | 1,142 | 962
Profit | 344 | (3) | 803 | 126 | 167
Total comprehensive income | 268 | (158) | 821 | 126 | 167
Net cash provided by operating activities | 771 | 1,196 | 916 | 206 | 178
Net cash used in investing activities | (542) | (1,206) | (1,389) | (77) | (92)
Net cash used in financing activities | 435 | (13) | (85) | 1 | (18)
Net increase (decrease) in cash and cash equivalents | 773 | 104 | (23) | 21 | (9)
Profit attributable to non-controlling interest | 87 | 6 | 54 | 64 | 85
Dividends paid to minority interest | 212 | 9 | 5 | 56 | 41

Equity pertaining to non-controlling interests as of December 31, 2025, amounted to €4,847 million (€2,863 million December 31, 2024) and includes the perpetual subordinated bond of Eni Marine Services SpA of €1,701 million. More information is reported in note 26 – Equity – Non-controlling interest.

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Changes in the ownership interest without loss of control

On March 6, 2025, Eni and the private equity fund KKR finalized KKR's investment in a 25% minority stake in its subsidiary Enilive, with total proceeds for Eni of €2,968 million, including a capital increase of €500 million. Subsequently, on April 11, 2025, Eni and KKR completed a similar transaction for an additional 5% investment for approximately €601 million. Following the transaction, KKR holds a total stake of 30% of Enilive’s share capital.

On March 31, 2025, Energy Infrastructure Partners (EIP) completed an increase in Plenitude's share capital, reaching a total stake of 10%. EIP's increase was achieved through a capital increase of approximately €209 million, which, taking into account the of €588 million paid in March 2024, brings the total investment to approximately €800 million. On November 4, Eni and the private equity fund Ares Capital finalized an investment in a 20% minority stake in Plenitude for €2,003 million.

Principal joint ventures, joint operations and associates as of December 31, 2025

Company name | Registered office | Country of operation | Segment | % ownership | % equity ratio
Joint venture |  |  |  |  |
2023 Sol IX Llc | Wilmington (USA) | USA | Plenitude | 73.62 | 73.62
Azule Energy Holdings Ltd | London (United Kingdom) | United Kingdom | Exploration & Production | 50.00 | 50.00
Cardón IV SA | Caracas (Venezuela) | Venezuela | Exploration & Production | 50.00 | 50.00
Eni CCUS Holding Ltd | London (United Kingdom) | United Kingdom | Exploration & Production | 50.01 | 50.01
E&E Algeria Touat BV | The Hague (Netherlands) | Algeria | Exploration & Production | 66.00 | 66.00
GreenIT SpA | San Donato Milanese (MI) (Italy) | Italy | Plenitude | 51.00 | 51.00
Mozambique Rovuma Venture SpA | San Donato Milanese (MI) (Italy) | Mozambique | Exploration & Production | 35.71 | 35.71
Saipem SpA | Milan (Italy) | Italy | Corporate and financial companies | 21.19 | 21.80
SeaCorridor Srl | San Donato Milanese (MI) (Italy) | Italy | Global Gas & LNG Portfolio | 50.10 | 50.10
St. Bernard Renewables Llc | Wilmington (USA) | USA | Enilive | 50.00 | 50.00
Vårgrønn AS | Stavanger (Norway) | Norway | Plenitude | 65.00 | 65.00
Joint Operation |  |  |  |  |
Damietta LNG (DLNG) SAE | Damietta (Egypt) | Egypt | Global Gas & LNG Portfolio | 50.00 | 50.00
GreenStream BV | Amsterdam (Netherlands) | Libya | Global Gas & LNG Portfolio | 50.00 | 50.00
Blue Stream Pipeline Co BV | Amsterdam(Netherlands) | Russia | Global Gas & LNG Portfolio | 50.00 | 50.00
Associates |  |  |  |  |
ADNOC Global Trading Ltd | Abu Dhabi (United Arab Emirates) | United Arab Emirates | Refining | 20.00 | 20.00
Abu Dhabi Oil Refining Company (Takreer) | Abu Dhabi (United Arab Emirates) | United Arab Emirates | Refining | 20.00 | 20.00
Coral FLNG SA | Maputo (Mozambique) | Mozambique | Exploration & Production | 25.00 | 25.00
Ithaca Energy Plc | London (United Kingdom) | United Kingdom | Exploration & Production | 35.92 | 35.92
QatarEnergy LNG NFE (5) | Doha (Qatar) | Qatar | Exploration & Production | 25.00 | 25.00
Vår Energi ASA | Sandnes (Norvegia) | Norway | Exploration & Production | 63.04 | 63.04

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Main line items of profit and loss and balance sheet related to the joint ventures, represented by the amounts included in the reports accounted under IFRS of each company, are provided in the table below:

| 2025
(€ million) | Azule Energy Holdings Ltd | St. Bernard Renewables Llc | E&E Algeria Touat BV | Saipem SpA | SeaCorridor Srl
Current assets | 3,394 | 395 | 117 | 9,122 | 114
- of which cash and cash equivalent | 507 | 23 | 56 | 1,707 | 80
Non-current assets | 21,678 | 1,310 | 1,224 | 5,425 | 578
Total assets | 25,072 | 1,705 | 1,341 | 14,547 | 692
Current liabilities | 4,295 | 116 | 33 | 8,393 | 93
- of which current financial liabilities | 1,744 | 116 |  | 1,012 | 29
Non-current liabilities | 9,657 | 309 | 291 | 3,410 | 140
- of which non-current financial liabilities | 4,956 | 308 |  | 2,094 | 123
Total liabilities | 13,952 | 425 | 324 | 11,803 | 233
Net equity | 11,120 | 1,280 | 1,017 | 2,744 | 459
Eni’s share of the investment (%) | 50.00 | 50.00 | 66.00 | 21.80 | 50.10
Goodwill, Group capital gains and perpetual subordinated bonds | (926) | 17 |  | (17) | 181
Book value of the investment | 4,634 | 657 | 671 | 581 | 411
Revenues and other income | 3,917 | 999 | 287 | 15,508 | 343
Operating expense | (822) | (961) | (90) | (13,792) | (44)
Other operating profit (loss) | (47) | (75) |  |  |
Depreciation, amortization and impairments | (2,188) | (57) | (88) | (1,037) | (47)
Operating profit (loss) | 860 | (94) | 109 | 679 | 252
Finance income (expense) | (268) | 2 | (3) | (189) | (1)
Income (expense) from investments | 289 | (24) |  | 28 | 28
Profit (loss) before income taxes | 881 | (116) | 106 | 518 | 279
Income taxes | (238) |  | (53) | (207) | (214)
Profit (loss) | 643 | (116) | 53 | 311 | 65
Other comprehensive income (loss) | (1,212) | (182) | (115) | 156 | (24)
Total other comprehensive income (loss) | (569) | (298) | (62) | 467 | 41
Profit (loss) attributable to Eni | 415 | (58) | 35 | 71 | 32
Dividends received from the joint venture | 386 |  |  | 72 | 95

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| 2024
(€ million) | Azule Energy Holdings Ltd | St. Bernard Renewables Llc | E&E Algeria Touat BV | Saipem SpA | SeaCorridor Srl
Current assets | 3,181 | 313 | 130 | 9,675 | 134
- of which cash and cash equivalent | 549 | 72 | 55 | 2,158 | 89
Non-current assets | 23,042 | 1,577 | 1,497 | 4,844 | 580
Total assets | 26,223 | 1,890 | 1,627 | 14,519 | 714
Current liabilities | 3,505 | 99 | 54 | 8,564 | 126
- of which current financial liabilities | 1,182 |  |  | 796 |
Non-current liabilities | 9,796 | 217 | 376 | 3,431 | 15
- of which non-current financial liabilities | 3,297 | 215 |  | 2,220 | 1
Total liabilities | 13,301 | 316 | 430 | 11,995 | 141
Net equity | 12,922 | 1,574 | 1,197 | 2,524 | 573
Eni’s share of the investment (%) | 50.00 | 50.00 | 54.00 | 21.61 | 50.10
Goodwill, Group capital gains and perpetual subordinated bonds | (1,250) | 19 |  | (17) | 198
Book value of the investment | 5,211 | 806 | 646 | 528 | 485
Revenues and other income | 4,961 | 1,220 | 290 | 14,552 | 332
Operating expense | (1,261) | (1,134) | (98) | (13,224) | (45)
Other operating profit (loss) |  | (93) |  | 1 |
Depreciation, amortization and impairments | (1,479) | (72) | (105) | (723) | (44)
Operating profit (loss) | 2,221 | (79) | 87 | 606 | 243
Finance income (expense) | (474) | (11) |  | (85) | 6
Income (expense) from investments | 208 |  |  | (25) | 29
Profit (loss) before income taxes | 1,955 | (90) | 87 | 496 | 278
Income taxes | (751) |  | (13) | (190) | (189)
Profit (loss) | 1,204 | (90) | 74 | 306 | 89
Other comprehensive income (loss) | 572 | 99 | 72 | (124) | 11
Total other comprehensive income (loss) | 1,776 | 9 | 146 | 182 | 100
Profit (loss) attributable to Eni | 602 | (45) | 40 | 75 | 45
Dividends received from the joint venture | 427 |  |  |  | 95

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The results for the year and the comprehensive income of the significant joint ventures are shown below:

| 2025
(€ million) | 2023 Sol IX Llc | GreenIT SpA | Mozambique Rovuma Venture SpA | Cardón IV SA | Vårgrønn AS
Profit (loss) |  | 5 | 100 | 125 | (54)
Other comprehensive income (loss) | (24) | (1) | (131) | (87) | (42)
Total other comprehensive income (loss) | (24) | 4 | (31) | 38 | (96)

| 2024
(€ million) | 2023 Sol IX Llc | GreenIT SpA | Mozambique Rovuma Venture SpA | Cardón IV SA | Vårgrønn AS
Profit (loss) | 1 | 4 | 47 | (18) | (57)
Other comprehensive income (loss) | 8 | (2) | 64 | 47 | 26
Total other comprehensive income (loss) | 9 | 2 | 111 | 29 | (31)

Main line items of profit and loss and balance sheet related to the associates represented by the amounts included in the reports accounted under IFRS of each company are provided in the table below:

| 2025
(€ million) | Abu Dhabi Oil Refining Company (TAKREER) | Vår Energi ASA | Ithaca Energy Plc | QatarEnergy LNG NFE (5)
Current assets | 5,730 | 1,533 | 980 |
- of which cash and cash equivalent | 6 | 595 | 154 |
Non-current assets | 15,401 | 20,705 | 6,194 | 2,863
Total assets | 21,131 | 22,238 | 7,174 | 2,863
Current liabilities | 4,857 | 2,316 | 1,242 | 151
- of which current financial liabilities |  | 199 | 62 |
Non-current liabilities | 6,373 | 19,446 | 3,758 | 70
- of which non-current financial liabilities | 5,995 | 5,067 | 1,243 |
Total liabilities | 11,230 | 21,762 | 5,000 | 221
Net equity | 9,901 | 476 | 2,174 | 2,642
Eni’s share of the investment (%) | 20.00 | 63.04 | 35.92 | 25.00
Goodwill, Group capital gains and perpetual subordinated bonds |  | (300) | (295) |
Book value of the investment | 1,980 |  | 486 | 661
Revenues and other income | 23,417 | 7,164 | 2,607 |
Operating expense | (21,341) | (1,409) | (815) | (12)
Other operating income (expense) | (831) |  |  |
Depreciation, amortization and impairments | (755) | (1,888) | (824) |
Operating profit (loss) | 490 | 3,867 | 968 | (12)
Finance income (expense) | (381) | 73 | (226) | (2)
Income (expense) from investments |  |  |  |
Profit (loss) before income taxes | 109 | 3,940 | 742 | (14)
Income taxes | 7 | (3,061) | (809) | 4
Profit (loss) | 116 | 879 | (67) | (10)
Other comprehensive income (loss) | (1,308) | 80 | (128) | (310)
Total other comprehensive income (loss) | (1,192) | 959 | (195) | (320)
Profit (loss) attributable to Eni | 23 | 602 | (15) | (3)
Dividends received from the associate | 56 | 653 | 161 |

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| 2024
(€ million) | Abu Dhabi Oil Refining Company (TAKREER) | Vår Energi ASA | Ithaca Energy Plc | QatarEnergy LNG NFE (5)
Current assets | 6,719 | 1,219 | 946 |
- of which cash and cash equivalent | 47 | 268 | 170 |
Non-current assets | 18,130 | 19,822 | 7,036 | 2,658
Total assets | 24,849 | 21,041 | 7,982 | 2,658
Current liabilities | 3,835 | 1,825 | 1,320 | 60
- of which current financial liabilities |  | 68 | 31 |
Non-current liabilities | 9,640 | 18,415 | 3,775 | 67
- of which non-current financial liabilities | 6,543 | 5,795 | 994 |
Total liabilities | 13,475 | 20,240 | 5,095 | 127
Net equity | 11,374 | 801 | 2,887 | 2,531
Eni’s share of the investment (%) | 20.00 | 63.04 | 37.17 | 25.00
Goodwill, Group capital gains and perpetual subordinated bonds |  | (505) | (348) |
Book value of the investment | 2,275 |  | 725 | 633
Revenues and other income | 12,879 | 6,884 | 703 |
Operating expense | (11,985) | (1,375) | (134) | (6)
Other operating income (expense) | (386) |  |  |
Depreciation, amortization and impairments | (338) | (1,884) | (367) |
Operating profit (loss) | 170 | 3,625 | 202 | (6)
Finance income (expense) | (332) | (455) | (66) | 1
Profit (loss) before income taxes | (162) | 3,170 | 136 | (5)
Income taxes |  | (2,759) | (118) | 1
Profit (loss) | (162) | 411 | 18 | (4)
Other comprehensive income (loss) | 708 | (125) | 100 | 138
Total other comprehensive income (loss) | 546 | 286 | 118 | 134
Profit (loss) attributable to Eni | (32) | 259 | 7 | (1)
Dividends received from the associate | 269 | 627 | 69 |

The results for the year and the comprehensive income of the significant associates are shown below:

| 2025
(€ million) | ADNOC Global Trading Ltd | Coral FLNG SA
Profit (loss) | 481 | (84)
Other comprehensive income (loss) | (106) | (104)
Total other comprehensive income (loss) | 375 | (188)

| 2024
(€ million) | ADNOC Global Trading Ltd | Coral FLNG SA
Profit (loss) | 563 | (33)
Other comprehensive income (loss) | 48 | 57
Total other comprehensive income (loss) | 611 | 24

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38 Significant non-recurring events and operations

In 2025, in 2024 and 2023, Eni did not report any non-recurring events and operations.

39 Positions or transactions deriving from atypical and/or unusual operations

In 2025, in 2024 and 2023, no transactions deriving from atypical and/or unusual operations were reported.

40 Subsequent events

After the balance sheet date and as the Iran conflict unfolded, oil, gas and refined products supply from the Middle East have been impacted. Commodity markets showed high volatility, creating uncertainty with regards to prices for oil and gas and refining margins. As at the date of these Consolidated Financial Statements, the conflict has not resulted in a material impact on Eni’s financial position and results of operations. The scale and duration of the conflict remain uncertain but could affect Eni's result, cash flow and financial condition.

On March 19, 2026, Eni initiated a reorganization of Plenitude's shareholding structure, together with the existing shareholders Ares Alternative Credit (affiliates of Ares Management Corporation) and Energy Infrastructure Partners. The aim is to establish a new governance framework based on joint control between Eni and Ares, resulting in the deconsolidation of Plenitude from Eni's financial statements. The transaction is subject to the approval of the competent authorities.

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Supplemental oil and gas information (unaudited)

The following information prepared in accordance with “International Financial Reporting Standards” (IFRS) is presented based on the disclosure rules of the FASB Extractive Activities - Oil and Gas (Topic 932). Amounts related to minority interests are immaterial.

Capitalized costs

Capitalized costs represent the total expenditures for proved and unproved mineral properties and related support equipment and facilities utilized in oil and gas exploration and production activities, together with related accumulated depreciation, depletion and amortization.

Capitalized costs by geographical area consist of the following:

(€ million) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
2025 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Proved property | 19,413 | 2,878 | 37,204 | 17,659 | 13,229 | 15,150 | 11,961 | 1,447 | 118,941
Unproved property | 22 | 102 | 544 | 957 |  | 1,260 | 341 | 207 | 3,433
Support equipment and facilities | 339 | 27 | 1,853 | 752 | 125 | 13 | 24 | 12 | 3,145
Incomplete wells and other | 727 | 323 | 2,846 | 1,598 | 731 | 2,754 | 375 | 125 | 9,479
Gross Capitalized Costs | 20,501 | 3,330 | 42,447 | 20,966 | 14,085 | 19,177 | 12,701 | 1,791 | 134,998
Accumulated depreciation, depletion and amortization | (17,215) | (2,712) | (30,329) | (11,343) | (5,351) | (11,981) | (9,843) | (915) | (89,689)
Net Capitalized Costs consolidated subsidiaries (a) | 3,286 | 618 | 12,118 | 9,623 | 8,734 | 7,196 | 2,858 | 876 | 45,309
Equity-accounted entities |  |  |  |  |  |  |  |  |
Proved property |  | 19,073 | 717 | 9,731 |  | 261 | 1,910 |  | 31,692
Unproved property |  | 205 | 173 | 76 |  |  |  |  | 454
Support equipment and facilities |  | 96 | 10 | 73 |  |  | 8 |  | 187
Incomplete wells and other |  | 1,053 | 22 | 2,731 |  | 455 | 221 |  | 4,482
Gross Capitalized Costs |  | 20,427 | 922 | 12,611 |  | 716 | 2,139 |  | 36,815
Accumulated depreciation, depletion and amortization |  | (7,803) | (192) | (3,377) |  |  | (1,518) |  | (12,890)
Net Capitalized Costs equity-accounted entities (a) (b) |  | 12,624 | 730 | 9,234 |  | 716 | 621 |  | 23,925

(a) The amounts include net capitalized financial charges totalling €747 million for consolidates subsidiaries and €1,075 million for equity-accounted entities.

(b) The amounts include the allocation at fair value of (i) the acquisition of an additional 12% stake in E&E Algeria Touat BV; (ii) the acquisition by Ithaca of JAPEX UK Limited and a stake of 46.25% of Spirit Energy; the acquisition by Var Energi of Ekofisk PPF's assets.

(€ million) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
2024 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Proved property | 19,272 | 3,242 | 43,769 | 30,245 | 14,379 | 15,223 | 16,212 | 1,626 | 143,968
Unproved property | 22 | 190 | 651 | 2,393 |  | 2,259 | 887 | 209 | 6,611
Support equipment and facilities | 339 | 29 | 2,012 | 837 | 138 | 14 | 26 | 13 | 3,408
Incomplete wells and other | 756 | 249 | 2,554 | 2,583 | 1,202 | 2,232 | 388 | 149 | 10,113
Gross Capitalized Costs | 20,389 | 3,710 | 48,986 | 36,058 | 15,719 | 19,728 | 17,513 | 1,997 | 164,100
Accumulated depreciation, depletion and amortization | (16,541) | (2,969) | (36,505) | (24,075) | (5,441) | (12,698) | (14,273) | (1,108) | (113,610)
Net Capitalized Costs consolidated subsidiaries (a) (c) | 3,848 | 741 | 12,481 | 11,983 | 10,278 | 7,030 | 3,240 | 889 | 50,490
Equity-accounted entities |  |  |  |  |  |  |  |  |
Proved property |  | 12,751 | 645 | 10,137 |  | 295 | 2,150 |  | 25,978
Unproved property |  | 1,178 | 149 | 88 |  |  |  |  | 1,415
Support equipment and facilities |  | 86 | 9 | 82 |  |  | 9 |  | 186
Incomplete wells and other |  | 4,989 | 22 | 2,246 |  | 370 | 249 |  | 7,876
Gross Capitalized Costs |  | 19,004 | 825 | 12,553 |  | 665 | 2,408 |  | 35,455
Accumulated depreciation, depletion and amortization |  | (6,799) | (140) | (2,809) |  |  | (1,644) |  | (11,392)
Net Capitalized Costs equity-accounted entities (a) (b) |  | 12,205 | 685 | 9,744 |  | 665 | 764 |  | 24,063

(a) The amounts include net capitalized financial charges totalling €830 million for consolidates subsidiaries and €996 million for equity-accounted entities.

(b) Includes allocation at fair value of the assets of Neptune Energy Group.

(c) Includes allocation at fair value of the assets of Neptune Energy Group and of Ithaca Energy in UK.

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Costs incurred

Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities. Costs incurred by geographical area consist of the following:

(€ million) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
2025 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Proved property acquisitions |  |  | 3 | 68 |  |  |  |  | 71
Unproved property acquisitions |  |  | 7 | 26 |  | 115 |  | 3 | 151
Exploration | 19 | 15 | 152 | 101 | 2 | 217 | 62 | 4 | 572
Development (a) | 177 | 53 | 2,346 | 1,842 | 195 | 1,935 | 560 | 162 | 7,270
Total costs incurred consolidated subsidiaries | 196 | 68 | 2,508 | 2,037 | 197 | 2,267 | 622 | 169 | 8,064
Equity-accounted entities |  |  |  |  |  |  |  |  |
Proved property acquisitions |  |  |  |  |  |  |  |  |
Unproved property acquisitions |  |  |  |  |  |  |  |  |
Exploration |  | 258 |  | 135 |  |  |  |  | 393
Development (b) |  | 1,761 | 26 | 1,440 |  | 133 | 10 |  | 3,370
Total costs incurred equity-accounted entities |  | 2,019 | 26 | 1,575 |  | 133 | 10 |  | 3,763

(a) Includes abandonment costs for €318 million in 2025.

(b) Includes abandonment costs for €87 million in 2025.

(€ million) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
2024 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Exploration | 47 | 53 | 98 | 139 | 57 | 128 | 124 | 2 | 648
Development (a) | 445 | 340 | 1,168 | 3,250 | 252 | 1,012 | 760 | 101 | 7,328
Total costs incurred consolidated subsidiaries | 492 | 393 | 1,266 | 3,389 | 309 | 1,140 | 884 | 103 | 7,976
Equity-accounted entities |  |  |  |  |  |  |  |  |
Exploration |  | 231 |  | 90 |  |  |  |  | 321
Development (b) |  | 1,850 | 15 | 1,191 |  | 157 | (6) |  | 3,207
Total costs incurred equity-accounted entities |  | 2,081 | 15 | 1,281 |  | 157 | (6) |  | 3,528

(a) Includes abandonment costs for €73 million in 2024.

(b) Includes abandonment costs for €42 million in 2024.

(€ million) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
2023 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Exploration | 12 | 55 | 328 | 189 | 9 | 277 | 138 | 1 | 1,009
Development (a) | 798 | 249 | 1,633 | 2,662 | 296 | 921 | 937 | 151 | 7,647
Total costs incurred consolidated subsidiaries | 810 | 304 | 1,961 | 2,851 | 305 | 1,198 | 1,075 | 152 | 8,656
Equity-accounted entities |  |  |  |  |  |  |  |  |
Exploration |  | 92 |  | 46 |  |  |  |  | 138
Development (b) |  | 1,703 | 4 | 731 |  | 150 | 2 |  | 2,590
Total costs incurred equity-accounted entities |  | 1,795 | 4 | 777 |  | 150 | 2 |  | 2,728

(a) Includes abandonment costs for €773 million in 2023.

(b) Includes abandonment costs for €163 million in 2023

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Results of operations from oil and gas producing activities

Results of operations from oil and gas producing activities represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expenses or general corporate overheads and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are calculated by applying the local income tax rates to the pre-tax income from production activities. Eni is party to certain Production Sharing Agreements (PSAs), whereby a portion of Eni’s share of oil and gas production is withheld and sold by its joint venture partners which are state owned entities, with proceeds being remitted to the state to fulfil Eni’s PSA related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni’s share of oil and gas production.

Results of operations from oil and gas producing activities by geographical area consist of the following:

(€ million) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
2025 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |
- sales to consolidated entities | 1,226 | 17 | 1,318 | 2,190 | 1,450 | 2,986 | 1,159 | 1 | 10,347
- sales to third parties |  | 249 | 5,650 | 902 | 815 | 398 | 159 | 30 | 8,203
Total revenues | 1,226 | 266 | 6,968 | 3,092 | 2,265 | 3,384 | 1,318 | 31 | 18,550
Production costs | (376) | (97) | (1,025) | (617) | (231) | (411) | (257) | (23) | (3,037)
Transportation costs | (4) | (18) | (63) | (3) | (170) | (7) | (10) |  | (275)
Production taxes | (114) | (1) | (246) | (234) |  | (293) | (100) |  | (988)
Exploration expenses | (21) | (10) | (60) | (28) | (2) | (53) | (33) | (4) | (211)
D.D. & A. and Provision for abandonment (a) | (792) | (119) | (1,669) | (1,639) | (569) | (1,152) | (684) | (116) | (6,740)
Other income (expenses) | (219) | (25) | (273) | (146) | (78) | (381) | (57) | (46) | (1,225)
Pretax income from producing activities | (300) | (4) | 3,632 | 425 | 1,215 | 1,087 | 177 | (158) | 6,074
Income taxes | 114 | 101 | (2,190) | (332) | (419) | (512) | (86) | 47 | (3,277)
Results of operations from E&P activities of consolidated subsidiaries | (186) | 97 | 1,442 | 93 | 796 | 575 | 91 | (111) | 2,797
Equity-accounted entities |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |
- sales to consolidated entities |  | 3,849 |  | 703 |  |  |  |  | 4,552
- sales to third parties |  | 1,483 | 186 | 1,609 |  |  | 652 |  | 3,930
Total revenues |  | 5,332 | 186 | 2,312 |  |  | 652 |  | 8,482
Production costs |  | (871) | (36) | (676) |  |  | (25) |  | (1,608)
Transportation costs |  | (187) | (13) |  |  |  | (2) |  | (202)
Production taxes |  |  | (2) | (31) |  |  | (147) |  | (180)
Exploration expenses |  | (138) |  | (14) |  |  |  |  | (152)
D.D. & A. and Provision for abandonment |  | (1,352) | (63) | (1,012) |  | (1) | (67) |  | (2,495)
Other income (expenses) |  | 163 | (1) | 34 |  | (2) | (305) |  | (111)
Pretax income from producing activities |  | 2,947 | 71 | 613 |  | (3) | 106 |  | 3,734
Income taxes |  | (2,288) | (31) | (206) |  | 1 | (13) |  | (2,537)
Results of operations from E&P activities of equity-accounted entities |  | 659 | 40 | 407 |  | (2) | 93 |  | 1,197

(a) Includes asset net impairment amounting to €1,081 million.

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(€ million) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
2024 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |
- sales to consolidated entities | 1,256 | 524 | 1,590 | 1,984 | 1,747 | 3,171 | 1,364 |  | 11,636
- sales to third parties |  | 462 | 7,135 | 892 | 958 | 752 | 138 | 19 | 10,356
Total revenues | 1,256 | 986 | 8,725 | 2,876 | 2,705 | 3,923 | 1,502 | 19 | 21,992
Production costs | (350) | (328) | (971) | (617) | (280) | (392) | (403) | (25) | (3,366)
Transportation costs | (4) | (86) | (65) | (8) | (175) | (8) | (15) |  | (361)
Production taxes | (139) | (1) | (299) | (276) |  | (339) | (73) |  | (1,127)
Exploration expenses | (16) | (158) | (148) | (54) | (81) | (243) | (39) | (2) | (741)
D.D. & A. and Provision for abandonment (a) | (606) | (440) | (1,880) | (2,121) | (555) | (1,142) | (1,373) | (52) | (8,169)
Other income (expenses) | (179) | (413) | (330) | (280) | (168) | (335) | (45) | (7) | (1,757)
Pretax income from producing activities | (38) | (440) | 5,032 | (480) | 1,446 | 1,464 | (446) | (67) | 6,471
Income taxes | 73 | 134 | (3,150) | (347) | (507) | (1,283) | 39 | 23 | (5,018)
Results of operations from E&P activities of consolidated subsidiaries | 35 | (306) | 1,882 | (827) | 939 | 181 | (407) | (44) | 1,453
Equity-accounted entities |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |
- sales to consolidated entities |  | 3,330 |  | 1,149 |  |  |  |  | 4,479
- sales to third parties |  | 1,213 | 162 | 1,682 |  |  | 669 |  | 3,726
Total revenues |  | 4,543 | 162 | 2,831 |  |  | 669 |  | 8,205
Production costs |  | (711) | (33) | (621) |  |  | (23) |  | (1,388)
Transportation costs |  | (151) | (15) |  |  |  | (3) |  | (169)
Production taxes |  |  | (2) | (42) |  |  | (148) |  | (192)
Exploration expenses |  | (119) |  | (7) |  |  |  |  | (126)
D.D. & A. and Provision for abandonment |  | (1,150) | (62) | (864) |  |  | (66) |  | (2,142)
Other income (expenses) |  | 37 | (26) | (127) |  | (1) | (333) |  | (450)
Pretax income from producing activities |  | 2,449 | 24 | 1,170 |  | (1) | 96 |  | 3,738
Income taxes |  | (1,839) | (2) | (456) |  |  | (42) |  | (2,339)
Results of operations from E&P activities of equity-accounted entities |  | 610 | 22 | 714 |  | (1) | 54 |  | 1,399

(a) Includes asset net impairment amounting to €2,203 million.

(€ million) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
2023 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |
- sales to consolidated entities | 1,475 | 862 | 1,477 | 1,745 | 1,845 | 2,970 | 1,661 | 1 | 12,036
- sales to third parties |  | 18 | 7,936 | 903 | 897 | 532 | 135 | 51 | 10,472
Total revenues | 1,475 | 880 | 9,413 | 2,648 | 2,742 | 3,502 | 1,796 | 52 | 22,508
Production costs | (348) | (202) | (952) | (656) | (267) | (304) | (469) | (25) | (3,223)
Transportation costs | (3) | (43) | (68) | (10) | (178) | (6) | (19) |  | (327)
Production taxes | (152) |  | (300) | (294) |  | (326) | (73) |  | (1,145)
Exploration expenses | (12) | (14) | (245) | (121) | (2) | (140) | (152) | (1) | (687)
D.D. & A. and Provision for abandonment (a) | (886) | (166) | (1,979) | (716) | (601) | (1,093) | (1,531) | (95) | (7,067)
Other income (expenses) | (347) | (117) | (360) | (128) | (148) | (263) | (108) | (7) | (1,478)
Pretax income from producing activities | (273) | 338 | 5,509 | 723 | 1,546 | 1,370 | (556) | (76) | 8,581
Income taxes | 169 | (292) | (3,368) | (391) | (503) | (1,150) | 369 | 19 | (5,147)
Results of operations from E&P activities of consolidated subsidiaries | (104) | 46 | 2,141 | 332 | 1,043 | 220 | (187) | (57) | 3,434
Equity-accounted entities |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |
- sales to consolidated entities |  | 2,911 |  | 958 |  |  |  |  | 3,869
- sales to third parties |  | 1,063 | 10 | 1,905 |  |  | 604 |  | 3,582
Total revenues |  | 3,974 | 10 | 2,863 |  |  | 604 |  | 7,451
Production costs |  | (562) | (6) | (535) |  |  | (20) |  | (1,123)
Transportation costs |  | (102) | (1) | (26) |  |  | (3) |  | (132)
Production taxes |  |  | (2) | (54) |  |  | (126) |  | (182)
Exploration expenses |  | (50) |  | (37) |  |  |  |  | (87)
D.D. & A. and Provision for abandonment |  | (1,116) | (5) | (1,314) |  | (1) | (68) |  | (2,504)
Other income (expenses) |  | (78) | (1) | 24 |  | (4) | (372) |  | (431)
Pretax income from producing activities |  | 2,066 | (5) | 921 |  | (5) | 15 |  | 2,992
Income taxes |  | (1,614) | 6 | (273) |  | 1 | (56) |  | (1,936)
Results of operations from E&P activities of equity-accounted entities |  | 452 | 1 | 648 |  | (4) | (41) |  | 1,056

(a) Includes asset net impairment amounting to €1,036 million.

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Proved reserves of oil and natural gas

Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves comply with Regulation S-X 4-10 of the U.S. Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities – Oil and Gas (Topic 932).

Proved oil and gas reserves are those quantities of oil and 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, and 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, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. In 2025, the average price for the marker Brent crude oil was $70 per barrel. Net proved reserves exclude interests and royalties owned by others.

Proved reserves are classified as either developed or undeveloped. Developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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Eni has its proved reserves evaluated on a rotational basis by independent oil engineering companies 24. The description of qualifications of the person primarily responsible of the reserves audit is included in the third-party audit report 25. In the preparation of their reports, independent evaluators rely, without independent verification, upon data furnished by Eni with respect to property interest, production, current costs of operation and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. Eni’s net equity share after cost recovery. 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 and technical analysis relevant to field performance, long-term development plans, future capital and operating costs. In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements, and other pertinent information are provided.

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 Eni 26.

In 2025, an independent evaluation of about 36%27 of Eni’s total proved reserves as of December 31, 2025, confirming, as in previous years, the reasonableness of Eni’s internal evaluations. In the three-year period from 2023 to 2025, 82% of Eni’s total proved reserves were subject to independent evaluation.

Eni operates under production sharing agreements in several of the foreign jurisdictions where it has oil and gas exploration and production activities. Reserves of oil and natural gas to which Eni is entitled under PSA arrangements are shown in accordance with Eni’s economic interest in the volumes of oil and natural gas estimated to be recoverable in future years. Such reserves include estimated quantities allocated to Eni for recovery of costs, income taxes owed by Eni but settled by its joint venture partners (which are state-owned entities) out of Eni’s share of production and Eni’s net equity share after cost recovery. Proved oil and gas reserves associated with PSAs represented 60%, 57% and 55% of total proved reserves as of December 31, 2025, 2024 and 2023 respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service contracts; proved reserves related to these contracts represent 2% of total proved reserves in barrels of oil equivalent in the three-year period 2023-2025.

Oil and gas reserves quantities include: (i) oil and natural gas quantities in excess of cost recovery which the company has an obligation to purchase under certain PSAs with governments or authorities, whereby the company serves as producer of reserves. Reserves volumes associated with oil and gas deriving from such obligation represent 1%, 1% and 2% of total proved reserves as of December 31, 2025, 2024 and 2023, respectively, on an oil equivalent basis; (ii) volumes of proved reserves of natural gas to be consumed in operations amounted to 2,614 BCF at 2025 year-end (2,380 BCF and 2,338 BCF respectively at 2024 and 2023 year-end); (iii) the quantities of hydrocarbons related to the Angola LNG plant owned by the JV Azule set up 50% with bp.

Numerous uncertainties are inherent in estimating quantities of proved reserves, in projecting future productions and development costs. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. The results of drilling, testing and production after the date of the estimate may require substantial upward or downward revisions. In addition, changes in oil and natural gas prices have an effect on the quantities of Eni’s proved reserves since estimates of reserves are based on prices and costs relevant to the date when such estimates are made. Consequently, the evaluation of reserves could also significantly differ from actual oil and natural gas volumes that will be produced.

Proved undeveloped reserves

Proved undeveloped reserves as of December 31, 2025, amount to 3,027 mmBOE, of which 1,082 mmBBL of liquids and 288 BCF of natural gas, mainly 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 provides a summary of changes in total proved undeveloped reserves for 2025.

(mmboe) |
Proved undeveloped reserves as of December 31, 2024 | 2,787
Transfer 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

24 For the past three years we have availed of the independent certification service of DeGolyer and Mac Naughton, Ryder Scott, and Sproule.

25 The reports of independent engineers are available on Eni website eni.com section Publications/Annual Report 2025.

26 In 2025 Azule and Vår Energi.

27 In 2025, the volumes of Azule Energy and Vår Energi are included, for which Eni has requested a Third Party Letter.

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In 2025, proved undeveloped reserves increased by 240 mmboe (proved undeveloped reserves of consolidated companies increased by 388 mmboe, while those of joint ventures and associates decreased by 148 mmboe). Main changes derived from:

i) progress in the conversion to Proved Reserves (-370 mmboe), mainly due to the advancement of development activities, field start-ups, and the review of projects related to assets in Vår Energi in Norway, the United Arab Emirates, and Azule Energy in Angola;

ii) new discoveries and extensions totalling 585 million boe, including 97 mmboe of liquids and 488 mmboe of gas, resulting from the progress of the activity in Kutei Basin in Indonesia (563 mmboe), in Sarb field in the United Arab Emirates (13 mmboe), and minor projects in the Netherlands, Norway, and Angola;

iii) revisions to previous estimates (23 mmboe), excluding conversion to developed reserves, mainly relate to: the progress of development activities in the United Arab Emirates (54 mmboe), in Vår Energi in Norway (53 mmboe) and in Egypt (41 mmboe). The downward revisions mainly relate to a reduction in Libya (-37 mmboe) and Azule Energy in Angola (-63 mmboe);

iv) improved recovery for 26 mmboe in Iraq at the Zubair field;

v) portfolio operations (-24 mmboe), mainly due to the sale of 30% of Baleine in Côte d'Ivoire and assets in Congo, offset by the acquisition of a stake in Bonga in Nigeria.

Proved reserves of crude oil (including condensate and natural gas liquids)

(million barrels) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
2025 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Reserves at December 31, 2024 | 213 |  | 458 | 268 | 591 | 578 | 127 |  | 2,235
of which: developed | 129 |  | 291 | 187 | 539 | 233 | 81 |  | 1,460
undeveloped | 84 |  | 167 | 81 | 52 | 345 | 46 |  | 775
Purchase of Minerals in Place |  |  |  | 7 |  |  |  |  | 7
Revisions of Previous Estimates | (7) |  | 123 | 37 | 7 | 48 | 7 |  | 215
Improved Recovery |  |  |  | 7 |  | 26 |  |  | 33
Extensions and Discoveries |  |  |  |  |  | 96 |  |  | 96
Production | (9) |  | (64) | (39) | (42) | (35) | (23) |  | (212)
Sales of Minerals in Place |  |  |  | (28) |  |  |  |  | (28)
Reserves at December 31, 2025 | 197 |  | 517 | 252 | 556 | 713 | 111 |  | 2,346
Equity-accounted entities |  |  |  |  |  |  |  |  |
Reserves at December 31, 2024 |  | 391 | 8 | 226 |  | 110 | 23 |  | 758
of which: developed |  | 207 | 8 | 103 |  |  | 23 |  | 341
undeveloped |  | 184 |  | 123 |  | 110 |  |  | 417
Purchase of Minerals in Place |  | 3 |  |  |  |  |  |  | 3
Revisions of Previous Estimates |  | 39 | (2) | (6) |  | 1 |  |  | 32
Improved Recovery |  |  |  |  |  |  |  |  |
Extensions and Discoveries |  | 10 |  | 1 |  |  |  |  | 11
Production |  | (62) | (1) | (29) |  |  | (3) |  | (95)
Sales of Minerals in Place |  |  |  |  |  |  |  |  |
Reserves at December 31, 2025 |  | 381 | 5 | 192 |  | 111 | 20 |  | 709
Reserves at December 31, 2025 | 197 | 381 | 522 | 444 | 556 | 824 | 131 |  | 3,055
Developed | 123 | 295 | 344 | 314 | 523 | 274 | 100 |  | 1,973
consolidated subsidiaries | 123 |  | 339 | 202 | 523 | 274 | 80 |  | 1,541
equity-accounted entities |  | 295 | 5 | 112 |  |  | 20 |  | 432
Undeveloped | 74 | 86 | 178 | 130 | 33 | 550 | 31 |  | 1,082
consolidated subsidiaries | 74 |  | 178 | 50 | 33 | 439 | 31 |  | 805
equity-accounted entities |  | 86 |  | 80 |  | 111 |  |  | 277

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(million barrels) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
2024 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Reserves at December 31, 2023 | 211 | 27 | 523 | 334 | 637 | 485 | 213 |  | 2,430
of which: developed | 136 | 24 | 326 | 225 | 576 | 240 | 163 |  | 1,690
undeveloped | 75 | 3 | 197 | 109 | 61 | 245 | 50 |  | 740
Purchase of Minerals in Place |  | 8 |  |  |  |  |  |  | 8
Revisions of Previous Estimates | 12 |  |  | 22 | (6) | 105 | 52 |  | 185
Improved Recovery |  |  |  |  |  |  | 1 |  | 1
Extensions and Discoveries |  |  |  | 15 |  | 22 |  |  | 37
Production | (10) | (6) | (65) | (32) | (40) | (34) | (21) |  | (208)
Sales of Minerals in Place |  | (29) |  | (71) |  |  | (118) |  | (218)
Reserves at December 31, 2024 | 213 |  | 458 | 268 | 591 | 578 | 127 |  | 2,235
Equity-accounted entities |  |  |  |  |  |  |  |  |
Reserves at December 31, 2023 |  | 326 | 6 | 207 |  | 110 | 26 |  | 675
of which: developed |  | 167 | 6 | 107 |  |  | 26 |  | 306
undeveloped |  | 159 |  | 100 |  | 110 |  |  | 369
Purchase of Minerals in Place |  | 90 | 1 | 2 |  |  |  |  | 93
Revisions of Previous Estimates |  | 21 | 2 | 35 |  |  |  |  | 58
Improved Recovery |  |  |  |  |  |  |  |  |
Extensions and Discoveries |  |  |  | 14 |  |  |  |  | 14
Production |  | (44) | (1) | (32) |  |  | (3) |  | (80)
Sales of Minerals in Place |  | (2) |  |  |  |  |  |  | (2)
Reserves at December 31, 2024 |  | 391 | 8 | 226 |  | 110 | 23 |  | 758
Reserves at December 31, 2024 | 213 | 391 | 466 | 494 | 591 | 688 | 150 |  | 2,993
Developed | 129 | 207 | 299 | 290 | 539 | 233 | 104 |  | 1,801
consolidated subsidiaries | 129 |  | 291 | 187 | 539 | 233 | 81 |  | 1,460
equity-accounted entities |  | 207 | 8 | 103 |  |  | 23 |  | 341
Undeveloped | 84 | 184 | 167 | 204 | 52 | 455 | 46 |  | 1,192
consolidated subsidiaries | 84 |  | 167 | 81 | 52 | 345 | 46 |  | 775
equity-accounted entities |  | 184 |  | 123 |  | 110 |  |  | 417

(million barrels) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
2023 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Reserves at December 31, 2022 | 188 | 36 | 531 | 367 | 644 | 433 | 234 | 1 | 2,434
of which: developed | 139 | 32 | 336 | 212 | 585 | 231 | 171 | 1 | 1,707
undeveloped | 49 | 4 | 195 | 155 | 59 | 202 | 63 |  | 727
Purchase of Minerals in Place |  |  | 4 |  |  |  |  |  | 4
Revisions of Previous Estimates | 34 | (2) | 58 | (2) | 35 | 35 | 3 | (1) | 160
Improved Recovery |  |  |  |  |  |  |  |  |
Extensions and Discoveries |  |  |  |  |  | 50 |  |  | 50
Production | (11) | (7) | (70) | (31) | (42) | (31) | (24) |  | (216)
Sales of Minerals in Place |  |  |  |  |  | (2) |  |  | (2)
Reserves at December 31, 2023 | 211 | 27 | 523 | 334 | 637 | 485 | 213 |  | 2,430
Equity-accounted entities |  |  |  |  |  |  |  |  |
Reserves at December 31, 2022 |  | 350 | 8 | 235 |  | 100 | 27 |  | 720
of which: developed |  | 173 | 8 | 135 |  |  | 27 |  | 343
undeveloped |  | 177 |  | 100 |  | 100 |  |  | 377
Purchase of Minerals in Place |  |  |  | 2 |  |  |  |  | 2
Revisions of Previous Estimates |  | 9 | (1) | 2 |  | 10 |  |  | 20
Improved Recovery |  |  |  |  |  |  |  |  |
Extensions and Discoveries |  |  |  |  |  |  |  |  |
Production |  | (32) | (1) | (32) |  |  | (1) |  | (66)
Sales of Minerals in Place |  | (1) |  |  |  |  |  |  | (1)
Reserves at December 31, 2023 |  | 326 | 6 | 207 |  | 110 | 26 |  | 675
Reserves at December 31, 2023 | 211 | 353 | 529 | 541 | 637 | 595 | 239 |  | 3,105
Developed | 136 | 191 | 332 | 332 | 576 | 240 | 189 |  | 1,996
consolidated subsidiaries | 136 | 24 | 326 | 225 | 576 | 240 | 163 |  | 1,690
equity-accounted entities |  | 167 | 6 | 107 |  |  | 26 |  | 306
Undeveloped | 75 | 162 | 197 | 209 | 61 | 355 | 50 |  | 1,109
consolidated subsidiaries | 75 | 3 | 197 | 109 | 61 | 245 | 50 |  | 740
equity-accounted entities |  | 159 |  | 100 |  | 110 |  |  | 369

Main changes in proved reserves of crude oil (including condensates and natural gas liquids) reported in the tables above for the period 2025, 2024 and 2023 are discussed below.

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Consolidated subsidiaries

Purchase of Minerals in Place

In 2023, we had an acquisition of some BP assets in Algeria for 4 mmbbl.

In 2024, 8 mmbbl were obtained for the acquisition of the Neptune company.

In 2025, 7 mmbbl were acquired following an increase in the stake in Bonga field in Nigeria.

Revisions of Previous Estimates

In 2023, revisions of previous estimates were +160 mmbbl. The main positive revisions were in Libya (+53 mmbbl) mainly in Area D and Bouri due to contractual changes and price effect; in Kazakhstan (+35 mmbbl) in Kashagan and Karachaganak fields mainly due to price effect; in Italy (+34 mmbbl) mainly in Val d'Agri and Gela; in Iraq (+24 mmbbl) in Zubair field due to price effect. The main negative changes were Nigeria (-8 mmbbl) mainly on NAOC fields; in the United States of America (-10 mmbbl) mainly on Triton, Oooguruk and Allegheny fields.

In 2024, revisions of previous estimates were +185 mmbbl. The main positive revisions were in the United Arab Emirates (+110 mmbbl) mainly in the Ghasha, Lower Zakum and Hail fields, due to availability of updated data from the new wells; in Algeria (+30 mmbbl) mainly in the Berkine North fields due to better performances. The main negative revisions were in Egypt (-31 mmbbl) mainly concentrated in the Belayim and Meleiha fields and considered the performance trends of the fields.

In 2025, revisions to previous estimates amount to +215 mmbbl. The main positive revisions relate to the renewal of licenses in Egypt in the Sinai area (+76 mmbbl) and Algeria in the Zek area (+40 mmbbl), to activities in the United Arab Emirates, mainly in the Lower Zakum field (+43 mmbbl), and in the Baleine field in Côte d'Ivoire (+29 mmbbl). The main negative revisions relate to fields in the United States (-9 mmbbl).

Improved Recovery

In 2023, there were no increases due to improvements from assisted recovery.

In 2024, there was 1 mmbbl due to improvements from assisted recovery on the St. Malo field in the United States of America.

In 2025, improved recovery amounted to 33 mmbbl for activities in Zubair field in Iraq and Baleine field in Côte d'Ivoire.

Extensions and Discoveries

In 2023, new discoveries and extensions amounted to 50 mmbbl, mainly related to the United Arab Emirates following the final investment decision in the Hail and Ghasha project.

In 2024, new discoveries and extensions amounted to 37 mmbbl, mainly due to the final investment decision in the Umm Shaif projects in the United Arab Emirates (22 mmbbl) and Bonga North in Nigeria (15 mmbbl).

In 2025, new discoveries and extensions amount to 96 mmbbl, due to the final investment decision in the Kutei Basin in Indonesia.

Sales of Minerals in Place

In 2023, the divestment of 2 mmbbl mainly concerned the reduction of the share in the Ghasha concession in the United Arab Emirates.

In 2024, 218 mmbbl of divestments were recorded. Of these, 71 mmbbl were related to the sale of NAOC assets in Nigeria, 118 mmbbl to the sale of assets in Alaska, and the remainder were related to the sale of some minor fields in Congo and the results of the business combination with Ithaca Energy.

In 2025, sales of 28 mmbbl were recorded, linked to the sale of the 30% stake in the Baleine field in Côte d'Ivoire and assets in Congo.

Equity-accounted entities

Purchase of Minerals in Place

In 2023, the 2 mmbbl of acquisition of a share in Block 3/05a in Azule.

In 2024 acquisitions amounted to 93 mmbbl and were mainly due to the business combination with Ithaca Energy and Vår Energi's acquisition of Neptune.

In 2025, acquisitions amounted to 3 mmbbl, mainly in Vår Energi in Norway and Ithaca Energy in the United Kingdom.

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Revisions of Previous Estimates

In 2023, positive revisions of +20 mmbbl were mainly due to Qatar (+10 mmbbl) on the NFE field, Vår Energi in Norway (+9 mmbbl).

In 2024, revisions were positive by 58 mmbbl, affecting mainly Azule Energy and Vår Energi.

In 2025, revisions were positive for 32 mmbbl, mainly concerning Azule Energy and Vår Energi.

Extensions and Discoveries

No extensions or new discoveries were recorded in 2023.

In 2024, extensions and new discoveries of 14 mmbbl were mainly the result of the inclusion of reserves from the Coral North project.

In 2025, extensions and new discoveries of 11 mmbbl are mainly the result of the booking of new reserves in Vår Energi in Norway.

Sales of Minerals in Place

In 2023, sales amounted to -1 mmbbl for the divestment of the Brage field in Vår Energi in Norway.

In 2024, divestments of 2 mmbbl involved assets of Vår Energi.

No sales recorded in 2025.

Proved reserves of natural gas

(billion cubic feet) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
2025 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Reserves at December 31, 2024 | 817 | 54 | 5,338 | 1,931 | 1,489 | 1,583 | 94 | 190 | 11,496
of which: 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
Purchase of Minerals in Place |  |  |  | 1 |  |  |  |  | 1
Revisions of Previous Estimates | (90) | 24 | 382 | 134 | (1) | 146 | 3 | (119) | 479
Improved Recovery |  |  |  |  |  |  |  |  |
Extensions and Discoveries |  | 27 |  |  |  | 2,513 |  |  | 2,540
Production (a) | (76) | (24) | (668) | (179) | (89) | (233) | (17) | (9) | (1,295)
Sales of Minerals in Place |  |  |  | (223) |  |  |  |  | (223)
Reserves at December 31, 2025 | 651 | 81 | 5,052 | 1,664 | 1,399 | 4,009 | 80 | 62 | 12,998
Equity-accounted entities |  |  |  |  |  |  |  |  |
Reserves at December 31, 2024 |  | 939 | 222 | 3,103 |  | 1,411 | 1,159 |  | 6,834
of which: developed |  | 545 | 222 | 1,054 |  |  | 1,159 |  | 2,980
undeveloped |  | 394 |  | 2,049 |  | 1,411 |  |  | 3,854
Purchase of Minerals in Place |  | 91 | 41 |  |  |  |  |  | 132
Revisions of Previous Estimates |  | 149 | 14 | 70 |  | 7 | 10 |  | 250
Improved Recovery |  |  |  |  |  |  |  |  |
Extensions and Discoveries |  | 218 |  | 2 |  |  |  |  | 220
Production (b) |  | (168) | (28) | (98) |  |  | (106) |  | (400)
Sales of Minerals in Place |  |  |  |  |  |  |  |  |
Reserves at December 31, 2025 |  | 1,229 | 249 | 3,077 |  | 1,418 | 1,063 |  | 7,036
Reserves at December 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
consolidated subsidiaries | 524 | 45 | 2,562 | 1,099 | 1,396 | 920 | 56 | 37 | 6,639
equity-accounted entities |  | 692 | 249 | 1,222 |  |  | 1,063 |  | 3,226
Undeveloped | 127 | 573 | 2,490 | 2,420 | 3 | 4,507 | 24 | 25 | 10,169
consolidated subsidiaries | 127 | 36 | 2,490 | 565 | 3 | 3,089 | 24 | 25 | 6,359
equity-accounted entities |  | 537 |  | 1,855 |  | 1,418 |  |  | 3,810

(a) Includes production volumes consumed in operations equal to 217 Bcf.

(b) Includes production volumes consumed in operations equal to 36 Bcf.

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(billion cubic feet) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
2024 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Reserves at December 31, 2023 | 859 | 174 | 5,935 | 2,479 | 1,546 | 1,303 | 131 | 192 | 12,619
of which: 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
Purchase of Minerals in Place |  | 184 | 9 |  |  | 226 |  |  | 419
Revisions of Previous Estimates | 30 | 2 | 172 | 194 | 35 | 267 | 23 | 3 | 726
Improved Recovery |  |  |  |  |  |  |  |  |
Extensions and Discoveries |  |  |  | 2 |  | 2 |  |  | 4
Production (a) | (72) | (71) | (778) | (164) | (92) | (215) | (18) | (5) | (1,415)
Sales of Minerals in Place |  | (235) |  | (580) |  |  | (42) |  | (857)
Reserves at December 31, 2024 | 817 | 54 | 5,338 | 1,931 | 1,489 | 1,583 | 94 | 190 | 11,496
Equity-accounted entities |  |  |  |  |  |  |  |  |
Reserves at December 31, 2023 |  | 515 | 14 | 1,501 |  | 1,406 | 1,260 |  | 4,696
of which: developed |  | 359 | 14 | 1,036 |  |  | 1,260 |  | 2,669
undeveloped |  | 156 |  | 465 |  | 1,406 |  |  | 2,027
Purchase of Minerals in Place |  | 544 | 174 |  |  |  |  |  | 718
Revisions of Previous Estimates |  | 28 | 56 | 38 |  | 5 | 3 |  | 130
Improved Recovery |  |  |  |  |  |  |  |  |
Extensions and Discoveries |  |  |  | 1,651 |  |  |  |  | 1,651
Production (b) |  | (139) | (22) | (87) |  |  | (104) |  | (352)
Sales of Minerals in Place |  | (9) |  |  |  |  |  |  | (9)
Reserves at December 31, 2024 |  | 939 | 222 | 3,103 |  | 1,411 | 1,159 |  | 6,834
Reserves at December 31, 2024 | 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
consolidated subsidiaries | 693 | 52 | 2,692 | 1,206 | 1,486 | 799 | 56 | 23 | 7,007
equity-accounted entities |  | 545 | 222 | 1,054 |  |  | 1,159 |  | 2,980
Undeveloped | 124 | 396 | 2,646 | 2,774 | 3 | 2,195 | 38 | 167 | 8,343
consolidated subsidiaries | 124 | 2 | 2,646 | 725 | 3 | 784 | 38 | 167 | 4,489
equity-accounted entities |  | 394 |  | 2,049 |  | 1,411 |  |  | 3,854

(a) Includes production volumes consumed in operations equal to 223 Bcf.

(b) Includes production volumes consumed in operations equal to 33 Bcf.

(billion cubic feet) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
2023 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Reserves at December 31, 2022 | 869 | 223 | 6,204 | 2,341 | 1,560 | 1,281 | 264 | 408 | 13,150
of which: developed | 695 | 214 | 3,402 | 1,306 | 1,560 | 796 | 195 | 223 | 8,391
undeveloped | 174 | 9 | 2,802 | 1,035 |  | 485 | 69 | 185 | 4,759
Purchase of Minerals in Place |  |  | 214 |  |  |  |  |  | 214
Revisions of Previous Estimates | 67 | (10) | 326 | 294 | 79 | 112 | 5 | (202) | 671
Improved Recovery |  |  |  |  |  |  |  |  |
Extensions and Discoveries |  |  | 4 | 5 |  | 275 |  |  | 284
Production (a) | (77) | (39) | (813) | (161) | (93) | (187) | (25) | (14) | (1,409)
Sales of Minerals in Place |  |  |  |  |  | (178) | (113) |  | (291)
Reserves at December 31, 2023 | 859 | 174 | 5,935 | 2,479 | 1,546 | 1,303 | 131 | 192 | 12,619
Equity-accounted entities |  |  |  |  |  |  |  |  |
Reserves at December 31, 2022 |  | 646 | 9 | 1,562 |  | 1,490 | 1,355 |  | 5,062
of which: developed |  | 444 | 9 | 1,070 |  |  | 1,355 |  | 2,878
undeveloped |  | 202 |  | 492 |  | 1,490 |  |  | 2,184
Purchase of Minerals in Place |  |  |  |  |  |  |  |  |
Revisions of Previous Estimates |  | (32) | 6 | 22 |  | (84) | 7 |  | (81)
Improved Recovery |  |  |  |  |  |  |  |  |
Extensions and Discoveries |  |  |  |  |  |  |  |  |
Production (b) |  | (97) | (1) | (83) |  |  | (102) |  | (283)
Sales of Minerals in Place |  | (2) |  |  |  |  |  |  | (2)
Reserves at December 31, 2023 |  | 515 | 14 | 1,501 |  | 1,406 | 1,260 |  | 4,696
Reserves at December 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
consolidated subsidiaries | 653 | 167 | 3,181 | 1,350 | 1,546 | 725 | 107 | 58 | 7,787
equity-accounted entities |  | 359 | 14 | 1,036 |  |  | 1,260 |  | 2,669
Undeveloped | 206 | 163 | 2,754 | 1,594 |  | 1,984 | 24 | 134 | 6,859
consolidated subsidiaries | 206 | 7 | 2,754 | 1,129 |  | 578 | 24 | 134 | 4,832
equity-accounted entities |  | 156 |  | 465 |  | 1,406 |  |  | 2,027

(a) Includes production volumes consumed in operations equal to 206 Bcf.

(b) Includes production volumes consumed in operations equal to 33 Bcf.

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Main changes in proved reserves of natural gas reported in the tables above for 2025, 2024 and 2023 are discussed below.

Consolidated subsidiaries

Purchase of Minerals in Place

In 2023, there was 214 BCF meters due to the acquisition of some BP assets in Algeria.

In 2024, 419 BCF were reported for the acquisition of the Neptune company in Indonesia, Netherlands and the United Kingdom.

In 2025, 1 BCF was recorded for the acquisition of a stake in Bonga asset in Nigeria.

Revisions of Previous Estimates

In 2023, total revisions were +671 BCF. The main positive revisions were recorded in: Libya (+651 BCF) in Area D and Bouri due to contractual changes and price effect; in Congo (+237 BCF) mainly in Mboundi Gas and Nene; in Algeria (+178 BCF) mainly in Block 208-404. The main negative revisions were in Australia (-202 BCF) in the Blacktip field and in Egypt (-506 BCF) mainly for the reconfiguration of the Zohr project phase 2, which entailed a review of the compression design and a downward revision of the relevant reserves.

In 2024, total revisions were +726 BCF. The main revisions were in the United Arab Emirates (+256 BCF) mainly in the Hail and Ghasha fields due to availability of updated data from the new wells; in Algeria (+101 BCF) mainly in the In Amenas, In Salah, HBNS and Brn Silurian fields due to better performance; in Ivory Coast (+87 BCF) in the Baleine field due to better performance; and in Ghana (+76 BCF) in the Sankofa field as a result of the implementation of compression activities.

In 2025, total revisions amounted to +479 BCF. The main positive revisions were recorded in Algeria (+146 BCF) for the renewal of the Zek concessions, in Libya (+145 BCF) mainly in Area D, offset by negative revisions in Blacktip in Australia (-119 BCF) and in Italy (-90 BCF), mainly in the offshore Adriatic and the offshore Sicily.

Improved Recovery

In 2023, 2024 and 2025 there were no improvements from assisted recovery.

Extensions and Discoveries

In 2023, new discoveries and extensions were 284 BCF in United Arab Emirates (217 BCF) as a result of the final investment decision in the Hail and Ghasha project and Indonesia (59 BCF) for the final investment decision in Merakes East.

In 2024, new discoveries and extensions totalled 4 BCF, following the final investment decision in the Umm Shaif projects in the United Arab Emirates (2 BCF) and Bonga North in Nigeria (2 BCF).

In 2025, new discoveries and extensions amounted to 2,540 BCF, mainly due to the progress and execution of the activities in Kutei Basin in Indonesia (2,445 BCF) and in Sarb field in the United Arab Emirates (68 BCF).

Sales of Minerals in Place

In 2023, divestments of 291 BCF were mainly due in the United States of America (113 BCF) for the divestment of Alliance assets and in the United Arab Emirates (177 BCF) for the reduction of the share in the Ghasha concession.

In 2024, divestments of 857 BCF were related to the sale of NAOC assets in Nigeria, the sale of assets in Alaska and some minor fields in Congo, and the results of the business combination with Ithaca Energy.

In 2025, sales of 223 BCF are linked to the sale of the 30% stake in Baleine in Côte d'Ivoire and assets in Congo.

Equity-accounted entities

Purchase of Minerals in Place

No purchase was made in 2023.

In 2024, acquisitions totalled 718 BCF due to Vår Energi's acquisition of Neptune and the business combination with Ithaca Energy.

In 2025, acquisitions amounted to 132 BCF relating to Vår Energi in Norway, a stake in Touat in Algeria, and assets in Ithaca Energy in the United Kingdom.

Revisions of Previous Estimates

In 2023, revisions of previous estimates were -81 BCF mainly due to a positive revision in Mozambique (+77 BCF) in Coral South, Azule in Angola (-55 BCF) and Qatar (-84 BCF) on the NFE field.

In 2024, revisions of previous estimates were +130 BCF, located mainly in Algeria (+57 BCF) in the Touat field, in Mozambique (+46 BCF) in the Coral South field and in Vår Energi.

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In 2025, revisions to previous estimates amount to (+250 BCF), mainly located in Vår Energi in Norway (+125 BCF), in Mozambique (69 BCF), and minor revisions in the United Kingdom and in Algeria.

Extensions and Discoveries

In 2023, there were no extensions or new relevant discoveries.

In 2024, extensions and new discoveries of 1,651 BCF were mainly the result of the Coral North project's reserve booking offshore Mozambique, based on the Company final investment decision, status of project maturity and commitment of all the JV partners, as well as the management’s reasonable expectation that remaining formal government approvals will be obtained shortly.

In 2025, extensions and new discoveries of 220 BCF are mainly the result of the registration of new reserves in Vår Energi in Norway (208 BCF) and minor projects in Ithaca Energy in the United Kingdom.

Sales of Minerals in Place

In 2023, divestments were 2 BCF in the Brage field in Vår Energi in Norway.

In 2024, disposals of 9 BCF were mainly related to portfolio activities of Vår Energi and Azule Energy.

No sales were recorded in 2025.

Standardized measure of discounted future net cash flows

Estimated future cash inflows represent the revenues that would be received from production and were determined by applying the year-end average prices during the years ended. Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved reserves at the end of the year. Neither the effects of price and cost escalations nor expected future changes in technology and operating practices have been considered. The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a yearly 10% discount factor. Future production costs include the estimated expenditure related to the production of proved reserves plus any production taxes without consideration of future inflation. Future development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantlement and abandonment of wells and facilities, under the assumption that year-end costs continue without considering future inflation. Future income taxes were calculated in accordance with the tax laws of the countries in which Eni operates. The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FASB Extractive Activities - Oil and Gas (Topic 932). The standardized measure does not purport to reflect realizable values or fair market value of Eni’s proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity.

The standardized measure of discounted future net cash flows by geographical area consists of the following:

(€ million) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
December 31, 2025 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Future cash inflows | 16,507 | 703 | 54,711 | 23,122 | 29,040 | 60,156 | 6,334 | 240 | 190,813
Future production costs | (7,531) | (363) | (12,974) | (8,627) | (5,351) | (13,520) | (3,098) | (48) | (51,512)
Future development and abandonment costs | (3,341) | (501) | (9,319) | (3,234) | (1,224) | (14,961) | (1,246) | (156) | (33,982)
Future net inflow before income tax | 5,635 | (161) | 32,418 | 11,261 | 22,465 | 31,675 | 1,990 | 36 | 105,319
Future income tax | (1,389) | (27) | (15,537) | (2,250) | (6,222) | (17,768) | (98) | (2) | (43,293)
Future net cash flows | 4,246 | (188) | 16,881 | 9,011 | 16,243 | 13,907 | 1,892 | 34 | 62,026
10% discount factor | (1,963) | 77 | (8,428) | (3,244) | (7,773) | (9,320) | (402) | (13) | (31,066)
Standardized measure of discounted future net cash flows | 2,283 | (111) | 8,453 | 5,767 | 8,470 | 4,587 | 1,490 | 21 | 30,960
Equity-accounted entities |  |  |  |  |  |  |  |  |
Future cash inflows |  | 34,001 | 1,528 | 21,853 |  | 15,807 | 5,912 |  | 79,101
Future production costs |  | (9,475) | (445) | (5,475) |  | (5,155) | (1,547) |  | (22,097)
Future development and abandonment costs |  | (8,515) | (75) | (2,401) |  | (145) | (193) |  | (11,329)
Future net inflow before income tax |  | 16,011 | 1,008 | 13,977 |  | 10,507 | 4,172 |  | 45,675
Future income tax |  | (11,851) | (229) | (3,186) |  | (7,515) | (1,742) |  | (24,523)
Future net cash flows |  | 4,160 | 779 | 10,791 |  | 2,992 | 2,430 |  | 21,152
10% discount factor |  | (845) | (231) | (5,489) |  | (1,792) | (815) |  | (9,172)
Standardized measure of discounted future net cash flows |  | 3,315 | 548 | 5,302 |  | 1,200 | 1,615 |  | 11,980
Total consolidated subsidiaries and equity-accounted entities | 2,283 | 3,204 | 9,001 | 11,069 | 8,470 | 5,787 | 3,105 | 21 | 42,940

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(€ million) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
December 31, 2024 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Future cash inflows | 20,844 | 570 | 66,540 | 30,478 | 40,322 | 49,205 | 9,164 | 742 | 217,865
Future production costs | (8,273) | (297) | (14,034) | (10,912) | (6,786) | (13,462) | (3,994) | (132) | (57,890)
Future development and abandonment costs | (3,318) | (417) | (9,317) | (4,942) | (1,658) | (7,547) | (2,104) | (280) | (29,583)
Future net inflow before income tax | 9,253 | (144) | 43,189 | 14,624 | 31,878 | 28,196 | 3,066 | 330 | 130,392
Future income tax | (2,088) | (49) | (21,879) | (3,541) | (8,505) | (18,186) | (387) | (6) | (54,641)
Future net cash flows | 7,165 | (193) | 21,310 | 11,083 | 23,373 | 10,010 | 2,679 | 324 | 75,751
10% discount factor | (2,995) | 60 | (10,150) | (4,102) | (11,301) | (5,826) | (656) | (96) | (35,066)
Standardized measure of discounted future net cash flows | 4,170 | (133) | 11,160 | 6,981 | 12,072 | 4,184 | 2,023 | 228 | 40,685
Equity-accounted entities |  |  |  |  |  |  |  |  |
Future cash inflows |  | 39,301 | 1,846 | 31,708 |  | 18,602 | 7,397 |  | 98,854
Future production costs |  | (10,169) | (612) | (7,702) |  | (5,969) | (1,882) |  | (26,334)
Future development and abandonment costs |  | (7,279) | (111) | (4,289) |  | (278) | (191) |  | (12,148)
Future net inflow before income tax |  | 21,853 | 1,123 | 19,717 |  | 12,355 | 5,324 |  | 60,372
Future income tax |  | (16,126) | (205) | (5,549) |  | (9,018) | (2,231) |  | (33,129)
Future net cash flows |  | 5,727 | 918 | 14,168 |  | 3,337 | 3,093 |  | 27,243
10% discount factor |  | (1,077) | (285) | (7,742) |  | (2,119) | (1,128) |  | (12,351)
Standardized measure of discounted future net cash flows |  | 4,650 | 633 | 6,426 |  | 1,218 | 1,965 |  | 14,892
Total consolidated subsidiaries and equity-accounted entities | 4,170 | 4,517 | 11,793 | 13,407 | 12,072 | 5,402 | 3,988 | 228 | 55,577

(€ million) | Italy | Rest of Europe | North Africa | Sub - Saharan Africa | Kazakhstan | Rest of Asia | America | Australia and Oceania | Total
December 31, 2023 |  |  |  |  |  |  |  |  |
Consolidated subsidiaries |  |  |  |  |  |  |  |  |
Future cash inflows | 22,724 | 3,926 | 72,835 | 35,147 | 40,081 | 40,622 | 14,951 | 707 | 230,993
Future production costs | (8,848) | (1,227) | (15,439) | (13,512) | (6,475) | (11,042) | (5,852) | (164) | (62,559)
Future development and abandonment costs | (4,270) | (824) | (9,383) | (7,757) | (1,814) | (7,437) | (1,954) | (355) | (33,794)
Future net inflow before income tax | 9,606 | 1,875 | 48,013 | 13,878 | 31,792 | 22,143 | 7,145 | 188 | 134,640
Future income tax | (2,233) | (1,274) | (24,069) | (4,729) | (8,186) | (16,348) | (3,161) | (8) | (60,008)
Future net cash flows | 7,373 | 601 | 23,944 | 9,149 | 23,606 | 5,795 | 3,984 | 180 | 74,632
10% discount factor | (3,325) | (39) | (10,467) | (4,223) | (11,668) | (3,081) | (1,462) | (58) | (34,323)
Standardized measure of discounted future net cash flows | 4,048 | 562 | 13,477 | 4,926 | 11,938 | 2,714 | 2,522 | 122 | 40,309
Equity-accounted entities |  |  |  |  |  |  |  |  |
Future cash inflows |  | 29,387 | 168 | 22,954 |  | 19,108 | 7,519 |  | 79,136
Future production costs |  | (7,128) | (122) | (6,202) |  | (5,880) | (1,925) |  | (21,257)
Future development and abandonment costs |  | (5,221) | (54) | (2,972) |  | (410) | (179) |  | (8,836)
Future net inflow before income tax |  | 17,038 | (8) | 13,780 |  | 12,818 | 5,415 |  | 49,043
Future income tax |  | (12,548) | (1) | (3,254) |  | (9,702) | (2,263) |  | (27,768)
Future net cash flows |  | 4,490 | (9) | 10,526 |  | 3,116 | 3,152 |  | 21,275
10% discount factor |  | (1,114) | 27 | (4,508) |  | (2,158) | (1,237) |  | (8,990)
Standardized measure of discounted future net cash flows |  | 3,376 | 18 | 6,018 |  | 958 | 1,915 |  | 12,285
Total consolidated subsidiaries and equity-accounted entities | 4,048 | 3,938 | 13,495 | 10,944 | 11,938 | 3,672 | 4,437 | 122 | 52,594

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Table of Contents

Changes in standardized measure of discounted future net cash flows

Changes in standardized measure of discounted future net cash flows for the years ended December 31, 2025, 2024 and 2023, were as follows:

(€ million) | Consolidated subsidiaries | Equity-accounted entities | Total
2025 |  |  |
Standardized measure of discounted future net cash flows at December 31, 2024 | 40,685 | 14,892 | 55,577
Increase (Decrease): |  |  |
- sales, net of production costs | (14,835) | (6,488) | (21,323)
- net changes in sales and transfer prices, net of production costs | (9,662) | (4,685) | (14,347)
- extensions, discoveries and improved recovery, net of future production and development costs | 5,243 | 1,544 | 6,787
- changes in estimated future development and abandonment costs | (4,126) | (2,528) | (6,654)
- development costs incurred during the period that reduced future development costs | 5,835 | 2,635 | 8,470
- revisions of quantity estimates | 4,012 | 2,341 | 6,353
- accretion of discount | 6,307 | 2,076 | 8,383
- net change in income taxes | 2,638 | 2,750 | 5,388
- purchase of reserves in-place | 33 | 820 | 853
- sale of reserves in-place | (1,075) |  | (1,075)
- changes in production rates (timing) and other | (4,095) | (1,377) | (5,472)
Net increase (decrease) | (9,725) | (2,912) | (12,637)
Standardized measure of discounted future net cash flows at December 31, 2025 | 30,960 | 11,980 | 42,940

(€ million) | Consolidated subsidiaries | Equity-accounted entities | Total
2024 |  |  |
Standardized measure of discounted future net cash flows at December 31, 2023 | 40,309 | 12,285 | 52,594
Increase (Decrease): |  |  |
- sales, net of production costs | (17,581) | (6,150) | (23,731)
- net changes in sales and transfer prices, net of production costs | (5,380) | 89 | (5,291)
- extensions, discoveries and improved recovery, net of future production and development costs | 401 | 1,851 | 2,252
- changes in estimated future development and abandonment costs | (2,959) | (3,860) | (6,819)
- development costs incurred during the period that reduced future development costs | 6,649 | 4,824 | 11,473
- revisions of quantity estimates | 4,664 | (2,467) | 2,197
- accretion of discount | 7,405 | 1,984 | 9,389
- net change in income taxes | 6,578 | (1,654) | 4,924
- purchase of reserves in-place | 1,085 | 5,167 | 6,252
- sale of reserves in-place | (2,947) | (1) | (2,948)
- changes in production rates (timing) and other | 2,461 | 2,824 | 5,285
Net increase (decrease) | 376 | 2,607 | 2,983
Standardized measure of discounted future net cash flows at December 31, 2024 | 40,685 | 14,892 | 55,577

(€ million) | Consolidated subsidiaries | Equity-accounted entities | Total
2023 |  |  |
Standardized measure of discounted future net cash flows at December 31, 2022 | 61,256 | 20,701 | 81,957
Increase (Decrease): |  |  |
- sales, net of production costs | (19,397) | (5,426) | (24,823)
- net changes in sales and transfer prices, net of production costs | (33,769) | (19,785) | (53,554)
- extensions, discoveries and improved recovery, net of future production and development costs | 1,659 |  | 1,659
- changes in estimated future development and abandonment costs | (4,684) | (1,353) | (6,037)
- development costs incurred during the period that reduced future development costs | 6,691 | 2,517 | 9,208
- revisions of quantity estimates | 6,531 | 155 | 6,686
- accretion of discount | 10,627 | 3,033 | 13,660
- net change in income taxes | 12,675 | 14,753 | 27,428
- purchase of reserves in-place | 977 | 44 | 1,021
- sale of reserves in-place | (845) | (60) | (905)
- changes in production rates (timing) and other | (1,412) | (2,294) | (3,706)
Net increase (decrease) | (20,947) | (8,416) | (29,363)
Standardized measure of discounted future net cash flows at December 31, 2023 | 40,309 | 12,285 | 52,594

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